VCE 2/10/22 Board Meeting Agenda Page 1 of 3
Regular Meeting of the Valley Clean Energy Alliance
Board of Directors
Thursday, February 10, 2022 at 5 p.m.
Via Video/Teleconference
Pursuant to Assembly Bill 361 (AB 361), legislative bodies may meet remotely without listing the location of each remote attendee, posting agendas at each remote location, or allowing the public to access each location, with the adoption of certain findings. The Board of Directors found that the local health official recommended measures to promote social distancing and authorized the continuation of remote meetings for the foreseeable future. Any interested member of the public who wishes to listen in should join this meeting via teleconferencing as set forth below.
Please note that the numerical order of items is for convenience of reference. Items may be taken out of order on the request of any Board member with the concurrence of the Board. Staff recommendations are advisory to the Board. The Board may take any action it deems appropriate on any item on the agenda even if it varies from the staff recommendation.
Members of the public who wish to listen to the Board of Director’s meeting may do so with the video/teleconferencing call-in number and meeting ID code. Video/teleconference information below to join meeting:
Join meeting via Zoom:
a. From a PC, Mac, iPad, iPhone, or Android device with high-speed internet. (If your device does not have audio, please also join by phone.) https://us02web.zoom.us/j/89556391876
Meeting ID: 895 5639 1876
b. By phone
One tap mobile:
+1-669-900-9128,, 89556391876# US
+1-253-215-8782,, 89556391876# US
Dial:
+1-669-900-9128 US
+1-253-215-8782 US
Meeting ID: 895 5639 1876
Public comments may be submitted electronically or during the meeting. Instructions on how to submit your public comments can be found in the PUBLIC PARTICIPATION note at the end of this agenda.
Board Members: Jesse Loren, (Chair/City of Winters), Tom Stallard (Vice Chair/City Woodland), Don Saylor (Yolo County), Dan Carson (City of Davis), Wade Cowan (City of Winters), Mayra Vega (City of Woodland), Gary Sandy (Yolo County), and Lucas Frerichs (City of Davis) 1 VCE 2/10/22 Board Meeting Agenda Page 2 of 3
5:00 p.m. Call to Order
1. Welcome
2. Public Comment: This item is reserved for persons wishing to address the Board on any VCE-related matters that are not otherwise on this meeting agenda or are listed on the Consent portion of the agenda. Public comments on matters listed on the agenda shall be heard at the time the matter is called. As with all public comment, members of the public who wish to address the Board are customarily limited to two minutes per speaker, electronically submitted comments should be limited to approximately 300 words. Comments that are longer than 300 words will only be read for two minutes. All electronically submitted comments, whether read in their entirety or not, will be posted to the VCE website within 24 hours of the conclusion of the meeting. See below under PUBLIC PARTICIPATION on how to provide your public comment.
CONSENT AGENDA
3. Renew authorization of remote public meetings as authorized by Assembly Bill 361.
4. Approve January 27, 2022 Board special meeting Minutes.
5. Receive 2022 Long Range Calendar.
6. Receive Financial Update – December 31, 2021 (unaudited) financial statements.
7. Receive February 4, 2022 Regulatory update provided by Keyes & Fox.
8. Receive February 2, 2022 Customer Enrollment update.
9. Receive Community Advisory Committee January 20, 2022 meeting summary.
10. SACOG Grant – Electrify Yolo Project update.
11. Time of Use (TOU) Rate Transition update.
12. Update on customer program development.
REGULAR AGENDA
13. Receive Carbon Neutral by 2030 Draft Report. (Information/Discussion)
14. Approve participation in and authorize the Interim General Manager to execute documents associated with VCE participating in the CC Power long duration storage project: Tumbleweed.
15. Approve 2022 Customer rates.
16. Approve 2022 Operating Budget.
17. Approve Line of Credit Agreement with the County of Yolo.
18. VCE Three-Year Strategic Plan Annual update. (Informational)
19. Board Member and Staff Announcements: Action items and reports from members of the Board, including announcements, AB1234 reporting of meetings attended by Board Members of VCEA expense, questions to be referred to staff, future agenda items, and reports on meetings and information which would be of interest to the Board or the public.
20. Adjournment: The next regular meeting is scheduled for March 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.
21. Public Conference with Labor Negotiators Pursuant to Government Code Section 54957.6 Agency-designated Negotiators: Don Saylor (VCE Board), Jesse Loren (VCE Board), Eric May (VCE Legal Counsel)
Unrepresented Employees: Executive Officer
2 VCE 2/10/22 Board Meeting Agenda Page 3 of 3
PUBLIC PARTICIPATION INSTRUCTIONS FOR VALLEY CLEAN ENERGY BOARD OF DIRECTORS SPECIAL MEETING ON THURSDAY, FEBRUARY 10, 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 be read during Item 3, Public Comment. Written public comment on individual agenda items should include the item number in the “Subject” line for the e-mail and the Clerk will read the comment during the item. Items read cannot exceed 300 words or approximately two (2) minutes in length. All written comments received will be posted to the VCE website. E-mail comments received after the item is called will be distributed to the Board and posted on the VCE website so long as they are received by the end of the meeting.
Public records that relate to any item on the open session agenda for a regular or special Board meeting are available for public review on the VCE website. Records that are distributed to the Board by VCE staff less than 72 hours prior to the meeting will be posted to the VCE website at the same time they are distributed to all members, or a majority of the members of the Board. Questions regarding VCE public records related to the meeting should be directed to Board Clerk Alisa Lembke at (530) 446-2750 or [email protected]. The Valley Clean Energy website is located at: https://valleycleanenergy.org/board-meetings/.
Accommodations for Persons with disabilities. Individuals who need special assistance or a disability-related modification or accommodation to participate in this meeting, or who have a disability and wish to request an alternative format for the meeting materials, should contact Alisa Lembke, VCE Board Clerk/Administrative Analyst, as soon as possible and preferably at least two (2) working days before the meeting at (530) 446-2754 or [email protected]. 3 VALLEY CLEAN ENERGY ALLIANCE
Staff Report - Item 3
____________________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Interim General Manager
Alisa Lembke, Board Clerk/Administrative Analyst
SUBJECT: Renew Authorization to continue Remote Public Meetings as authorized by Assembly Bill 361
DATE: February 10, 2022
Recommendation
VCE Board renew authorization for remote (video/teleconference) meetings, including any standing or future committee(s) meetings and Community Advisory Committee meetings, by finding:
1. Pursuant to Assembly Bill 361 (AB 361), that, (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.
4 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.
On January 27, 2022, the Board made findings pursuant to AB 361 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 renew authorization for remote (video/teleconference) meetings, including any standing or future committee(s) meetings and Community Advisory Committee 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 5 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. 6
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. 7 1
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 4
TO: Board of Directors
FROM: Alisa Lembke, Board Clerk / Administrative Analyst SUBJECT: Approval of Minutes from special January 27, 2022 meeting DATE: February 10, 2022
RECOMMENDATION
Receive, review and approve the attached January 27, 2022 special meeting Minutes.
8 VCEA Minutes January 27, 2022 Board Special Meeting via Webinar Page 1 of 4
MINUTES OF THE VALLEY CLEAN ENERGY ALLIANCE
BOARD OF DIRECTORS SPECIAL MEETING
THURSDAY, JANUARY 27, 2022
The Board of Directors of the Valley Clean Energy Alliance duly noticed their special meeting scheduled for Thursday, January 27, 2022 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 5:02 p.m.
Board Members Present: Dan Carson, Jesse Loren, Don Saylor, Gary Sandy, Wade Cowan, Lucas Frerichs
Members Absent: Mayra Vega, Tom Stallard
Welcome Chair Carson welcomed everyone.
Election of
Officers for 2022
Director Lucas Frerichs nominated Jesse Loren to serve as the 2022 Chair of the VCE Board, seconded by Director Wade Cowan. Motion passed with Directors Mayra Vega and Tom Stallard absent.
Motion made by Director Don Saylor nominating Mayra Vega as 2022 Vice Chair, seconded by Director Lucas Frerichs. After a brief discussion, motion was withdrawn.
Chair Jesse Loren nominated Tom Stallard to serve as the 2022 Vice Chair of the VCE Board, seconded by Director Dan Carson. Motion passed with Directors Mayra Vega and Tom Stallard absent.
Chair Jesse Loren read an honorary proclamation recognizing Dan Carson for his service as Chair.
Public Comment
– General and
Consent
Chair Loren opened the floor for public comment for items not listed on the agenda and items listed on the Consent Agenda.
Gerry Braun provided a verbal public comment on the California Public Utilities Commission (CPUC) considering proposed changes on the utility rates that apply to roof top solar equipment owners. Mr. Braun encourages VCE to do the same as the City Davis Council did on offering thoughtful and measurable input on the proposed changes and he asks that VCE do more. He encourages VCE to have active engagement with the retail solar industry and VCE’s customers.
9 VCEA Minutes January 27, 2022 Board Special Meeting via Webinar Page 2 of 4 Board Clerk informed those present that there were no written comments.
Approval of
Consent Agenda
(Resolutions
2022-001 through
2022-004)
Motion made by Director Lucas Frerichs to approve the consent agenda, seconded by Director Wade Cowan. Motion passed with Directors Vega and Stallard absent. The following items were approved, ratified, and/or received:
3. continue remote public meetings as authorized by Assembly Bill 361;
4. November 10, 2021 Board special meeting Minutes;
5. 2022 Long Range Calendar;
6. A) Financial Updates – October 31, 2021 and B) November 30, 2021 financials (unaudited) financial statements;
7. Legislative update;
8. January 19, 2022 Regulatory update provided by Keyes & Fox;
9. January 19, 2022 Customer Enrollment update;
10. Community Advisory Committee November 18, 2021 and December 16, 2021 meeting summaries;
11. Community Advisory Committee 2021 Year End Report;
12. Amendment 26 to the Sacramento Municipal Utilities District Task Order 2 to implement VCE 2022 rate configuration (Resolution 2022- 001);
13. copy of signed Amendment 3 to Jim Parks Consulting agreement extending term through June 30, 2022;
14. Near-term Procurement Directives and Delegations for 2022 Power Procurement Activities (Resolution 2022-002);
15. extension of credit agreement to February 28, 2022 with River City Bank (Resolution 2022-003);
16. 2022 Legislative Platform;
17. support of Senate Bill 833 (Dodd) Community Energy Resilience Act of 2022;
18. temporary use of up to $200,000 of the program reserve fund to initiate the Ag FIT (Flexible Irrigation Technology) dynamic pricing pilot; and,
19. GHG Free Attributes for 2022 accepting large hydro and rejecting nuclear (Resolution 2022-004).
Item 21: Receive
Marketing and
Outreach 2021
Interim General Manager Mitch Sears introduced this item. VCE Staff Rebecca Boyles provided a slide presentation summarizing marketing and outreach efforts in 2021.
10 VCEA Minutes January 27, 2022 Board Special Meeting via Webinar Page 3 of 4 year-in review
presentation.
(Informational)
The Board discussed: the need for targeted and specific outreach efforts to customers for each of VCE’s jurisdictions; increased engagement on social media to build brand awareness and opt ups, including efforts to have each jurisdiction opt up their (building) accounts.
There were no written or verbal public comments.
Item 22:
Overview of 2022
draft budget and
customer rates.
Mr. Sears provided an update on the California Public Utilities Commission (CPUC) filing process and the revised timeline for a decision on Power Charge Indifference Adjustment (PCIA) and PG&E rates. CPUC will be making a decision at their Commission meeting scheduled for February 10th, the same day as the Board’s next regular meeting. Mr.
Sears reviewed the background, 2022 customer rate and budget scenarios, Community Advisory Committee’s January 20, 2022 updated recommendation on this item, and next steps.
The Board briefly discussed: impacts to customers, rate structure clarification, timing of re-evaluation of rates, rebates, and programs, and outreach efforts to customers explaining increases.
There were no verbal or written public comments.
Item 23: Board
Member and
Staff
Announcements
Director Saylor provided the status on Yolo County’s SACOG projects and informed those present that contracts were signed for three (3) Yolo County buildings where electric vehicle charging stations will be installed.
Director Carson informed those present that the Davis City Council in response to local comments received, adopted a resolution asking that the proposed decision on Net Energy Metering (NEM) 3.0 be put on hold as more information and analysis is needed.
Director Saylor informed those present that Yolo County sent a letter also asking that the proposed decision on NEM 3.0 be placed on hold.
Chair Loren informed those present that the City of Winters installed electric vehicle (EV) charging stations with assistance from the SACOG grant. In addition, the city passed ordinances limiting the time an EV owner could use the charger. Lastly, she noted that users of the EV chargers are paying for the electric at the site.
11 VCEA Minutes January 27, 2022 Board Special Meeting via Webinar Page 4 of 4 Mr. Sears informed those present that Staff have been discussing and analyzing potential impacts to customers of NEM 3.0. Staff will continue to analyze impacts to VCE’s customers.
Mr. Sears informed those present that next week he will be attending the groundbreaking at the Aquamarine site, of which VCE has contracted for 50 Megawatts of energy.
Mr. Sears thanked VCE Staff Rebecca Boyles and Sierra Huffman for all of their work on the AgFIT program.
Adjournment Chair Loren announced that the Board’s next regular meeting is scheduled for Thursday, February 10, 2022 at 5 p.m. She announced that the Board will convene into Closed Session and that it is anticipated there will be nothing to report out of closed session. Chair Loren adjourned the regular Board meeting at 6:32 p.m. to go into Closed Session.
CLOSED SESSION:
Public Employee
Performance
Evaluation (Gov.
Code Section
54957)
The Board entered into Closed Session at 6:35 p.m. Closed session ended at 7:14 p.m.
Alisa M. Lembke
VCEA Board Secretary
12 VALLEY CLEAN ENERGY ALLIANCE
Staff Report - Item 5
____________________________________________________________________________________ TO: Board of Directors
FROM: Alisa Lembke, Board Clerk/Administrative Analyst
SUBJECT: Board and Community Advisory Committee 2022 Long-Range Calendar DATE: February 10, 2022
Recommendation
Receive and file the 2022 Board and Community Advisory Committee long-range calendar listing proposed meeting topics.
13 2/3/22
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
• Time of Use (TOU) (placeholder)
• Informational
• Discussion/Action
• Action
• Discussion/Action
March 24, 2022 Advisory
Committee
WOODLAND
• Update on Time of Use (TOU) (placeholder)
• Update on customer program concept
• Review of Forecasting (load) (placeholder)
• Informational
• Informational
• Informational/Discussion
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
• Review of Forecasting (PCIA and PG&E rates) (placeholder) • Informational
• Informational
• Action: Recommendation
to Board
• Information
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)
• Mid-year rates review – feasibility of allocation of funds to other areas (placeholder)
• Discussion/Action
• Informational
• Informational
• Informational
• Informational/Discussion
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
15 June 23, 2022 Advisory
Committee
DAVIS
• Prioritizing types of energy (placeholder)
• Net Energy Metering (NEM) 3.0 Update (placeholder)
• Discussion/Action
• Informational
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
16 November 17, 2022
(rescheduled
November 24th
meeting due to the
Thanksgiving holiday)
Advisory
Committee
WOODLAND
• Finalize Committee Evaluation of Calendar Year End (Annual) • Review draft revised Procurement Guide (placeholder)(Annual) • FY22/23 Operating Budget / RPS update
• Power Procurement / Renewable Portfolio Standard Update • Review CAC Charge (tentative) (Annual)
• Discussion/Action
• Action: Recommendation
to Board
• 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 15, 2022
(rescheduled
December 22nd
meeting due to the
Christmas holiday)
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 6
______________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Interim General Manager
Edward Burnham, Finance and Operations Director
SUBJECT: Financial Update – December 1, 2021 (unaudited) financial statements (with comparative year to date information) and Actual vs. Budget year to date ending December 31, 2021
DATE: February 10, 2022
RECOMMENDATION:
Accept the following Financial Statements (unaudited) for the period of December 1, 2021 to December 31, 2021 (with comparative year to date information) and Actual vs. Budget year to date ending December 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 December 31, 2021.
Financial Statements for the period December 1, 2021 – December 31, 2021 In the Statement of Net Position, VCEA, as of December 31, 2021, has a total of $3,990,009 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 $2,461,158 restricted assets for the Power Purchases Reserve account. VCE has incurred obligations from Member agencies and owes as of December 31, 2021, $117,945. 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 $1,153,026. On December 31, 2021, VCE’s net position is $9,749,097.
In the Statement of Revenues, Expenditures, and Changes in Net Position, VCEA recorded $4,195,092 of revenue (net of allowance for doubtful accounts), of which $3,808,159 was billed in December and $1,768,193 represent estimated unbilled revenue. The cost of the electricity for the December revenue totaled $4,458,815. For December, VCEA’s gross margin was approximate -23.78% and net loss totaled ($1,158,362). The year-to-date change in net position was ($2,732,293).
In the Statement of Cash Flows, VCEA cash flows from operations were ($450,670) due to December cash receipts of revenues being less than the monthly cash operating expenses.
Actual vs. Budget Variances for the year to date ending December 31, 2021 Below are the financial statement line items with variances >$50,000 and 5% • Electric Revenue - $4,939,612 and 20% – 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, and rate adjustment starting November 1, 2021.
• Purchased Power - $2,689,275 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, and rising power costs.
• Program Costs – ($67,500) and (100%) – favorable variance to budget is due to not having utilized budgeted annual program costs expected in later periods.
• Contingency – ($67,867) and (100%) – favorable variance to budget is due to not having a need yet to utilize the contingency funds set aside in the budget.
Attachments:
1) Financial Statements (Unaudited) December 1, 2021 to December 31, 2021 (with comparative year to date information.)
2) Actual vs. Budget for the year to date ending December 31, 2021 19 VALLEY CLEAN ENERGY ALLIANCE
FINANCIAL STATEMENTS
(UNAUDITED)
FOR THE PERIOD OF DECEMBER 1 TO DECEMBER 31, 2021
PREPARED ON FEBRUARY 2, 2022
20 2
ASSETS
Current assets:
Cash and cash equivalents $ 3,990,009
Accounts receivable, net of allowance 7,129,816
Accrued revenue 1,768,193
Prepaid expenses 885,230
Other current assets and deposits 1,998,276
Total current assets 15,771,524
Restricted assets:
Debt service reserve fund 1,100,000
Power purchase reserve fund 2,461,158
Total restricted assets 3,561,158
Noncurrent assets:
Other noncurrent assets and deposits
Total noncurrent assets -
TOTAL ASSETS $ 19,332,682
LIABILITIES
Current liabilities:
Accounts payable $ 529,237
Accrued payroll 63,909
Interest payable 2,786
Due to member agencies 117,945
Accrued cost of electricity 5,332,169
Other accrued liabilities 285,750
Security deposits - energy supplies 1,980,000
User taxes and energy surcharges 118,763
Limited Term Loan 1,153,026
Total current liabilities 9,583,585
Noncurrent liabilities
Term Loan- RCB
Total noncurrent liabilities -
TOTAL LIABILITIES $ 9,583,585
NET POSITION
Restricted
Local Programs Reserve 224,500
Restricted 3,561,158
Unrestricted 5,963,439
TOTAL NET POSITION $ 9,749,097
(UNAUDITED)
VALLEY CLEAN ENERGY ALLIANCE
STATEMENT OF NET POSITION
DECEMBER 31, 2021
21 3
FOR THE PERIOD
ENDING
DECEMBER 31, 2021 YEAR TO DATE
OPERATING REVENUE
Electricity sales, net $ 3,616,867 $ 29,676,961
TOTAL OPERATING REVENUES 3,616,867 29,676,961
OPERATING EXPENSES
Cost of electricity 4,458,815 30,132,779
Contract services 195,280 1,383,829
Staff compensation 94,690 537,689
General, administration, and other 24,224 341,143
TOTAL OPERATING EXPENSES 4,773,009 32,395,440
TOTAL OPERATING INCOME (LOSS) (1,156,142) (2,718,479)
NONOPERATING REVENUES (EXPENSES)
Other Revenue
Interest income 1,325 8,731
Interest and related expenses (3,545) (22,545)
TOTAL NONOPERATING REVENUES
(EXPENSES) (2,220) (13,814)
CHANGE IN NET POSITION (1,158,362) (2,732,293)
Net position at beginning of period 10,907,459 12,481,390 Net position at end of period $ 9,749,097 $ 9,749,097
(UNAUDITED)
CHANGES IN NET POSITION
FOR THE PERIOD OF DECEMBE 1, 2021 TO DECEMBER 31, 2021
(WITH COMPARATIVE YEAR TO DATE INFORMATION)
VALLEY CLEAN ENERGY ALLIANCE
STATEMENT OF REVENUES, EXPENDITURES AND
22 4
FOR THE
PERIOD ENDING
DECEMBER 31, 2021 YEAR TO DATE
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from electricity sales $ 4,195,092 $ 31,566,898 Receipts for security deposits with energy suppliers - - Payments to purchase electricity (3,880,924) (31,379,421) Payments for contract services, general, and adminstration (671,295) (3,251,148) Payments for staff compensation (84,870) (517,485)
Other cash payments (8,673) (11,393)
Net cash provided (used) by operating activities (450,670) (3,592,549)
CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES
Principal payments of Debt (32,943) (197,661)
Interest and related expenses (3,528) (23,018)
Net cash provided (used) by non-capital financing activities (36,471) (220,679)
CASH FLOWS FROM INVESTING ACTIVITIES
Interest income 1,325 8,731
Net cash provided (used) by investing activities 1,325 8,731 NET CHANGE IN CASH AND CASH EQUIVALENTS (485,816) (3,804,497) Cash and cash equivalents at beginning of period 8,036,983 11,355,664 Cash and cash equivalents at end of period $ 7,551,167 $ 7,551,167 Cash and cash equivalents included in:
Cash and cash equivalents 3,990,009 3,990,009
Restricted assets 3,561,158 3,561,158
Cash and cash equivalents at end of period $ 7,551,167 $ 7,551,167
VALLEY CLEAN ENERGY ALLIANCE
STATEMENTS OF CASH FLOWS
FOR THE PERIOD OF DECEMBER 1 TO DECEMBER 31, 2021
(WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
23 5
FOR THE
PERIOD ENDING
DECEMBER 31, 2021 YEAR TO DATE
Operating Income (Loss) $ (1,156,142) $ (2,718,479)
(Increase) decrease in net accounts receivable 304,244.41 674,395.41 (Increase) decrease in accrued revenue 257,252 1,167,097.74 (Increase) decrease in prepaid expenses (317,970) (870,087.00) (Increase) decrease in inventory - renewable energy credits - - (Increase) decrease in other assets and deposits (8,673) (11,393.00) Increase (decrease) in accounts payable (33,210) 45,276.00 Increase (decrease) in accrued payroll 9,820 20,204.00
Increase (decrease) in due to member agencies 20,963 (5,461.00) Increase (decrease) in accrued cost of electricity 577,891 (1,246,642.00) Increase (decrease) in other accrued liabilities (121,574) (695,904.00) Increase (decrease )security deposits with energy suppliers - - Increase (decrease) in user taxes and energy surcharges 16,729 48,443.90 Net cash provided (used) by operating activities $ (450,670) $ (3,592,549)
RECONCILIATION OF OPERATING INCOME TO NET CASH
PROVIDED (USED) BY OPERATING ACTIVITIES
(WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
FOR THE PERIOD OF DECEMBER 1 TO DECEMBER 31, 2021
VALLEY CLEAN ENERGY ALLIANCE
STATEMENTS OF CASH FLOWS
24 VALLEY CLEAN ENERGY
ACTUAL VS. BUDGET FYE 12-31-21 (6 Month)
FOR THE YEAR TO DATE ENDING 12/31/21
12/31/2021 12/31/2021
YTD YTD YTD %
GL# Description FY2022 Actuals FY2022 Budget Variance over/-under 301.00 Electric Revenue 24,737,349 29,676,961 4,939,612 20% 311.00 Interest Revenues 28,200 8,731 (19,469) -69%
415.00 Purchased Power 27,443,504 30,132,779 2,689,275 10% Labor & Benefits 579,577 537,689 (41,888) -7%
451.10 Salaries & Wages/Benefits 488,740 454,502 (34,237) -7% 451.20 Contract Labor 23,302 - (23,302) -100%
453.41 Human Resources & Payroll 67,536 83,187 15,651 23% Office Supplies & Other Expenses 94,224 101,938 7,714 8% 452.10 Technology Costs 17,016 15,652 (1,365) -8%
452.15 Office Supplies 1,152 1,547 395 34%
452.25 Travel 3,048 - (3,048) -100%
452.30 CalCCA Dues 62,107 56,075 (6,033) -10%
CC Power 10,000 28,440 18,440 184%
452.35 Memberships 900 224 (676) -75%
Contractual Services 1,368,998 1,296,794 (72,204) -5%
453.10 Other Contract Services 12,000 - (12,000) -100%
453.15 Don Dame 5,000 5,155 155 3%
453.20 SMUD - Credit Support 329,976 328,787 (1,189) 0% 453.21 SMUD - Wholesale Energy Services 292,986 293,922 936 0% 453.22 SMUD - Call Center 393,733 396,310 2,577 1%
453.23 SMUD - Operating Services 30,000 59,236 29,236 97% 453.24 Commercial Legal Support - - - 100%
453.25 Legal General Counsel 75,645 46,299 (29,346) -39% 453.36 Regulatory Counsel 97,330 79,726 (17,604) -18%
453.37 Joint CCA Regulatory counsel 15,759 602 (15,158) -96% 453.38 Legislative - (Lobbyist) 30,000 35,000 5,000 17% 453.40 Accounting Services 12,608 4,458 (8,150) -65%
453.41 Financial Consultant 12,500 - (12,500) -100%
453.42 Audit Fees 61,462 47,300 (14,162) -23%
453.60 PG&E Acquisition Consulting - - - 100%
Marketing 117,079 78,849 (38,230) -33%
459.05 Marketing Collateral 113,940 78,299 (35,641) -31% 459.15 Community Engagement Activities & Sponsorships 3,139 550 (2,589) -82% Programs 67,500 - (67,500) -100%
Program Costs 67,500 - (67,500) -100%
Rents & Leases 12,060 7,950 (4,110) -34%
457.10 Hunt Boyer Mansion 12,060 7,950 (4,110) -34%
Other A&G 204,145 236,718 32,574 16%
459.08 Development - New Members 12,000 - (12,000) -100% 459.09 Strategic Plan Implementation 37,500 62,261 24,761 66% 459.10 PG&E Data Fees 150,149 133,451 (16,698) -11%
459.20 Insurance 3,865 9,201 5,335 138%
459.70 Banking Fees 630 31,806 31,176 4946%
463.10 Miscellaneous Operating Expenses 3,221 2,722 (500) 0% 463.99 Contingency 67,867 - (67,867) -100%
TOTAL OPERATING EXPENSES 29,958,174 32,395,440 2,437,266 8% 481.10 Interest on RCB loan 23,019 22,545 (473) -2%
NET INCOME (5,215,643) (2,732,293) 2,483,350 -48%
25 1
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 7
To: Board of Directors
From: Mitch Sears, Interim General Manager
Subject: Regulatory Monitoring Report – Keyes & Fox
Date: February 10, 2022
______________________________________________________________________________ Please find attached Keyes & Fox’s January 2022 Regulatory Memorandum dated February 4, 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 February 4, 2022. 26 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: February 4, 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: VCE submitted Advice Letter 11-E on January 5, 2022, detailing information on its implementation of its agricultural irrigation pumping dynamic rates pilot. On January 25, 2022, PG&E filed a protest of VCE’s AL 11-E, to which VCE replied on January 31, 2022. On January 31, 2022, VCE, Polaris and TeMix filed a Petition for Modification of D.21-12-015 to authorize a VCE administrative budget for the pilot. • IRP Rulemaking: On January 27, 2022, the CPUC decided to hold until its February 10, 2022, meeting a vote on the Proposed Decision adopting a 2021 Preferred System Plan. The PD, if approved, would certify VCE’s 2020 IRP, finding numerous sections were “exemplary.” On February 1, 2022, VCE and other LSEs submitted compliance filings updating the CPUC on their incremental procurement.
• PG&E 2022 ERRA Forecast: The ALJ issued a Proposed Decision. Parties filed comments on the PD on January 31, 2022, and reply comments on February 3, 2022. • RPS Rulemaking: The CPUC approved D.22-01-025, fining Gexa Energy $352,500 for non-compliance with mandatory reporting requirements of its RPS contracts standard terms and conditions.
• PG&E’s Phase 2 GRC: On January 14, 2022, a group of parties filed a Settlement Agreement resolving all issues included within the scope related to program and rate design issues for Stage 1 Real-Time Pricing (RTP) Pilots. On January 18, 2022, PG&E filed several motions, including requesting (1) that its Marginal Generation Capacity Cost (MGCC) Study be filed on the same date in this docket as it is required, which was granted by the ALJ in the form of an 8-week extension, and (2) that it be allowed to supplement its testimony in this proceeding with a Declaration on costs, which was also granted. PG&E and CLECA filed a Motion requesting the CPUC to establish a separate expedited schedule to allow a final decision adopting the Joint Stipulation (or otherwise resolving the single carryover issue of material fact about the MGCC 27 2
Property Tax Adder) by March 17, 2022. Parties responded to the Motion on February 1, 2022. In addition, an evidentiary hearing on RTP issues was held January 26, 2022, during which a representative from each of the Settling Parties participated in a Settlement Panel. • 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.
• RA Rulemaking (2023-2024): On January 19, 2022, the final workshop to develop PG&E’s Slice-of-Day proposal and related RA program structural reform was held. On January 21, 2022, parties filed Phase 2 proposals. The Local Capacity Requirement (LCR) Working Group held a meeting on February 2, 2022.
• PG&E’s 2019 ERRA Compliance: On January 18, 2022, the CCA Parties and TURN filed Phase 2 testimony.
• PCIA Rulemaking: On January 27, 2022, the CPUC approved D.22-01-023 targeting improvements to the process of establishing the PCIA in ERRA proceedings. • Provider of Last Resort Rulemaking: A January 27, 2022, email to parties tentatively rescheduled the date of the second workshop to March 7, 2022. • 2022-2023 Wildfire Fund Nonbypassable Charge Rulemaking: No updates this month. The CPUC issued D.21-12-006 adopting a Wildfire Fund NBC of $0.00652/kWh for January 1, 2022, through December 31, 2022.
• Utility Safety Culture Assessments: No updates this month. 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.
• 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.
Ensuring Summer 2021 Reliability
VCE submitted Advice Letter 11-E on January 5, 2022, detailing information on its implementation of its pilot. On January 25, 2022, PG&E filed a protest of VCE’s AL 11-E, to which VCE replied on January 31, 2022. On January 31, 2022, VCE, Polaris and TeMix filed a Petition for Modification of D.21-12-015 to authorize a VCE administrative budget for the pilot, along with a motion to shorten time for comments. 28 3
• Background: CAISO experienced rolling blackouts (Stage 3 Emergency) on August 14, 2020, and August 15, 2020, when a heatwave struck the Western U.S. and there was insufficient available supply to meet high demand. The OIR was issued to ensure reliable electric service in the event that an extreme heat storm occurs in the summer of 2021.
D.21-03-056 instituted modifications to the planning reserve margin (PRM), effectively increasing the PRM beginning summer 2021 from 15% to 17.5%. For 2021, this results in a minimum target of incremental procurement of 450 MW for PG&E, 450 MW for SCE, and 100 MW for SDG&E.
The net costs associated with this incremental procurement would be shared by all customers (including CCA customers) in each IOU’s service territory. It also authorized the IOUs to implement a Flex Alert paid media campaign program to encourage ratepayers to voluntarily reduce demand during moments of a stressed grid, adopts modifications and expansions to the Critical Peak Pricing (CPP) program, and established an emergency load reduction program.
D.21-12-015 approved VCE’s dynamic rate pilot for three years (2022-2024) and directed that it start no later than May 1, 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 authorized new funding to PG&E of $3.25 million for the administration and execution of the three-year pilot.
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.
• Details: VCE’s AL 11-E provided information on the implementation of its Agricultural Pumping Dynamic Rate Pilot as required by D.21-12-015. PG&E filed a protest of AL 11-E asserting that the following requirements applied to the pilot:
o A Request for Proposals process for the independent evaluator of the pilot. o Third-party data security review of VCE and its contractors’ systems. o A services-style contract between PG&E and VCE in order for VCE to have access to pilot funding authorized in D.21-12-015 for payment of customer pumping automation technology, payment of VCE’s vendors and payment of VCE’s administrative expenses. o VCE reporting to the Energy Division.
o PG&E has the responsibility to develop the distribution rate component in the pilot.
VCE filed a reply to VCE on January 31, 2022, asserting, among other points, that a services contract between VCE and PG&E is inappropriate and that additional reporting is duplicative.
VCE, Polaris and TeMix filed a Petition for Modification of D.21-12-015 to increase the budget for this Pilot to ensure that the total budget covers VCE’s administrative costs. VCE, Polaris and TeMix also filed a Motion to Shorten Time for comments on the PFM as well as on the Commission’s proposed decision resolving the PFM.
• Analysis: PG&E was resistant to the authorization of VCE’s pilot in its comments to the Commission, and its actions since the pilot was approved have had the impact of delaying pilot 29 4
implementation. VCE is seeking approval of its advice letter and petition for modification to facilitate implementation of the pilot.
• Next Steps: The proceeding is now closed. 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: VCE Reply to PG&E Protest of VCE AL 11-E (January 31, 2022); VCE, TeMix and Polaris Petition for Modification (January 31, 2022); Motion to Shorten Time (January 31, 2022); PG&E Protest of VCE AL 11-E (January 25, 2021); D.21-12-069 correcting errors in D.21-12-014 (December 27, 2021); D.21-12-015 (December 6, 2021); D.21-09-045 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 January 27, 2022, the CPUC decided to hold until its February 10, 2022, meeting a vote on the Proposed Decision issued on December 22, 2021 adopting a 2021 Preferred System Plan. The PD, if approved, would certify VCE’s 2020 IRP, finding numerous sections were “exemplary.” On February 1, 2022, VCE and other LSEs submitted compliance filings updating the CPUC on their incremental procurement.
• 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-30 5 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.
A pending December 2021 CCA motion for clarification pertains to cost recovery of resources under D.19-11-016, which 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.
• 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 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.
• 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: The PD may be heard, at the earliest, at the CPUC's February 10, 2022, business meeting.
• Additional Information: Proposed Decision adopting 2021 Preferred System Plan (December 22, 2021); CCA Motion for Clarification (December 13, 2021); D.21-06-035 establishing a 11,500 MW by 2026 procurement mandate (June 24, 2021); D.21-02-028 recommending portfolios for CAISO’s 2021-2022 TPP (February 17, 2021); D.20-12-044 establishing a backstop procurement process (December 22, 2020); Scoping Memo and Ruling (September 24, 2020); Resolution E-5080 (August 7, 2020); Order Instituting Rulemaking (May 14, 2020); Docket No. R.20-05-003. 31 6
PG&E 2022 ERRA Forecast
On January 24, 2022, the ALJ issued a Proposed Decision. Parties filed comments on January 31, 2022, and reply comments on February 3, 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.
PG&E’s Fourth Supplemental Testimony included both an “October Update” and a “December Update.” A group of CCA parties recommended in comments that the CPUC adopt the proposed forecasted revenue requirements and associated rates from the December Update and requested the rates be implemented by February 1, 2022. The CCA parties said that adopting the December update would reduce likely volatility between 2022 and 2023 rates and that adoption of an October Update would clearly violate State law and Commission precedent. The CCAs noted that PG&E’s forecasted costs to serve load in 2022 are 66.5% higher than in 2021.
CalCCA 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. • Details: The PD would approve a 2022 forecast of electric sales and energy procurement revenue requirements of $2.4 billion. It would find the December Update, updated again with the actual year end ERRA-main account balance provides the most accurate forecast for 2022 revenue requirements, and approve the 12-month amortization that was supported by CCAs.
Under the December Update adopted in the PD, the 2022 total PCIA rate for 2017-vintaged customers (i.e., most VCE customers) would fall 59% relative to 2021 to $0.02061/kWh for residential customers and to $0.01980/kWh on a system-average basis. The PD would also agree with the Joint CCAs and DACC that all customers who were financially responsible for the ERRA-PCIA Financing Subaccount (ERRA-PFS) balance should be entitled to the appropriate credit and direct PG&E to transfer the $95 million ERRA-PFS credit for 2022 to the 2020 vintage subaccount. The PD would approve a request by CCAs and direct PG&E to include the confidential workpapers supporting the PCIA rates from the prior year’s ERRA Forecast proceeding as part of the Master Data Request it will provide in each subsequent ERRA Forecast proceeding. The PD would deny without prejudice the CCA’s request to direct PG&E to provide data demonstrating its future role as a CPE in future ERRA forecast proceedings. • Analysis: The PD results in a 59% reduction to VCE’s PCIA rates in 2022 compared to 2021.
While the PCIA rate will fall substantially in 2022 for VCE customers, the non-RPS benchmarks that contributed to the reduction in the PCIA in 2022 could result in the opposite effect in 2023.
That is, the same high benchmarks that helped reduce the 2022 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. The PD would also improve transparency by approving the CCAs’ request for PG&E to provide confidential workpapers supporting the PCIA rates from the prior year’s ERRA Forecast proceeding as part of the Master Data Request it will provide in each subsequent ERRA Forecast proceeding.
32 7
• Next Steps: The final decision can be adopted on February 10, 2022. • Additional Information: Proposed Decision (January 24, 2022); Ruling modifying procedural schedule (January 14, 2022); Ruling directing PG&E to provide amortization scenarios (December 17, 2021); Scoping Memo and Ruling (August 11, 2021); Notice of Prehearing Conference (July 15, 2021); Application (June 1, 2021); Docket No. A.21-06-001.
RPS Rulemaking
On January 27, 2022, the CPUC approved D.22-01-025, fining Gexa Energy $352,500 for non-compliance with mandatory reporting requirements of its RPS contracts standard terms and conditions. • 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.
D.22-01-004 directed 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.
A pending Joint Motion by IOUs requests 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 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. • Details: In D.22-01-025, the CPUC found that Gexa, an ESP that is currently not serving any load, met its procurement quantity requirement for the Compliance Period 2014-2016 and retired sufficient RECs. However, by excluding non-modifiable standard terms and conditions, it found Gexa was out of compliance with the requirement to include the nonmodifiable standard terms and conditions in its contract. Gexa retroactively added the non-modifiable and the modifiable standard terms and conditions to its contract after the Compliance Period had closed.
Accordingly, the CPUC imposed a fine for the period that the REC Agreement underlying Gexa’s Compliance Report was out of compliance with the applicable RPS program rules. The decision assessed a penalty of $352,500.
• Analysis: D.22-01-025 provides another example of how the CPUC has strictly interpreted regulatory compliance requirements and issued sizeable penalties in cases of non-compliance. • 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.22-01-025 fining Gexa for RPS non-compliance (approved at January 27, 2022, meeting); 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 33 8
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.
PG&E’s Phase 2 GRC
On January 14, 2022, a group of parties filed a Settlement Agreement resolving all of the issues included within the scope related to program and rate design issues for Stage 1 Real-Time Pricing (RTP) Pilots.
On January 18, 2022, PG&E filed several motions, including requesting (1) that its Marginal Generation Capacity Cost (MGCC) Study be filed on the same date in this docket as it is required, which was granted by the ALJ in the form of an 8-week extension, and (2) that it be allowed to supplement its testimony in this proceeding with a Declaration on costs, which was also granted. On January 21, 2022, PG&E and CLECA filed a Motion requesting the CPUC to establish a separate expedited schedule to allow a final decision adopting the Joint Stipulation (or otherwise resolving the single carryover issue of material fact about the MGCC Property Tax Adder) by March 17, 2022. Parties responded to the Motion on February 1, 2022. In addition, an evidentiary hearing on RTP issues was held January 26, 2022, during which a representative from each of the Settling Parties participated in a Settlement Panel. • 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 Settlement Agreement includes the following terms of the Stage 1 RTP pilot:
o Eligibility: PG&E’s bundled customers who are eligible for the B-20, B-6 and E-ELEC rates may participate on an opt-in basis. CCAs will need to affirmatively decide to participate in the Stage 1 Pilots for their customers to be eligible. PG&E agrees to work with its twelve CCAs to seek agreement from one or two of them to participate in the Stage 1 Pilots, if possible.
o Duration: Stage 1 Pilots shall have a duration of 24 months, subject to potential extension.
o Enrollment: PG&E will make its best efforts to program and make available for enrollment the three Stage 1 RTP rates by October 1, 2023.
34 9
o Pricing: The RTP element of the Stage 1 Pilot RTP rates will replace the generation component of the customer’s otherwise applicable rate schedule. The remaining transmission, distribution, Public Purpose Program and other charges and taxes remain the same as the otherwise applicable underlying rate. The generation component to be used in the Stage 1 Pilots’ RTP rates will include: (1) a Marginal Energy Charge, (2) a Marginal Generation Capacity Cost, and (3) a Revenue Neutral Adder (designed to make the forecasted annual generation revenue collected under the three Stage 1 Pilot RTP rates revenue neutral to the base schedule). Residential customers would have 1 year bill protection. There would be a limited amount of participation incentives as well.
All development, implementation and operating costs for the Stage 1 Pilots, as well as for the separate Customer Research Study for residential, agricultural, and small commercial customers, will be recovered in distribution rates from all customers.
PG&E/CLECA filed a Motion requesting to establish a separate expedited schedule to allow a final decision adopting the Joint Stipulation (or otherwise resolving the single carryover issue of material fact about the MGCC Property Tax Adder) by March 17, 2022. The ALJ issued a Ruling on January 25, 2022, directing parties to respond by February 1, 2022.
PG&E filed several motions on January 18, 2022. In the first Motion, PG&E requested the Marginal Generation Capacity Cost (MGCC) Study be filed on the same date in this docket as it is required to be filed in A.20-10-011, the proceeding for the real-time commercial electric vehicle rate (DAHRTPCEV). PG&E further requested an ALJ Ruling setting dates for MGCC related testimony and hearings for this proceeding on a combined basis with the same issues in the DAHRTP-CEV case. A January 25, 2022, email from PG&E indicated that the ALJ approved an 8-week extension. In the second Motion, PG&E requested to supplement its testimony in this proceeding with the Declaration on costs for the Residential Stage 1 RTP pilot. • Analysis: This phase of the proceeding could impact real-time pricing rate design issues for PG&E customers. If the settlement agreement is adopted, VCE could elect to allow its customers to participate in the Stage 1 RTP pilot. The Settlement Agreement provides that cost recovery of development, implementation and operating costs for the Stage 1 Pilots, as well as for the separate Customer Research Study, would be recovered in distribution rates that both bundled PG&E and VCE customers pay.
• Next Steps: The proceeding remains open to address RTP issues. PG&E/CLECA reply comments are due February 7, 2022. PG&E’s MGCC Study is due March 15, 2022., 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: Ruling on timing to respond to PG&E/CLECA Motion (January 25, 2022); Motion by PG&E/CLECA to establish a separate expedited schedule (January 21, 2022); PG&E Motion on MGCC Study (January 18, 2022); PG&E Motion (January 18, 2022); Motion to Adopt Settlement Agreement (January 18, 2022); D.21-11-016 on revenue allocation and rate design (November 19, 2021); Amended Scoping Memo and Ruling (August 25, 2021); Ruling bifurcating RTP issues into separate track (February 2, 2021); D.20-09-021 on EUS budget (September 28, 2020); Exhibit (PG&E-5) (May 15, 2020); Scoping Memo and Ruling (February 10, 2020); Application, Exhibit (PG&E-1): Overview and Policy, Exhibit (PG&E-2): Cost of Service, Exhibit (PG&E-3): Revenue Allocation, Rate Design and Rate Programs, and Exhibit (PG&E-4): Appendices (November 22, 2019); Docket No. A.19-11-019.
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 35 10
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 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. 36 11
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.
RA Rulemaking (2023-2024)
On January 19, 2022, the final workshop to develop PG&E’s Slice-of-Day proposal and related RA program structural reform was held. On January 21, 2022, parties filed Phase 2 proposals. The Local Capacity Requirement (LCR) Working Group held a meeting on February 2, 2022. • Background: In Track 3B.2 of the 2021-2022 RA Rulemaking (R.19-11-009), D.21-07-014 rejected CalCCA/SCE's proposal for restructuring the 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 now that workshops to develop this proposal have been completed. 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 37 12
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 proposals were submitted in January 2022 and this phase is expected to conclude in June 2022. Neither CalCCA nor any CCAs individually filed a Phase 2 proposal.
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 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
• Energy Division’s loss of load expectation (LOLE) study and proposal: February 1, 2022 • Workshop on proposals: February 4, 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
• Informal comments: February 4, 2022
• Workshop report: February 2022
BTM Counting Convention Working Group meeting dates (9am-1pm): 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 38 13
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.
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.
39 14
• 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 Memo and Ruling (June 19, 2020); PG&E’s Application and Testimony (February 28, 2020); Docket No. A.20-02-009.
PCIA Rulemaking
On January 27, 2022, the CPUC approved D.22-01-023 targeting improvements to the process of establishing the PCIA in ERRA proceedings.
• 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 40 15
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: D.22-01-023 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 adopted party proposals to establish a policy for disposition of the year-end balance in the ERRA account and to modify the calculation of the ERRA trigger point and threshold. It also adopted party proposals to support efficient party access to ERRA forecast proceeding data.
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. • Analysis: D.22-01-023 makes improvements to the annual ERRA process and CCA access to pertinent IOU data.
• Next Steps: D.21-05-030 identified the following next steps:
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: D.22-01-023 on Phase 2 (approved January 27, 2021); Ruling requesting comments on PCIA forecasting data access (November 5, 2021); Ruling requesting comments (September 17, 2021); 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
41 16
A January 27, 2022, email to parties tentatively rescheduled the date of the second workshop to March 7, 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.
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 November 5, 2021, and (2) questions on Workshop 1 and what changes if any are recommended to adequately meet POLR requirements. 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.
• Details: A forthcoming ruling will provide additional details on comment and reply comment deadlines, as well as a workshop agenda for the March 7, 2022 workshop. • 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 42 17
POLR to step in to serve those customers. Second, in setting the requirements and application process for another entity to be designated as the POLR, it could create a pathway for a CCA or other retail provider to elect to become a POLR for its service area. The preliminary questions (Appendix B to the OIR) suggest these issues will include examining topics such as CCA financial security requirements, portfolio risk and hedging, CCA deregistration, CCA mergers, and CCA insolvency.
• Next Steps: A second workshop in Phase 1 has been tentatively rescheduled for March 7, 2022.
A forthcoming ruling will provide an updated schedule for comments and reply comments • 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. 2022-2023 Wildfire Fund Nonbypassable Charge Rulemaking No updates this month. 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.
Utility Safety Culture Assessments
No updates this month. 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 43 18
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 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 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. 44 19
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 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. 45 20
• 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 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 46 21
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
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. 47 22
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.
• 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 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.
48 23
• 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 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.
49 24
• 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.
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 50 25
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 issued next.
• 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 51 26
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.
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 52 27
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
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
53 28
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
TOU Time of Use
TURN The Utility Reform Network
UOG Utility-Owned Generation
WMP Wildfire Mitigation Plan
WSD Wildfire Safety Division (CPUC)
54 1
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 8
TO: Board of Directors
FROM: Rebecca Boyles, Director of Customer Care & Marketing SUBJECT: Customer Enrollment Update (Information)
DATE: February 10, 2022
RECOMMENDATION
Receive and review the attached Customer Enrollment update as of February 2, 2022.
55 0
20 40
60 80
100
120
140
160
Monthly Opt Outs
Item 8 - Enrollment Update
Status Date: 02/2/22 1
All Winters customers are now enrolled and are included in this table. % of Load Opted Out
Residential Commercial Industrial Ag Total
10% 9% 0% 13% 10%
Davis Woodland Winters Yolo Co Total Residential Commercial Industrial Ag NEM Non-NEM VCEA customers 28,079 20,514 2,542 10,768 61,903 53,864 6,087 7 1,857 10,844 51,059 Eligible customers 29,372 23,552 2,853 12,321 68,098 59,163 6,692 7 2,132 12,004 56,094 Participation Rate 96% 87% 89% 87% 91% 91% 91% 100% 87% 90% 91% 56 Davis
77%
Woodland
15%
Unincorp. Yolo
6%
Winters
2%
317 Opt Ups*
0 5
10 15
20 25
Monthly Opt Ups*
Item 8 - Enrollment Update
Status Date: 02/2/22 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. 57 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 8 - Enrollment Update
Status Date: 02/2/22 3
* These numbers represent all opt up actions ever taken regardless of current customer enrollment status. 58 Item 8 - Enrollment Update
Status Date: 02/2/22 4
* These numbers represent all opt up actions ever taken regardless of current customer enrollment status.
Davis
66%
Woodland
22%
Unincorp. Yolo
10%
Winters
2%
489 Opt Ups*
Davis
21%
Woodland
48%
Unincorp. Yolo
27%
Winters
4%
10588 Opt Outs
59 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 9
TO: Board of Directors
FROM: Alisa Lembke, Board Clerk / Administrative Analyst SUBJECT: Community Advisory Committee January 20, 2022 Meeting Summary DATE: February 10, 2022
This report summarizes the Community Advisory Committee’s meeting held via Zoom webinar on Thursday, January 20, 2022.
A. Considered Cost-based Customer Rates – 2022 Customer Rates. The CAC received an update on the CPUC filing process and the revised timeline for a decision on PCIA and PG&E rates. The CAC received 2022 financial forecast update, budget scenarios based on anticipated PCIA and PG&E rates, reserves target, and rates implementation procedure.
Staff provided a copy of the CAC’s November 10th recommendation to the Board on rates and presented staff’s updated recommendation based on the most recent PCIA and PG&E information collected in the past several months. Staff recommended that the CAC amend their November 10th recommendation. The CAC discussed rate stability, forecasting of revenue and costs, impacts such as hedging on forecasting, Dividend policy consideration, programs, renewable energy, potential impacts of NEM 3.0 on rates, improving forecasting for cost-based rate setting/assessment. After the discussion, the CAC recommended (8-0- 0) that the Board:
1. Adopt customer rates for 2022 to match PG&E 2022 generation rates for all customer classes to cover VCE’s FY 2022 budget expenditures and to achieve between 80-90 days cash reserves by the end of 2022;
2. Provide a 2.5% rate credit for CARE and FERA customers in 2022;
3. Conduct a mid-year rates review in Q2 2022 to assess rates forecast and determine the feasibility of:
a. allocating additional funds for 2022 clean energy content procurement, b. allocating additional funds to program implementation, c. providing additional rate credits for all customer classes during peak summer months in 2022.
B. Draft VCE Carbon Neutral by 2030 report. Staff reminded the CAC that at their December meeting, highlights of the carbon neutral report were provided. The draft report presented at this meeting is the draft report and includes “sensitivities” and input from the Carbon Neutral Task Group. Staff are seeking the CAC’s comments, prior to the final draft 60 being presented to the Board at their February meeting. Comments were provided on:
building electrification and electric vehicles impacting forecasting and future load scenarios, the idea of looking at the whole system rather than specifically at procurement, ways to meet the need and how to meet the need, looking at the impacts of residential and commercial building, including rooftop solar, growth of construction impacting the need for electricity, and the need to consider reorganizing the report to make its findings and recommendations easier to identify. Staff asked that any additional comments and suggestions be sent to Staff Gordon Samuels.
California Community Power JPA (“CC Power”) long duration energy storage project:
Tumbleweed. Staff presented an overview of the Tumbleweed long duration energy storage project that CC Power is considering. After a brief discussion, the CAC recommended that VCE participate in the California Community Power (CC Power) Tumbleweed Energy Storage Project (8-0-0).
C. Update on customer program development. Staff provided an overview of various customer programs that are under development: Heat Pump Pilot Program, Electric Vehicle Rebates Pilot, AgFIT (Agricultural Flexible Irrigation Technology), and Net Energy Metering (NEM) 3.0.
D. Formation of 2022 Task Groups and consideration of Task Group “charges”. The CAC discussed the formation of task groups. Whether a Rates Task Group will be needed in 2022 was discussed and it was determined that at this point in time, there is no need for it.
Instead, when input is needed by Staff and/or the Board, an ad hoc group could be formed to address specific tasks. After a thorough discussion, three (3) task groups were formed:
Leg/Reg, Outreach, and Programs (8-0-0). The draft “charges” presented at this meeting for the Leg/Reg, Outreach and Programs Task Groups were approved (8-0-0). CAC members expressed their interests in serving on the 3 task groups. Lastly, it was agreed that there should be a discussion scheduled for the CAC’s February meeting on the best way to approach the topic of resiliency and hold off on forming a task group until discussed.
E. Reviewed and discussed draft Collections Policy. Staff introduced a draft Collections Policy and reviewed VCE’s collection approach and customer service focus. The CAC made suggestions, which will be considered by Staff for a revised draft policy. A revised draft policy will be brought to the CAC at their February meeting when Staff will seek the CAC’s recommendation to the Board to adopt the policy.
61 1
Item 10
VALLEY CLEAN ENERGY ALLIANCE
Staff Report - Item 10
TO: Board of Directors
FROM: Mitch Sears, Interim General Manager
Rebecca Boyles, Director of Customer Care and Marketing SUBJECT: SACOG Grant - Electrify Yolo Project Update
DATE: February 10, 2022
REQUESTED ACTION
Informational item. The purpose of this report is to give an update on the status of the Electrify Yolo (SACOG grant) project.
BACKGROUND
In December 2018, the Sacramento Area Council of Governments (SACOG) authorized the award of a Green Region grant in the amount of $2,912,000, representing the regional “Electrify Yolo” project, with the purpose of installing publicly accessible electric vehicle (EV) charging stations. Originally, only VCE and the City of Davis were involved, and Woodland, Winters and unincorporated Yolo County joined the project prior to submitting the grant application in August 2018. The City of Davis distributed funds to each entity once the Memoranda of Understanding (MOUs) were approved by each jurisdiction. All projects are to be finished by December 31, 2023.
UPDATE
As shown in the attached progress reports each jurisdiction is making progress toward meeting its obligations under the grant. All MOUs were signed (Davis, VCE/Winters, Woodland, unincorporated Yolo County) as of April 2021, and some EV charger installation projects have begun. Staff does note that EV charger installations have been subject to some delays, including impacts from the COVID-19 pandemic and staffing shortages. The City of Woodland is experiencing delays in project implementation due to staffing constraints and was not able to provide a written update as of the writing of this report but anticipates being able to complete the project on time.
VCE Staff is working with each jurisdiction to design banners to be hung at each charging station with logos of all project partners, as well as permanent aluminum signs. Temporary banners will inform members of the public that there will be EV chargers coming soon in that location and aim to increase the public’s brand association with VCE and electric vehicles. Banners have been hung in Winters at the Community Center charging stations, as well as a permanent aluminum sign.
62 2
Item 10
ATTACHMENTS:
1. VCE SACOG Progress Report Davis – February 2022
2. VCE SACOG Progress Report Winters - February 2022
3. VCE SACOG Progress Report Yolo - February 2022
63 VALLEY CLEAN ENERGY
SACOG GRANT
PROGRESS REPORT – CITY OF DAVIS FEBRUARY 2022
1. Project Summary
The City of Davis was apportioned $1,912,000 of the total award ($2,912,000) to perform the following:
• Site, design, permit, construct and install Level 2 Chargers in the project area (3 minimum)
• Site, design, permit, construct and install DC Fast Chargers (Level 3) in downtown area within ½ to 5 miles of major freeway corridors (2 minimum) • Purchase Mobile Chargers of the type similar to ‘EV ARC’ solar standalone charging stations (2 minimum)
• Purchase or lease electric vehicle(s) to transport 8 or more people (one minimum) In discussion of the project, the City has divided the effort into “Phase 1” - the minimum action needed to meet the requirements of the grant award, and “Phase 2” for funds that may remain after the miniumums are met, to determine locations for installations based on the siting criteria discussed and approved during “Phase 1” efforts.
2. Project Manager
Stan Gryzcko, Director, Public Works Utilities and Operations
3. Site (s) Description
At this time, locations have been discussed internally and presented to the City’s Natural Resources Commission, however locations have not been formally approved. The following have been discussed:
Location Existing Proposed
City Hall Two dumb pedestal mount
Clipper Creek
Two smart dual-port Level 2
stations and one DCFC
4 th & G Garage Two dumb pedestal mount
Clipper Creek
Two smart dual-port Level 2
stations (wall mount)
E Street Parking Lot Two dumb pedestal mount
Clipper Creek
Two smart dual-port Level 2
stations or one quad-port
station
Amtrak Two dumb pedestal mount
charging stations
One dual-port DCFC
Olive Drive Configured for a DCFC One dual-port DCFC,
potentially a high-speed
150kW charger
4. Description of any material planned changes to the Project.
N/A at this time - of note the City staffperson previously assigned to this project has left City employment and there is a recruitment underway at this time. 64 VALLEY CLEAN ENERGY
SACOG GRANT
PROGRESS REPORT – CITY OF DAVIS FEBRUARY 2022
5. Table schedule showing progress on achieving each of the Milestones See below.
6. Summary of activities during the previous calendar quarter or month.
The draft recommendations for siting the chargers and the types of chargers to install from the City’s consultant on this project was presented by staff and the consultant to the Natural Resources Commission in November 2021. The team received substantive feedback from the Commission, and are preparing responses to the questions, along with the consultant continuing to work on the lifecycle cost analysis for staff review.
7. Forecast of activities scheduled for the current calendar quarter Once the City has the lifecycle cost analysis and recommendations on the installation and management of chargers, staff will return to the Natural Resources Commission with the recommended locations & methods of installation/management, and answers to the Commission questions from November. Discussion from the NRC, along with any support or alternative suggestions then be presented to City Council to begin the implementation portion of the Phase 1 project, with an outline of the recommended process for Phase 2.
8. Written descriptions about the progress relative to Milestones, including whether the milestone has been met or is on target to meet the Milestones
For the purposes of this report, we will not include milestones, other than the first milestone of completing the feasilibity study. Once the City has made a determination on how best to move forward with installation/purchase of the required chargers/vehicle, additional milestones will be added to show progress towards those actions.
9. List of issues that are reasonably likely to affect Milestones We have run into some issues with PG&E in getting electrical connection information. We also have a shortage of staffing resources with current vacancies. Depending on the outcome of upcoming recrutiments, we may have some additional resourcing necessary to keep the project moving forward.
10. A status report of activities, including a forecast of ongoing activities, information on project performance, and projections for the next twelve (12) months.
In the next year, staff expects completion of the site location report, construction of Phase I installations, completion of Phase II siting (which is partially encompassed in the site location report for Phase I), and prep for construction of Phase II installations. 65 VALLEY CLEAN ENERGY
SACOG GRANT
PROGRESS REPORT – CITY OF DAVIS FEBRUARY 2022
11. Progress and schedule of all material agreements, contracts, permits, approvals, technical studies, financing agreements, and purchase orders showing the start dates, completion dates, and completion percentages.
For the purposes of this portion of the effort, we have a contract with our consultant to complete this Phase 1 study. There are no other responsive documents to this request at this time.
Dashboard
TABLE 1
Milestone
Description Status % Completion
Estimated
Completion
Date
Notes
Feasibility Report
and Lifecycle Cost
Analysis
Initial draft
reviewed by
Natural
Resources
Commission,
internal work
continues, City
awaiting final
report draft
80%
LINKED: Natural Resources Commission Meeting Documents
- Staff Report
- Frontier Energy Draft Report
66 318 First Street
Winters, CA 95694
Phone.530.795.4910
Fax. 530.795.4935
COU NCIL ME MBERS
Ha ro ld Anderso n
J esse Lo ren
Pierre Neu
MAYO R
Wa de Co wa n
MAYO R PR O TEM
Bill Biasi
CITY CLERK
Ashley Bussa r t
CITY TRE AS URER
Shelly Gun by
CITY M AN AGER
Ka thleen Sa lg uero Trepa
To Valley Clean Energy,
Please let this letter serve as our February 2022 progress report. The City of Winters is currently working on the project with the contractor Ample Electric. City Staff posted this project on the city website for proposals, contacted four different contractors through email and phone and had just one response which was Ample Electric. Currently the City has spent $79,500 of funds toward the project. (Invoices attached) As of today, all four chargers have been received. The City has decided to go with Blink chargers. Our project consists of two separate locations for the charging stations. One location is the Winters Community Center parking lot located at 201 Railroad Ave, Winters Ca. This location has two Level 2 double chargers replacing existing chargers. The second location is the City parking lot at the corner of First St and Abbey St. This location is a new parking lot that will have one level 2 double charger and one 50kw level 1 fast charger. The progress at this location is being delayed by a Rule 20A project in the alley next to the parking lot that will supply the power for the electricity to the car charging stations. This project is scheduled to be completed by May 2022. Once the power source has been installed with the Rule 20A project we will immediately install the chargers.
Thank you,
Eric Lucero
City of Winters
67 318 First Street
Winters, CA 95694
Phone.530.795.4910
Fax. 530.795.4935
COU NCIL ME MBERS
Ha ro ld Anderso n
J esse Lo ren
Pierre Neu
MAYO R
Wa de Co wa n
MAYO R PR O TEM
Bill Biasi
CITY CLERK
Ashley Bussa r t
CITY TRE AS URER
Shelly Gun by
CITY M AN AGER
Ka thleen Sa lg uero Trepa
1. Project Summary - Install car charging stations at Community Center and City parking lot.
2. Project Manager – Eric Lucero
3. Site (s) Description – Winter Community Center and city parking lot at First and Abbey.
4. Site information (Maps, Pictures, Etc.)
5. Description of any material planned changes to the Project. - None
6. Table schedule showing progress on achieving each of the Milestones. – See below
7. Summary of activities during the previous calendar quarter or month. - No activities this quarter
8. Forecast of activities scheduled for the current calendar quarter. - No activities planned
9. Written descriptions about the progress relative to Milestones, including whether the milestone has been met or is on target to meet the Milestones – see Attachment C
10. List of issues that are reasonably likely to affect Milestones. – PG&E Rule 20A utilitiy project
Dashboard
Site Selection Contract
Award Permits Installation Testing Go Live
Completed Completed Completed In Progress 50% 50%
TABLE 1
Milestone
Description Status % Completion
Estimated
Completion
Date
Notes
Community
Center charging
stations are
complete and in
operation
Complete 100% 9-23-2021 Chargers have
been in
operation since
September
First & Abbey
Street charging
stations are on
hold waiting for
PG&E Rule 20A
project to
underground
power.
On Hold 10% 6-21-2022 Chargers and
materials have
been purchased
68 318 First Street
Winters, CA 95694
Phone.530.795.4910
Fax. 530.795.4935
COU NCIL ME MBERS
Ha ro ld Anderso n
J esse Lo ren
Pierre Neu
MAYO R
Wa de Co wa n
MAYO R PR O TEM
Bill Biasi
CITY CLERK
Ashley Bussa r t
CITY TRE AS URER
Shelly Gun by
CITY M AN AGER
Ka thleen Sa lg uero Trepa
Overview of Charger Locations
Winters Community Center Operational Chargers
69 318 First Street
Winters, CA 95694
Phone.530.795.4910
Fax. 530.795.4935
COU NCIL ME MBERS
Ha ro ld Anderso n
J esse Lo ren
Pierre Neu
MAYO R
Wa de Co wa n
MAYO R PR O TEM
Bill Biasi
CITY CLERK
Ashley Bussa r t
CITY TRE AS URER
Shelly Gun by
CITY M AN AGER
Ka thleen Sa lg uero Trepa
Photo of 1st & Abbey Parking Lot Charger Locations
70 VALLEY CLEAN ENERGY
SACOG GRANT
PROGRESS REPORT – YOLO COUNTY FEBRUARY 2022
1. Project Summary
Install EV charging stations throught Yolo County that are accessible to the pubic
2. Project Manager
Mike Martinez, IT & Projects Manager, County Of Yolo General Services Department
3. Site (s) Description
Various County owned properties in the cities of Woodland, Davis, and Winters Site 1: 137 N Cottonwood St, Woodland, California 95695 Bauer Building 2-Dual Charging Stations
Site 2: 25 N. Cottonwood Street Woodland, CA 95695 Gonzalez Building 2-Dual Charging Stations
Site 3: 315 E 14th St, Davis, CA 95616 Mary L. Stephens Davis Branch Library 1-Dual Charging Station
4. Site information (Maps, Pictures, Etc.) Attached EV Project Location Map.PDF
5. Summary of activities during the previous calendar quarter or month.
Negoitiated and finalized procurement and contracts for installation and of EV Charging stations for 3 sites.
6. Forecast of activities scheduled for the current calendar quarter Site visits for preliminary design and drawings. Start permitting process
7. List of issues that are reasonably likely to affect Milestones Design and permitting issues may cause delays
Dashboard
Site Selection Contract
Award Permits Installation Testing Go Live
Completed Completed –
for 3 sites
IN PROGRESS
DASHBOARD KEY
Completed IN PROGRESS DELAYED ON HOLD
71 Item 11
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 11
To: Board of Directors
From: Mitch Sears, Interim General Manager
Rebecca Boyles, Director of Customer Care and Marketing Sierra Huffman, Program and Community Engagement Analyst Subject: Time-of-Use (TOU) Rate Transition Update
Date: February 10, 2022
______________________________________________________________________________
RECOMMENDATION
None requested. Informational item.
BACKGROUND
Since April of 2021, VCE’s residential customers have been transitioning from flat, tiered rates to time-of-use (TOU) rates. TOU rates are designed to better reflect the wholesale energy market and grid conditions, with elevated prices when energy is in high demand and lower prices when solar and wind energy is plentiful. TOU rates encourage customers to use energy during daylight hours or overnight, when energy is both cleaner and more abundant.
VCE’s residential TOU transition began with NEM customers in March 2021, and the remainder of eligible customers will be transitioned in April 2022. These customers have received co-branded PG&E and VCE notifications, one of which details a customer’s projected financial impact on the rate, including information on how the customer can decline the transition if they choose. As of 2/1/2022, about 12,500 customers are projected to be included in the April transition. While 44,000+ VCE customers are still on a non-TOU rate, there are factors that make them ineligible for the transition: medical baseline, <12 months of usage data, or enrollment/eligibility for CARE/FERA in a hot climate zone. Customers can decline the transition to stay on their current rate plan at any time.
Since nearly 12,500 individuals or about 20% of VCE’s residential customers will be moved to ETOU-C, VCE staff is analyzing the impacts of providing Bill Protection for newly transitioning TOU customers. PG&E is providing Bill Protection that requires that the customer stay on the TOU rate for 12 months. After 12 months on the TOU rate, customers are credited back any additional money they spent on the TOU plan compared to E1.
If implemented by VCE, Bill Protection implementation would be done by SMUD. If VCE follows PG&E’s approach to Bill Protection, SMUD would verify a VCE customers’ transition, confirm they stayed on the rate for 12 months, and calculate and apply the bill credits. 72 Item 11
2 Financial Impact: Estimates are being updated from the previous analysis (2019) and will be provided at the March Board meeting. Analyses will consider: the cost of implementing Bill Protection, benefiters/non-benefiters on the TOU rates, and potential revenue impacts of the transition.
CONCLUSION
Next steps for TOU and Bill Protection include an updated financial analysis, along with clarifying the options for Bill Protection consideration at the March Board meeting. 73 Item 12
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 12
To: Board of Directors
From: Mitch Sears, Interim General Manager
Rebecca Boyles, Director of Customer Care and Marketing Sierra Huffman, Program and Community Engagement Analyst Subject: Update on Customer Program Development: Heat Pump Pilot Program Date: February 10, 2022
______________________________________________________________________________
RECOMMENDATION
None requested. Informational item.
BACKGROUND
Mid-2021, VCE began developing a Heat Pump Pilot Program within the context of a growing trend in home electrification programs available throughout the state. The shift in focus from traditional HVAC systems to Heat Pumps, alongside the availability of generous rebates for customers, motivated VCE to explore the most appropriate role its programs could fulfill. VCE is working to create a program that complements existing rebates and incentives. From initial research and engagement, a key unfulfilled need could be providing Marketing, Education and Outreach (ME+O) to contractors, customers, and other key stakeholders such as realtors and HVAC manufacturers.
Staff believes that the emphasis on ME+O for the initial phase of this pilot is the best way to provide value while learning more about the intricacies of the heat pump landscape. After the conclusion of the initial ME+O phase, staff (with the assistance of the Programs Task Group, or PTG) will determine whether VCE can add value by designing and launching a complementary heat pump rebate pilot phase.
VCE’s heat pump pilot will focus on Dual Fuel Heat Pumps (DFHP), as they are less expensive to install, highly efficient, and lead to the near elimination of greenhouse gas emissions from furnaces. A dual-fuel system is a type of heating, ventilation and air conditioning (HVAC) system that can switch between an electric heat pump and a gas furnace to maximize comfort and energy efficiency (i.e. the gas furnace is actually more efficient at space heating than the electric heat pump in very low temperatures).
Staff found that although large rebates are available to customers for the installation of heat pumps, few contractors based in Yolo County are currently certified to provide them. VCE staff connected with Franklin Energy, the implementers of the Comfortable Home Rebates (CHR) and 74 Item 12
2 Energy Solutions, the managers of TECH Clean California (TECH), to facilitate working together to engage local contractors. This pilot could provide support to Yolo County-based contractors in becoming certified to provide rebates through both CHR and TECH. Staff could provide contractors with program application assistance, as well as provide program clarity by developing web materials, and hosting webinars/in-person meetings.
VCE’s heat pump program could engage customers by hosting webinars/in-person workshops and connecting with customers through collateral such as web materials, social media, and printed information. Webinars/in-person workshops (similar to CoolDavis’ “Make a Plan for a Clean Energy Home” workshop in which VCE participated in fall 2021) give customers the opportunity to connect with contractors and ask them questions, as well as cover topics on owning and operating a heat pump. Collateral would explain the benefits of heat pumps such as lowering gas bills, reducing greenhouse gas emissions, and improved indoor air quality. Subjects such as duct installation, building envelope, and heat pump best practices could be addressed to ensure negligible rises in a customer’s electricity bills and boost customer satisfaction.
The next steps in this pilot program’s development are to complete a Preliminary Program Design/Implementation Form and present the Form to the CAC before requesting a recommendation for adoption to VCE’s Board.
Financial Impact: Staff projects that this pilot program phase could be efficiently run with a budget of no more than $15,000. The funds would primarily go toward collateral development and printing, and potentially for consultant support to help with paperwork and application assistance.
CONCLUSION
Staff is requesting that the Board provide feedback on this informational item should they choose to.
75 Item 13
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 13
____________________________________________________________________________________ TO: Board of Directors
FROM: Gordon Samuel, Assistant General Manager & Director of Power Services SUBJECT: Carbon Neutral by 2030 (CNx2030) Draft Report
DATE: February 10, 2022
Recommendations
1. Receive and provide feedback on the Carbon Neutral by 2030 Final Report.
2. Direct staff to re-assess VCE’s policy of 80% renewable by 2030 and consider increasing this goal.
3. Direct staff to return with recommendation(s) related to the Carbon Neutral Report in Q3 2022.
Background
In October 2020, the Board approved VCE’s 2021-2023 Strategic Plan which contains goals related to VCE’s power resource portfolio as well as decarbonization. The Community Advisory Committee (CAC) formed task groups at the January 2021 meeting and approved the task group “charge” at the February meeting. The initial task group – carbon neutral and decarbonization task group – has been meeting bi-weekly since March. It became apparent very early in the meetings that addressing the carbon neutral topic (specifically Goal 2, Objective 2.5) was going to be more than enough to focus on for 2021 and decided to postpone the decarbonization work (Goal 4) until 2022.
The task group’s “charge” stated that the task group 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. In order to complete this work an outside consultant was selected from an April 30, 2021 request for proposals (RFP) seeking qualified consultants to explore the feasibility, cost and benefit of pursuing a 100% carbon free portfolio. The consultant, Energeia, was selected to perform the study. The contract with the consultant was approved by the Board on July 8, 2021. Interim updates were provided to the CAC (late August 2021) and to the Board (September 2021).
VCE Current Renewable Portfolio Trajectory
For reference, staff is including VCE’s current renewable portfolio and trajectory out to 2030 which illustrates the resources that will achieve VCE’s current goal of 80% renewable by 2030. 76 2
Figure 1 - VCE Current Renewable Portfolio Trajectory (*currently in compliance period 4 – ’21-’24) Analysis
The primary purpose of producing the CNx2030 report effort is to understand what the future resource portfolio would consist of in order to be 100% carbon neutral as well as the be 100% renewable 24x7 (that is, every hour of every day meet VCE’s demand with renewable resources). The figures below provide a potential outcome from the draft report to achieve either of these goals.
Figure 2 below show a 100% carbon neutral portfolio meeting VCE’s annual demand. That is, over the course of a year the resources generate at least an annual amount that meets or exceeds VCE’s annual demand. In this scenario the timing of the resource’s generation does not have to match the load. 77 3
Figure 2 – 100% Carbon Neutral Portfolio
Figure 3 below is an hour by hour 100% renewable portfolio for VCE. This portfolio meets or exceeds VCE’s load every hour of the year. At a minimum the resource’s generation needs to match or exceed the load.
Figure 3 – Hour by Hour 100% Renewable Portfolio
VCE has a stated goal of being 80% renewable by 2030. Either of the portfolios studied exceeds VCE’s current commitment. Resources exist that can satisfy either situation, but there is a significant cost difference between the two sample portfolios. Table 1 below outlines the incremental (additional) resources needed – resources above what VCE has contracted for or will be contracting for in the near 78 4
future to satisfy regulatory mandates from CPUC Proceeding D.21-06-035 (Mid-Term Reliability). The carbon neutral portfolio is approximately 1/3rd the cost of the hour-by-hour portfolio ($17M/yr vs $47m/yr). This would be in addition to the approximate $50-$60M/yr VCE spends on the current power portfolio.
Table 1 – MW Needed for Hour-by-Hour and Carbon Neutral Portfolios Scenarios Solar Wind Geothermal Small
Hydro
Large
Hydro
4-Hour
Battery
Energy
Storage
8-Hour
Battery
Energy
Storage
12-Hour
PES OCGT
hr x hr 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.7 112.3
Carbon
Neutral
(net) 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0
Difference 0 13.2 11.3 0 0 -57.7 57.7 10.7 112.3
Above table represents the incremental Mega Watts (MW) needed to satisfy the hour by hour (HBH) or the carbon neutral (CN) portfolios.
Sensitivity Analysis
Energeia conducted a sensitivity analysis addressing three risk factors: drought impacts, electric vehicle (EV) penetration, and building electrification (BE). The drought impacts can vary year to year but in severe drought the impact on VCE’s annual load can be nearly 10%. EV penetration and BE will be increasing and developing forecasts that accurately reflect this growth will be important in VCE’s long range load forecasts. It is not unreasonable to assume a 6% and approximately 20% increase in annual load by 2030 from EV and BE, respectively.
Discussion
At this time, staff is not recommending any policy adjustments. This information, combined with the final report, will act as a foundation that will be used for future discussions with the Board and CAC to formulate a new policy that can be presented to the Board in Q3 2022.
Attachment
1. Carbon Free Portfolio RFP
2. 100% Carbon Free Portfolio Study (Final)
79 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 1
Valley Clean Energy Alliance
604 2nd Street, Davis, California 95616
Phone: (530) 446-2750
REQUEST FOR PROPOSALS
FOR
100% CARBON FREE PORTFOLIO STUDY
PROPOSALS ARE DUE:
Friday, May 21, 2021 BY 4:00 P.M. (Pacific Daylight Time) Proposals must be e-mailed in PDF form to [email protected] Valley Clean Energy Alliance is a Joint Powers Authority consisting of the Cities of Davis, Woodland, and Winters and the County of Yolo. 80 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 2
Scope of Services
100% CARBON FREE PORTFOLIO STUDY
I. INTRODUCTION
Valley Clean Energy is seeking a qualified consultant (Contractor) to explore the feasibility, cost and benefit of pursuing a 100% carbon free portfolio. This 100% carbon free portfolio will be developed as an option to be considered as part of VCE’s Strategic Plan and in VCE’s upcoming Integrated Resource Plan (IRP). It is intended that all elements of the generation portfolio will be renewable and/or carbon free as defined below.
II. BACKGROUND
2.1 Valley Clean Energy Alliance or Valley Clean Energy (VCE), is a joint powers authority providing a state-authorized Community Choice Energy (CCE) program. Participating VCE governments include the City of Davis, the City of Woodland, the City of Winters and the unincorporated areas of Yolo County. PG&E continues to deliver the electricity procured by VCE and to perform billing, metering, and other electric distribution utility functions and services. Customers within the participating jurisdictions have the choice not to participate in the VCE program.
2.2 Since VCE started serving load in June 2018, VCE has added resources under long term contracts and is gradually building up a portfolio of short and long term assets in line with its vision and the demand of its customers. To date, VCE has relied mainly on market purchases of energy, Resource Adequacy (RA), and Renewable Energy Credits (RECs) in order to serve its electric demand and meet regulatory requirements with respect to resource adequacy and renewable energy. Starting in 2021 VCE will increasingly meet electric demand with resources under long term contracts. VCE has contracted for 50 MW of new solar resource (PV – photovoltaic) located in Kings County, CA and a 3 MW PV + 3 MW storage (BESS – battery energy storage system) project in Yolo County, CA to come online before the end of 2021. In 2022, two additional solar + storage power purchase agreements (PPAs) have been executed (90 MW PV + 75 MW BESS in San Bernardino County, CA and 20 MW PV + 6.5 MW BESS in Yolo County, CA). Finally, two other long-term RA capacity contracts have been executed - 7 MW of demand response beginning in the Summer 2021 and another 2.5 MW of stand-alone battery storage by Summer 2022.
III. DETAILED SCOPE OF WORK
The scope of work for this project includes the following:
• Develop a 100% renewable portfolio study report
o Net zero and 24x7 by 2030
• Develop a 100% carbon free portfolio study report
o Net zero and 24x7 by 2030
• Use production cost model to simulate generation of existing and future resources 81 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 3
o Develop lowest cost resource mix at different renewable/carbon free penetrations levels
• Perform risk analysis of the scenarios/contingencies
o Contractor invited to present scenarios/contingencies to consider • Provide industry trends for renewable resources, large hydro, storage, etc.
3.1 Renewable Electricity – includes “biomass, solar thermal, photovoltaic, wind, geothermal, fuel cells using renewable fuels, small hydroelectric generation of 30 megawatts or less, digester gas, municipal solid waste conversion, landfill gas, ocean wave, ocean thermal, or tidal current”, [(Public Resources Code § 25741), Renewables Portfolio Standard (RPS). (Public Utilities Code § 399.11 et seq.)] Renewable electricity is assumed to be free of GHG emissions.
3.2 Carbon Free Electricity – Any electricity that meets the definition of renewable electricity above plus other sources considered zero emission. These zero emission sources now in California include existing large hydro (greater than 30 MW) and existing nuclear.
New technologies not now included in the zero-emission category can be added in the future. Carbon Free power uses no fossil fuel generation. See https://focus.senate.ca.gov/sb100/faqs for FAQs on existing large hydro and existing nuclear and their inclusion in SB 100. The percent of the power that must meet RPS is governed by SB 100 (De Leon, 2018) and shall be equal to or greater than 60% for 2030 and beyond. By 2045 all electricity in California is to be Carbon Free.
3.3 Hour by Hour // 24/7 – The Carbon Content of the Electricity provided is analyzed on an hour by hour basis. And for our purposes is either Renewable or Carbon Free Electricity each and every hour of the day.
3.4 Carbon Neutrality – The net carbon content of the electricity is analyzed over a period of time (usually a year) and the net carbon content is zero. During this period both sources that emit carbon and those that do not can be used, but the net carbon emissions are zero.
Net zero can be achieved if zero carbon electricity is overproduced at certain times and that excess zero carbon electricity is demonstrated through available data to displace carbon emitting electricity on the grid at that time. If enough zero carbon electricity is overproduced, the net carbon emissions can be zero.
- This area purposely left blank -
82 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 4
POWER
RENEWABLE R/HBH R/CN
SOURCE
CARBON-FREE CF HBH CF/CN
HOUR BY HOUR CARBON NEUTRAL
ANAYLYSIS TIME FRAME
“R/HBH/CF/CN”: Renewable /Hour by hour/Carbon free/Carbon neutral IV. PROFESSIONAL SERVICES
The following tasks and are incorporated into the Scope of Work.
4.1 Project Tasks
Contractor shall prepare and provide the following:
4.2 Portfolio Study Reports
The Portfolio Study Report (Report) shall describe at a high level the method used to perform the work. The fundamental algorithmic assumptions and approach must however be logical, consistent and explained in narrative form. The inputs used by the Contractor should align with the inputs provided by VCE. Reports and supporting documents shall be provided in .pdf, WORD, Excel or other commonly used formats.
Potential resources that could be included in the portfolios • Solar (Front of meter, FOM/Behind the meter, BTM)
• Wind
• Hydro
• Pump Storage
83 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 5
• Geothermal
• Biomass
• Battery Storage (FOM/BTM)
• Nuclear
• Energy Efficiency
• Demand Response
• Demand Management
4.3 Scenario Scope
The Contractor must use a production cost model to simulate the generation of existing and future resources. The results for each scenario must be summarized in the Report to at least include the following: costs, generation of each resource (GWh), market purchases (GWh), demand response deployment, behind the meter deployments, nameplate capacity of new resources, battery configurations (capacity and duration), imports, amount of local generation and CO2 equivalent tons.
The Contractor shall propose and discuss with VCE any viable scenarios based on Contractor’s experience and expertise. These proposed scenario submittals will be reviewed by VCE. Each scenario shall include all costs on an annual basis for PPA energy costs, transmission or other delivery costs, fuel costs and any fixed and variable O&M. Contractor shall complete a quantitative evaluation for each scenario. Each scenario, unless otherwise noted, shall be modeled on an hourly basis. The Loss of Load Expectation (LOLE) for each scenario should not exceed one (1) day in ten (10) years.
4.4 Model VCE reference case. Align with the assumptions made for the reference case and identify any differences.
Contractor will solve for the mix of renewable or carbon free resources that results in the lowest cost plan. All loads will be served by assets procured by VCE. VCE will not rely on spot energy purchased from outside resources.
4.5 Risk Analysis
Attempting to achieve a 100% carbon free portfolio entails risks and unknowns, some of which VCE is able to anticipate, and others that may not be obvious. This section lists some of the potential risks that VCE has so far identified. The Contractor shall explain the risk and mitigation for each concern listed below.
It is also anticipated that the list below is likely incomplete, and for that reason the Contractor is expected to address and explain in the Report any additional risks and mitigations that it may be aware of or discover during the course of the study.
4.5.1 Particular attention shall be paid to the capacity and duration of output of any energy storage facilities proposed. There is some concern for instance, that solar 84 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 6
sources of supply may not be available or adequate for extended times, during some winter peak conditions. The storage must be capable of covering the deficit.
4.5.2 If large amounts of storage are necessary through the variability of renewable sources, how will it be ensured that storage can be kept sufficiently charged using only the renewables? Would access to a greater amount of renewables, either from the grid or locally connected, be required to charge the storage and maintain a 100% renewable posture? What would be the estimated cost?
For instance, if renewable resources are installed or purchased only in quantities sufficient to serve VCE’s peak load, when and how often would it be assumed those resources could be successfully diverted to keep the storage charged to acceptable levels? Would it be necessary to purchase more renewables strictly to serve storage?
4.5.3 There could be a risk in purchasing access to renewables or carbon free in quantities sufficient to ensure the ability to reliably serve load for the full 8760 hours of the year. The risk is having significant excess energy at certain times of the year or day.
What would be the best strategy for dealing with this issue? Exporting to the grid? Curtailing the renewable/carbon free energy?
The Contractor shall identify in each scenario evaluated the magnitude in MWs and the risk in annual hours of having significant excess energy.
4.5.4 How will demand response programs be deployed? What is the magnitude, duration (per day/per year), and time of day that these programs are expected to be implemented?
4.6 Discussion of possible future industry trends in renewable resources, carbon free resources and storage
Contractor shall also gather input on trends and emerging technologies that could reach maturity by 2030, and which could help in achieving the 100% renewable or carbon free goal.
The Contractor shall provide in the Report a separate discussion of what is considered to be emerging and future trends in renewable energy, carbon free energy, storage and other potential technologies that could aid in achieving a goal of 100% carbon free portfolio. The discussion should include future factors such as, but not limited to, pricing, capacity factor, efficiency, new inverter technology, operating capabilities, and whatever else the Contractor may consider to be relevant.
The Contractor shall provide in support of this discussion of future trends a survey or summary of pertinent industry sources, referenced as appropriate. 85 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 7
V. PROPOSER MINIMUM QUALIFICATIONS
The proposals submitted in response to this Request for Proposals shall be evaluated for award based on the following criteria and weighting.
Item Criteria Description Weighting
Experience and Qualifications
1. Experience of firm
2. Resumes of staff designated to support this scope
3. CCA/Public Power/Energy experience
45%
Compliance with VCE Sample Contract 10%
Price 45%
Total 100%
5.1 Proposal Submittal Requirements
1. Ten pages maximum submitted electronically. Executive Summary with brief description of company including Firm or individual name and contact information, including e‐mail and website addresses, year organized, principals with the firm, types of work performed, number of employees.
2. Resumes of key staff that would work on VCE projects.
3. Information on any previous experience or services provided, including CCA experience.
4. Other factors or special considerations you feel would influence the selection of your proposal.
5. List of references and contact information.
5.2 Miscellaneous
1. Additional Information
Scope of Services may be revised upon mutual agreement between the Contractor and VCE.
2. Ownership of Work Products
All notes, documents, and final products in all native formats (e.g., Word, Excel, PowerPoint, databases, handwritten notes) produced in the performance of this agreement shall be the property of VCE and shall not be shared with other entities without permission from VCE staff.
86 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 8
3. Request for Proposal Schedule
VCE anticipates that the process for selection of Carbon Free Portfolio Study and awarding the contract will be according to the following tentative schedule.
5.3 Schedule
Milestone Description Date
Issue RFP 4/30/2021
Return NDA 5/12/2021
Responses due 5/21/2021
Consultant selection 6/17/2021
Study work Q3 2021
Final report complete Q4 2021
5.4 Instructions to Proposers
1. Time and Manner of Submission
The Proposal shall be submitted electronically to and received by VCE's office no later than 4:00 p.m. (PDT) on Friday, May 21, 2021.
Submit to:
Gordon Samuel, Assistant General Manager
Email: [email protected]
• Each proposal shall include the full business legal name, DBA, and address and shall be signed by an authorized official of the company. The name of each person signing the proposal shall be typed or printed below the signature. • All proposals submitted become the property of VCE.
2. Explanations to Proposers
All requests, questions or other communications regarding this RFP shall be made in writing to VCE via email. Address all communications to Gordon Samuel ([email protected]). To ensure that written requests are received and answered in a timely manner, email correspondence is required.
VCE will not be bound by any oral interpretation of the Request for Proposal, which may be made by any of its representatives or employees, unless such interpretations are subsequently issued in the form of an addendum to this Request for Proposal.
3. Withdrawal or Modification of Proposals
Proposals may be modified or withdrawn only by an electronic request received by VCE prior to the Request for Proposal due date.
87 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 9
4. Revisions and Supplements
Addenda: If it becomes necessary to revise or supplement any part of this Request for Proposal an addendum will be provided.
5. Proposal Evaluation and Selection Process
The proposals submitted shall be evaluated for award based on the criteria described in the “Proposal Evaluation Criteria” section of this Request for Proposal.
VCE may request additional information from any or all Proposers after the initial evaluation of the proposals to clarify terms and conditions.
Based on VCE's review of the proposals received, a “short listed” group of Proposers may be selected. The “short listed’ firms may be required to make verbal presentations of their qualification to VCE. If a presentation is determined to be required, the presentation will be considered in the overall technical rating.
The contract will be awarded to the best-qualified Proposer, after price and other factors have been considered, provided that the proposal is reasonable and is in the best interests of VCE to accept it.
The right is reserved, as the interest of VCE may require, to reject any or all proposals and to waive any irregularity in the proposals received.
Within fourteen (14) calendar days after notice of award, the successful Proposer shall deliver to VCE the required insurance certificates as per section 3.10 of the sample contract and the signed copies of the contract. The contract forms will be forwarded to the Proposer with the award notification.
6. Duration of Contract
This contract shall be for one year, subject to approval by VCE's Board of Directors of the corresponding annual budget, unless otherwise mutually agreed upon in writing.
The Budget is subject to the approval of VCE's Board of Directors.
7. Qualifications of Proposers
VCE expressly reserves the right to reject any proposal if it determines that the business and technical organization, financial and other resources, or experience of the Proposer, compared to the work proposed justifies such rejection.
8. Proposal Preparation Costs
The costs of developing proposals are entirely the responsibility of the Proposer and shall not be charged in any manner to VCE.
88 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 10
9. Conflicts
If conflicts exist between the contract and the other elements of this Request for Proposal, the contract prevails. If conflict exists within the contract itself, the Terms and Conditions govern, followed by Scope of Services. If conflict exists between the contract and applicable Federal or State law, rule, regulation, order, or code; the law, rule, regulation, order, or code shall control. Varying levels of control between the Terms and Conditions, drawings and documents, laws, rules, regulations, orders, or codes are not deemed conflicts, and the most stringent requirement(s) shall control.
10. Manner and Time of Payment
At completion of the scope, Contractor shall submit an invoice for the lump sum of the work performed.
11. Subcontractors
The Proposers must describe in their proposals the areas that they anticipate subcontracting to specialty firms. Identify the firms and describe how Proposer will manage these subcontracts.
Contractor will pay subcontractors in a timely manner.
Nothing contained in the Contract shall create any contractual relation between any subcontractor and VCE.
12. Notice Related to Proprietary/Confidential Data
Proposers are advised that the California Public Records Act (the “Act”, Government Code §§ 6250 et seq.) provides that any person may inspect or be provided a copy of any identifiable public record or document that is not exempted from disclosure by the express provisions of the Act. Each Proposer shall clearly identify any information within its submission that it intends to ask VCE to withhold as exempt under the Act.
Any information contained in a Proposer’s submission which the Proposer believes qualifies for exemption from public disclosure as "proprietary” or “confidential” must be identified as such at the time of first submission of the Proposer’s response to this RFP.
A failure to identify information contained in a Proposer’s submission to this RFP as "proprietary” or “confidential” shall constitute a waiver of Proposer’s right to object to the release of such information upon request under the Act. VCE favors full and open disclosure of all such records. VCE will not expend public funds defending claims for access to, inspection of, or to be provided copies of any such records.
13. Contract
VCE’s standard contract is included as Attachment A - Sample Contract of this Request for Proposal. VCE may reject proposals that contain exceptions to the Terms and Conditions included in the sample contract.
89 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 11
5.5 Performance Requirements
Performance Requirements/Acceptance Criteria
a. All Milestones shall be completed in accordance with approved schedule. b. Deliverable items must be complete, legible, comprehensible, and satisfy all requirements set forth in the scope of work.
5.6 Reference Documents
VCE will provide reference documents to aid in the preparation of RFP responses after execution of the non-disclosure agreement (NDA) – a sample NDA is attached as Attachment B.
5.7 Resource and Submittal Requirements
Contractor shall provide all resources required to complete the work described herein, including but not limited to skills, services, supervision, tools, documents, information, labor, materials, equipment, computing capability, transportation, and any other necessary item or expense to fulfill the work requirements.
5.8 Project Cost
Contractor shall provide a not to exceed lump sum price. If VCE modifies the scope and additional study work needs to be performed, Contractor shall provide a change order price before initiating the work.
90 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 12
ATTACHMENT A - SAMPLE CONTRACT
A SAMPLE CONTRACT IS ATTACHED HERETO.
SAMPLE CONTRACT INTENTIONALLY REMOVED
91 VALLEY CLEAN ENERGY RFP NO. 2021CFPS
RFP 2021CFPS 13
ATTACHMENT B – SAMPLE NON-DISCLOSURE AGREEMENT
A SAMPLE NON-DISCLOSURE AGREEMENT IS ATTACHED HERETO.
SAMPLE NON-DISCLOSURE AGREEMENT INTENTIONALLY REMOVED
92 Version 1.0 Page 1 of 41 January 2022
100% Carbon Free Portfolio Study
Final Report
Prepared for Valley Clean Energy
7 February 2022
energeia-usa.com
93 Version 1.0 Page 2 of 41 January 2022
Executive Summary
In 2018, the California Governor issued Executive Order B-55-180F 1 to Achieve Carbon Neutrality, which set a zero
carbon goal by no later than 2045, and negative emissions thereafter, and the State Legislature passed Senate Bill No. 1001F
2 , requiring all electricity consumed in California to be 100% carbon neutral by 2045.
Since then, a growing number of California utilities have set more ambitious targets, including the Sacramento Municipal Utilities District (SMUD), whose Board approved2F 3 a net zero carbon generation target by 2030, and the
Los Angeles Department of Water and Power (LADWP), whose Board approved 3F 4 a net zero target by 2035.
Valley Clean Energy (VCE) is in the process of reviewing its decarbonization pathways and engaged Energeia to analyse the feasibility, costs and benefits of pursuing renewable and carbon-free portfolios on an hour-by-hour and annual carbon neutral basis by 2030 to inform its Strategic Plan and Integrated Resource Plan (IRP).
Scope and Approach
Energeia’s approach to delivering the scope of work involved the following main workstreams:
• Stakeholder Engagement – Energeia met with VCE throughout the project to discuss the scope and approach for each of the technical workstreams, our initial findings, conclusions and recommendations and to agree material for discussion with the Community Advisory Committee (CAC). • Resource Requirements – Energeia developed an estimate of the annual and hour-by-hour resource gap in 2030 based on VCE’s IRP, updated to include newly contracted resources, as well as resources required since then due to changes in regulations.
• Desktop Review of Technology Options and Costs – Energeia undertook comprehensive desktop research of technology trends to identify the most relevant zero carbon fuels, generation and storage technologies, which were vetted and validated by VCE and the CAC. • Modelling Resource Portfolios – Energeia configured its zero carbon resource portfolio optimization model with information from VCE’s IRP, the results of the technology costs research to identify least cost resource mixes capable of meeting VCE’s forecasted 2030 demand under the four scenarios. • Risk Assessment and Sensitivity Analysis – Energeia discussed and agreed key demand and supply risks associated with the four scenarios with VCE and the CAC, and then modelled their potential impact on the portfolio mix and net costs.
• Implementation Considerations and Pathways – Based on the results of the portfolio optimization modelling, including the sensitivity analysis, Energeia developed recommendations regarding key implementation considerations and practical pathways for achieving the identified optimized portfolios.
Following completion of each of the above workstreams, Energeia documented the project scope, approach, technical methodologies, results and key recommendations in this report.
VCE's Resource Requirement by Hour in 2030
Figure ES1 shows Energeia’s estimate of VCE’s average net resource requirements in 2030 by hour and month.4F
5 VCE demand is expected to be met by existing and planned contracts from 9:00 to 15:00, and additional resources are needed to address the remaining load during other hours of the day, depending on the month. 1 State of California (2018), Executive Order B-55-18 To Achieve Carbon Neutrality 2 State of California – Legislative Information (2018), Senate Bill No. 100 3 SMUD (2021), Our 2030 Clean Energy Vision
4 Mayor of LA (2021), Targets – Renewable Energy
5 Energeia modelled all hours of the year, i.e. 8,760 hours per year. Hourly average results are shown here as easier to visualize. 94 Version 1.0 Page 3 of 41 January 2022
Figure ES1 – 2030 Average Hourly Net Requirements by Month Source: VCE (2020); Note: Hour of the Day (Military Time) It is important to note that the resource gaps may be met by zero carbon fuelled generation, renewable energy generation and/or storage technologies capable of shifting VCE’s excess generation into the periods of deficit.
Future Zero Carbon Resource Options and Costs
Energeia’s comprehensive desktop research of zero carbon fuel, renewable and storage technologies identified green hydrogen and renewable natural gas5F
6 fuelled combustion, solar PV, onshore wind, geothermal, pumped hydro and lithium battery storage as the most prospective resources for 2030 portfolio construction.
Figure ES2 shows Energeia’s forecast of levelized cost of resources by type6F over time, which draws from a range of authoritative public domain sources 7F. Energeia notes that levelized costs can be misleading, as they do not reflect the shape of the renewable energy resource, nor the flexibility value of dispatchable resources.8F 7 Figure ES2 – Forecasted Levelized Cost of Energy for Resources Considered in Portfolio Construction ($/MWh) Source: NREL (2020), EIA (2021), IEA (2010); Note: OCGT = Open Cycle Gas Turbine, PES = Pumped Energy Storage, BES = Battery Energy Storage, gas turbine capacity factor of 50% assumed Whether or not a given resource forms part of a least cost portfolio of zero carbon resources in 2030 depends on the hour-by-hour resource gap, as well as the relative costs of competing resource options.
Resource Portfolio Optimization
Energeia identified four least cost portfolios to meet the forecast resource gap in 2030, which varied by carbon balancing period and resourcing constraints, per VCE’s specifications. The carbon balancing constraints were hour-by-hour (HBH) and (annual) carbon neutral (CN). The resource constraints were Carbon-Free (100% carbon free, incl. large hydro) and Renewable (excludes large hydro). 6 Energeia considered both renewable natural gas and green hydrogen as fuel for thermal generation, but research and analysis revealed green hydrogen will be the lower cost fuel by 2030.
7 Levelized storage costs are exclusive of energy costs or associated losses, which were included in the portfolio optimization modelling. -220
-176
-132
-88
-44
0 44
88 132
176
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
$0
$80
$160
$240
$320
$400
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
$/MWh
Solar PV 4-Hr BES Wind Hydro - Small OCGT
Geothermal 8-Hr BES 12-Hr PES Hydro - Large
95 Version 1.0 Page 4 of 41 January 2022
Figure ES3 shows the resulting average hourly profiles (including existing and planned resources) for the HBH and CN scenarios against VCE’s gross (Baseline) load.9F 8 The modelling shows the expected least cost approach
to meeting HBH and CN average daily demand in 2030 is primarily via solar PV and 4-hour lithium-ion storage, complemented by geothermal, wind and a wider mix of resources to meet demand before 6:00 and after 17:00.10F 9 Figure ES3 – 2030 Hour-by-Hour (left) and Carbon Neutral (right) Average Day Profiles
Source: VCE (2020), Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine The estimated incremental costs of the four portfolios are shown below on an annualized basis by cost category.
Resource costs are broken out from CAISO net costs, with HBH scenarios showing a net payment for excess resources and CN scenarios showing a net cost overall.
Table ES1 – Proposed Portfolio Total Costs ($M/Yr)
Scenarios Power Source Resources CAISO Net
HBH Carbon Free $46.5 -$3.9 $42.6
HBH Renewable $46.5 -$3.9 $42.6
CN Carbon Free $16.5 $0.5 $17.0
CN Renewable $16.5 $0.5 $17.0
Source: Energeia research and analysis; Note: RA = Resource Adequacy, AS = Ancillary Services, FRA = Flexible Resource Adequacy These results show that, given the inputs and assumptions set out above and in the report, the estimated incremental annual cost for VCE to meet demand with zero carbon resources every hour of the day is 250% greater at $42.6m than the cost of being carbon neutral on an annual basis at $17.0m.
Sensitivity and Risk Analysis
Energeia, VCE and the CAC discussed and agreed a wide range of potential risks and issues that could materially impact on VCE’s ability to achieve the target resource portfolios at the estimated net cost. These were then refined over the course of multiple discussions into seven key risks, which were then modelled.
The effects of the seven agreed sensitivities on portfolio costs are shown in Figure ES4.
Energeia’s analysis found that further constraining the HBH scenario to exclude green hydrogen powered OCGT resources, and to not rely on selling excess energy to the CAISO, increased costs by $13m per year.11F 10 8 Only two portfolio mixes are shown because large hydro was not part of the most economical resource mix for either scenario. 9 Energeia notes that other portfolios could be the same or lower cost due to the complexity of this type of portfolio analysis and the limitations of non-linear programming techniques. However, we have tested these results multiple times to help mitigate this risk. 10 These risk factors do not apply to the CN scenario.
-150
-100
-50
0 50
100
150
200
250
300
350
0 2 4 6 8 10 12 14 16 18 20 22
MWh
-150
-100
-50
0 50
100
150
200
250
300
350
0 2 4 6 8 10 12 14 16 18 20 22
MWh
96 Version 1.0 Page 5 of 41 January 2022
On the demand side, Energeia’s modelling found annual HBH costs go up the most due to Building Electrification (BE), while CN costs go up the most as a result of drought. However, each of the demand side risk factors resulted in a significant increase in annual incremental portfolio costs.
Figure ES4 – Hour-by-Hour and Carbon Neutral Net Portfolio Costs Source: Energeia modelling
Portfolio optimization is a complex interplay of resource costs and shape, and hourly net shortfalls, however, in general these results reflect the relative increase in energy under each of the analyzed demand side risk factors.
Portfolio Implementation Considerations
Based on the results of our least cost portfolio optimization analysis, including assessment of the impact of seven key risk factors, Energeia developed the following key recommendations regarding implementing the identified least cost portfolios:
• Focus on No Regrets Opportunities – Resources present in both portfolios, including wind, 4-hour and 8-hour lithium-ion storage could be purchased initially allowing VCE to head in the direction of carbon neutrality under the CN scenario, and potentially change to the HBH scenario in the future. • Consider Deferring Lithium-ion Projects – Lithium-ion battery storage systems are expected to decline significantly over the next decade. VCE should therefore consider delaying storage contracts, and/or requesting that storage embedded in future renewables projects to be built closer to 2030. • Benefit from Co-location – Regarding resource placement, co-locating batteries at solar or wind sites, if possible, may minimize revenue lost to curtailment, which is expected to increase in California over the next 10 years. Battery asset timing should therefore consider curtailment and future cost declines. • Address Key Risk Factors – Developing programs to increase the efficiency of agriculture pumping load, and to increase the flexibility of transportation and building electrification loads, could help reduce the associated impact on portfolio costs.
It is important to evaluate these recommendations over time, as key risk factors could change due to unforeseen changes in policy, regulation, technology, market and industry conditions. $43 $43
$50 $46
$56 $51 $49
$59
$17
$32
$22 $25
$0
$25
$50
$75
Base
No
Hydropower
No OCGT
No CAISO
Revenue
No OCGT,
No CAISO
Revenue
Drought
EV Uptake
BE Uptake
$M/Yr
Hour-by-Hour Carbon Neutral
97 Version 1.0 Page 6 of 41 January 2022
Table of Contents
Executive Summary ................................................................................................................................................2 Disclaimer ...............................................................................................................................................................8
1. Background.....................................................................................................................................................9
2. Scope and Approach.....................................................................................................................................10
2.1. Scope ..................................................................................................................................................10
2.2. Approach .............................................................................................................................................10
3. VCE’s Resource Requirements by Hour in 2030 ..........................................................................................12
3.1. Load Net of Behind-the-Meter Resources ...........................................................................................12
3.2. Baseline Resource Assumptions.........................................................................................................13
3.3. Hourly Resource Requirements...........................................................................................................14
4. Future Resource Costs .................................................................................................................................15
4.1. Key Future Carbon-Free and Renewable Technologies......................................................................15
4.2. Zero Carbon Fuel Price Forecasts.......................................................................................................16
5. Optimized Carbon-Free and Renewable Portfolios.......................................................................................17
5.1. Portfolio Optimization Model................................................................................................................17
5.2. Least Cost Resource Portfolios ...........................................................................................................17
5.3. Portfolio Cost by Resource Type.........................................................................................................18
5.4. Portfolio Load and Resource Profiles ..................................................................................................18
6. Risk Analysis.................................................................................................................................................21
6.1. Key Risks.............................................................................................................................................21
6.2. Portfolio Cost Impacts .........................................................................................................................24
7. Portfolio Implementation Considerations.......................................................................................................26 Appendix A – Existing Power Purchase Agreements............................................................................................27 Appendix B – Technology Findings.......................................................................................................................28 Appendix C – Detailed Portfolio Results ...............................................................................................................32 Appendix D – Additional Portfolio Views ...............................................................................................................35 Appendix E – Bibliography....................................................................................................................................37 Appendix F – About Energeia USA ......................................................................................................................38 98 Version 1.0 Page 7 of 41 January 2022
Table of Figures
Figure 1 – Portfolios Assessed in the Following Study .........................................................................................10 Figure 2 – 2020 Average Load Including DER......................................................................................................12 Figure 3 – 2030 Average Load Including DER......................................................................................................12 Figure 4 – Average Hourly Net Requirements by Month Including PPAs (2020)..................................................14 Figure 5 – Average Hourly Net Requirements by Month Including PPAs (2030)..................................................14 Figure 6 – Forecast Levelized Cost of Renewable Electricity Generation Technology .........................................15 Figure 7 – Forecast Levelized Cost of Storage Technology .................................................................................15 Figure 8 – Forecast Levelized Cost of Thermal Electricity Generation Technology Costs....................................16 Figure 9 – Forecast Renewable Fuel Prices .........................................................................................................16 Figure 10 – Schematic of Portfolio Optimization Tool ...........................................................................................17 Figure 11 – 2030 Hour-by-Hour Average Day Profile ...........................................................................................19 Figure 12 – 2030 Hour-by-Hour Peak Day Profile.................................................................................................19 Figure 13 – 2030 Carbon Neutral Average Day Profile.........................................................................................20 Figure 14 – 2030 Carbon Neutral Peak Day Profile..............................................................................................20 Figure 15 – Forecast Added Daily Average Load from Drought (2030)................................................................22 Figure 16 – Forecast Added Peak Day Load from Drought (2030).......................................................................22 Figure 17 – Forecast Added Daily Average Load from EV Adoption (2030).........................................................23 Figure 18 – Forecast Added Peak Day Load from EV Adoption (2030)................................................................23 Figure 19 – Forecast Maximum Potential Daily Average Load from Building Electrification (2030)......................24 Figure 20 – Forecast Maximum Potential Peak Day Load from Building Electrification (2030) ............................24 Figure 21 – Hour-by-Hour Portfolio Cost Impacts .................................................................................................25 Figure 22 – Carbon Neutral Portfolio Cost Impacts...............................................................................................25 Table of Tables
Table 1 – Proposed Resource Capacities (MW)...................................................................................................17 Table 2 – Proposed Resource Costs ($M/Yr) .......................................................................................................18 Table 3 – Proposed Portfolio Total Costs ($M/Yr).................................................................................................18 99 Version 1.0 Page 8 of 41 January 2022
Disclaimer
While all due care has been taken in the preparation of this report, in reaching its conclusions Energeia has relied upon information and guidance from Valley Clean Energy, and other publicly available information. To the extent these reliances have been made, Energeia does not guarantee nor warrant the accuracy of this report.
Furthermore, neither Energeia nor its Directors or employees will accept liability for any losses related to this report arising from these reliances. While this report may be made available to the public, no third party should use or rely on the report for any purpose.
For further information, please contact:
Energeia USA
132 E St. #310
Davis, CA 95616
T: (530) 312-6127
E: [email protected] W: www.energeia-usa.com
100
Version 1.0 Page 9 of 41 January 2022
1. Background
In 2018, the California Governor issued Executive Order B-55-1812F 11 to Achieve Carbon Neutrality, which set a
zero carbon goal by no later than 2045, and negative emissions thereafter, and the State Legislature passed Senate Bill No. 10013F
12, requiring all electricity consumed in California to be 100% carbon neutral by 2045.
Since then, a growing number of California utilities have set more ambitious targets, including the Sacramento Municipal Utilities District (SMUD), whose Board approved 14F 13 a net zero carbon generation target by 2030, and
the Los Angeles Department of Water and Power (LADWP), whose Board approved15F 14 a net zero target by 2035.
16FCalifornia community choice aggregators (CCAs) are increasingly setting carbon and/or renewable targets above those of state minimum levels, including San Jose Clean Energy’s goal of carbon neutrality by 2030, 17F 15 18F
Peninsula Clean Energy’s goal of 100% renewable energy on a 24/7 basis by 2025 19F 16 and finally, Marin Clean
Energy’s goal of 85% renewable by 2029.20F
17 Currently, VCE has multiple long-term contracts for solar, storage, geothermal and demand response, which are forecasted to serve approximately 35.8% of VCE’s 2030 load, leaving 528 GWh p.a. to be served by CAISO purchases. This is consistent with California state targets for CCAs.
Valley Clean Energy (VCE) is in the process of reviewing its decarbonization pathways and engaged Energeia to analyse the feasibility, costs and benefits of pursuing renewable and carbon-free portfolios on an hour-by-hour and annual carbon neutral basis by 2030 to inform its Strategic Plan and Integrated Resource Plan (IRP). 11 State of California (2018), Executive Order B-55-18 To Achieve Carbon Neutrality 12 State of California – Legislative Information (2018), Senate Bill No. 100 13 SMUD (2021), Our 2030 Clean Energy Vision
14 Mayor of LA (2021), Targets – Renewable Energy
15 City of San Jose (2021), City of San Jose to Pledge Carbon Neutrality by 2030 16 Peninsula Clean Energy (2021), Our Path to 24/7 Renewable Power by 2025 17 Marin Clean Energy (2022), MCE Operational Integrated Resource Plan 101
Version 1.0 Page 10 of 41 January 2022
2. Scope and Approach
This section summarizes Energeia’s scope of work and the approach adopted to deliver it.
2.1.Scope
Valley Clean Energy engaged Energeia to explore:
• The feasibility, costs and benefits of pursuing renewable or carbon free portfolios under two scenarios, Carbon Neutral (CN) and Hour-by-Hour (HBH), by 2030 and; • The impact of key risks forecasted to potentially drive increases in portfolio costs.
A diagram of the scenarios assessed is shown in Figure 1.
Figure 1 – Portfolios Assessed in the Following Study
Source: VCE (2021)
The HBH analysis requires VCE’s demand to be met by zero carbon generation every hour of the year, while the CN timeframe requires VCE’s annual renewable generation to equal VCE’s annual demand.
The power source analysis defines renewable electricity to include biomass, solar thermal, photovoltaic, wind, geothermal, fuel cells using renewable fuels, small hydroelectric generation (<= 30 MW), digester gas, municipal solid waste conversion, landfill gas, ocean wave, ocean thermal, or tidal current, and carbon free electricity to include any generation source that meets the definition of renewable plus other sources considered zero emission such as large hydro (> 30 MW) and existing nuclear.
Additional refinements to the scope were developed over the course of the engagement in consultation with VCE and the CAC, including the consideration of green hydrogen and renewable natural gas fuelled Combined Cycle Gas Turbines (CCGTs).
2.2.Approach
Energeia’s approach to delivering the scope of work involved the following main workstreams:
• Stakeholder Engagement – Energeia met with VCE throughout the project to discuss the scope and approach for each of the technical workstreams, our initial findings, conclusions and recommendations and to agree material for discussion with the Community Advisory Committee (CAC). • Resource Requirements – Energeia developed an estimate of the annual and hour-by-hour resource gap in 2030 based on VCE’s IRP, updated to include newly contracted resources, as well as resources required since then due to changes in regulations.
102
Version 1.0 Page 11 of 41 January 2022
• Desktop Review of Technology Options and Costs – Energeia undertook comprehensive desktop research of technology trends to identify the most relevant zero carbon fuels, generation and storage technologies, which were vetted and validated by VCE and the CAC. • Modelling Resource Portfolios – Energeia configured its zero carbon resource portfolio optimization model with information from VCE’s IRP, the results of the technology costs research to identify least cost resource mixes capable of meeting VCE’s forecasted 2030 demand under the four scenarios. • Risk Assessment and Sensitivity Analysis – Energeia discussed and agreed key demand and supply risks associated with the four scenarios with VCE and the CAC, and then modelled their potential impact on the portfolio mix and net costs.
• Implementation Considerations and Pathways – Based on the results of the portfolio optimization modelling, including the sensitivity analysis, Energeia developed recommendations regarding key implementation considerations and practical pathways for achieving the identified optimized portfolios.
Following completion of the above workstreams, Energeia documented the project scope, approach, technical methodologies, results and key recommendations in this report. 103
Version 1.0 Page 12 of 41 January 2022
3. VCE’s Resource Requirements by Hour in 2030
This section describes the development of the forecast VCE resource requirements by hour in 2030. We developed our estimates by taking VCE’s forecast loads from their latest Integrated Resource Plan (IRP), including Behind-the-Meter (BTM) resources, and updated their forecast resources by adding any new resources acquired since the IRP was issued, or planned to be required due to changes in regulations.
3.1.Load Net of Behind-the-Meter Resources
Figure 2 and Figure 3 shows daily averages by month and were generated using VCE’s forecast demand net of BTM resources. In 2020, VCE’s hourly load varies by 74 MW, with a minimum hourly load of 61 MW in November and a maximum of 135 MW in August. Additionally, a very slight 'duck curve’21F 18 can be seen peaking
around 17:00 during the most sun-intensive months, June through September.
Figure 2 – 2020 Average Load Including DER
Source: VCE (2020)
VCE’s forecast hourly demand in 2030 experiences varies by ~106 MW on average, which is 44% greater than the range in 2020. In 2030, the minimum hourly load occurs in March rather than November and is 51 MW, while the maximum hourly load remains in August and increases to 157 MW. An expected increase in BTM solar PV uptake over the next decade drives a more prominent duck curve in all months of 2030.
Figure 3 – 2030 Average Load Including DER
Source: VCE (2020)
Resource generation curves scaled to VCE’s existing PPAs were applied to the demand curves shown above to understand the shape of the outstanding load. These resource profiles were taken from VCE’s IRP assumptions. 18 The Duck Curve refers to the impact of solar PV generation on the net load shape, which increasingly looks like a duck in profile. -220
-176
-132
-88
-44
0 44
88 132
176
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
-220
-176
-132
-88
-44
0 44
88 132
176
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
104
Version 1.0 Page 13 of 41 January 2022
3.2.Baseline Resource Assumptions
The Power Purchase Agreement (PPA) values presented in Appendix A – Existing Power Purchase Agreements were provided by VCE, they include all current PPAs, as well as expected PPAs required to meet changes in regulatory requirements since the IRP was completed, including geothermal and long duration storage portfolio requirements.
VCE currently contracts a total of 401 MW of renewable generation, and its portfolio has the following resources:
• Solar PV, 235 MW
• Hydroelectric, 2.9 MW
• Geothermal, 15 MW
• Combined Heat and Power (CHP), 8 MW
• Short Duration Storage (4-hour), 123 MW
• Long Duration Storage (8-hour) 5 MW, and
• Demand Response, 7 MW.
As a result of changes in portfolio requirements regulated by the California Energy Commission (CEC), VCE is also expecting to need to contract the following additional resources by 2026:
• Long Duration Storage (8-hour) 15 MW, and
• Geothermal, 5 MW.
The above resources represent the Baseline resources assumed in place by 2030. 105
Version 1.0 Page 14 of 41 January 2022
3.3. Hourly Resource Requirements
Resource load shapes provided in VCE’s IRP were scaled to their available capacity in a given year to determine net hourly resource requirements. An annual degradation factor of 0.5%22F 19 and a system round trip efficiency of
86%2 were assumed when calculating expected battery storage output, and a solar panel annual degradation factor of 0.5%23F
20 was assumed when calculating expected solar PV output.
Figure 4 shows average net load requirements by hour and month in 2020, which is almost identical to the 2020 average load including DER as the only existing PPA in 2020 provided 2.9 MW of hydroelectric generation.
Figure 4 – Average Hourly Net Requirements by Month Including PPAs (2020) Source: VCE (2020)
VCE’s 2030 average net load requirements by hour and month are shown in Figure 5. There is a significant difference in this chart compared to 2030 as nearly all the PPAs listed in will be online in 2030. From 7:00 to 16:00, VCE is forecasted to have excess generation of 50 MWh on average, and during other hours, VCE will need to contract more resources.
Figure 5 – Average Hourly Net Requirements by Month Including PPAs (2030) Source: VCE (2020)
19 DOE (2019), Energy Storage Technology and Cost Characterization Report 20 NREL (2018), STAT FAQs Part 2: Lifetime of PV Panels -220
-176
-132
-88
-44
0 44
88 132
176
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
-220
-176
-132
-88
-44
0 44
88 132
176
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
106
Version 1.0 Page 15 of 41 January 2022
4. Future Resource Costs
Energeia conducted a comprehensive review of zero carbon fuels, renewable generation and storage technology trends to ensure the list of potential resources in VCE’s portfolios included the most prospective resources.
Appendix B – Technology Findings reports the detailed findings from our research, and the following subsections cover the present and forecasted levelized cost of energy (LCOE) values for the key technologies and fuels considered as potential resources for 2030. LCOE values are assumed to include each resource’s capital expenditure (capex), fixed operational expenditure (opex), variable opex and fuel cost, if any.
4.1.Key Future Carbon-Free and Renewable Technologies
The LOCE costs presented in Figure 6 are from NREL’s 2020 Annual Technology Baseline report. A key trend to highlight is the relatively constant costs for all technologies except for offshore wind. This reflects the trend of falling technology costs to be offset by the development of increasingly lower quality renewable resources.
Of the two solar resources presented, only solar PV was taken forward as a potential resource for VCE’s portfolios due to the relative immaturity of solar thermal. Similarly, only onshore wind was considered in portfolio development. Both small and large hydro power technologies were considered in portfolio development, and biomass was not considered due to its relatively higher cost and alternative consideration of zero carbon fuels.
Figure 6 – Forecast Levelized Cost of Renewable Electricity Generation Technology Source: NREL (2020); Note: CSP = Concentrated Solar Power, Hydro – Large is for hydropower projects > 30 MW and Hydro – Small is for hydropower projects <= 30 MW
NREL forecasted prices for storage technologies are shown in Figure 7 on a Levelized Cost of Storage (LCOS) basis, assuming lifetimes of 10 and 20 years for Li-ion energy storage and pumped energy storage, respectively.
Both long and short duration Li-ion energy storage prices are expected to fall by ~50% over the next decade before experiencing a smaller rate of decline while pumped energy storage prices are expected to remain essentially constant through 2050. Both 4-hour (short duration) and 8-hour (long duration) Li-ion battery storage and 12-hour pumped energy storage were considered as potential resources during portfolio construction.
Figure 7 – Forecast Levelized Cost of Storage Technology Source: NREL (2020), Energeia modelling; Note: Li = Lithium, PHES = Pumped Hydro Energy Storage $0
$50
$100
$150
$200
$250 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 $/MWh Solar PV Wind - Onshore Hydro - Large Geothermal
Solar Thermal (CSP) Wind - Offshore Hydro - Small Biomass $0
$30
$60
$90
$120
$150
$180
202120222023202420252026202720282029203020312032203320342035203620372038203920402041204220432044204520462047204820492050 $/MWh
Li 2 hr Li 4 hr Li 6 hr Li 8 hr Li 10 hr PHES 12 hr
107
Version 1.0 Page 16 of 41 January 2022
Energeia’s forecast LCOE values for the zero carbon thermal technologies presented in Figure 8 were developed using a bottom-up approach. Capex, opex, CCS and fuel prices for combined cycle gas turbines (CCGT) and open cycle gas turbines (OCGT) were gathered from the EIA and IEA sources. Energeia modelled green hydrogen fuel prices on a bottom-up basis using public domain sources for solar PV renewable energy projects, electrolyzer, gas storage and gas transport costs.
Energeia’s research and modelling found that LCOEs for zero carbon OCGT and CCGT configurations are expected to fall by 11.2% and 10.3%, respectively, over the 2020 to 2025 period, mainly driven by decline in green hydrogen costs. Post 2025, LCOEs are projected to change only marginally, rate of cost reduction is expected to slow significantly.
Figure 8 – Forecast Levelized Cost of Thermal Electricity Generation Technology Costs Source: EIA (2021), IEA (2010), Energeia modelling; Note: CCGT = Continuous Cycle Gas Turbine, OCGT = Open Cycle Gas Turbine, CCS = Carbon Capture and Sequestration
Despite having a forecast higher LCOE in 2030, Energeia only included OCGT technology as a potential technology during portfolio construction because combined cycle plants are unlikely to be able to achieve the dispatch levels required to make them economic due to the zero marginal cost of renewable generation. This decision was vetted with VCE and the CAC.
4.2.Zero Carbon Fuel Price Forecasts
Both renewable natural gas (RNG) and green hydrogen were considered as zero carbon fuels for the above thermal electricity generation technology. RNG prices were gathered from the public domain, and Energeia’s method for modelling green hydrogen prices was summarised in the preceding section. Green hydrogen was selected because it is forecasted to be the more economical option after 2031, as shown in Figure 9.
Figure 9 – Forecast Renewable Fuel Prices
Source: ICF (2019), Energeia modelling; Note: RNG = Renewable Natural Gas It is important to note that the above prices are exclusive of any government incentives. $0
$50
$100
$150
$200
$250
$300
$350
$400
202120222023202420252026202720282029203020312032203320342035203620372038203920402041204220432044204520462047204820492050 $/MWh
CCGT - CCS CCGT - Green Hydrogen OCGT - Green Hydrogen
$0
$16
$32
$48
$64
$80
$96
$112
$128
2022202320242025202620272028202920302031203220332034203520362037203820392040 $/MWh
RNG Green Hydrogen
108
Version 1.0 Page 17 of 41 January 2022
5. Optimized Carbon-Free and Renewable Portfolios
This section discusses the portfolio optimization methodology Energeia used along with optimized portfolio results, including resource mix, costs, revenues and net costs.
5.1.Portfolio Optimization Model
A diagram of the portfolio optimization tool used to determine least cost resource portfolios is shown in Figure 10.
Energeia configured the tool by loading in VCE’s 2030 hourly demand profiles, 2030 baseline capacity by resource type, 2030 costs by potential resource type, hourly (i.e. ‘8760’) profiles by resource type. The tool was then parameterized for each portfolio scenario, including sensitivity scenarios, and a least cost portfolio mix was identified using a non-linear solver, which ensured the solution met all conditions, including resource adequacy.
Figure 10 – Schematic of Portfolio Optimization Tool
Source: Energeia
The final step was to generate the incremental resource capacities (MWs) by resource type, incremental resource costs by resource type and total 8,760 electricity profiles by resource.
5.2.Least Cost Resource Portfolios
Table 1 shows the results of Energeia’s modelling of least cost incremental resource mixes for VCE in 2030 by scenario.
Under both the HBH and CN scenarios, there is no variation between the carbon free and renewable resource mixes as large hydropower (> 30 MW) generation is not included in the least cost solution for either portfolio.
Additionally, neither portfolios include additional solar generation, which is not unexpected due to the relatively poor alignment of solar PV generation with forecast resource requirements.
Table 1 – Proposed Resource Capacities (MW)
Scenarios Power
Source Solar Wind Geothermal
Small
Hydro
Large
Hydro
4-Hr
BES
8-Hr
BES
12-Hr
PES OCGT
HBH Carbon Free 0 39.3 11.3 0 0 42.3 65.4 10.7 112.3
HBH Renewable 0 39.3 11.3 0 0 42.3 65.4 10.7 112.3
CN Carbon Free 0 26.1 0 0 0 100.0 7.7 0 0
CN Renewable 0 26.1 0 0 0 100.0 7.7 0 0
Source: Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine
The least cost resource mix for the HBH scenario features wind, geothermal, 4-hour BES, 8-hour BES, 12-Hr PES and green hydrogen fuelled OCGT generation. It should be noted OCGT generation is only used in the HBH 8,760 Load Profiles
Incremental Resource Costs
Unitized 8,760 Profiles by
Resource Category
Non-Linear
Solver
Load-Side Risk Impacts Scenario Parameters MWs by Resource and Cost Category
Capex and Opex by
Resource, Cost and Revenue
Category
Baseline Resource Portfolio 8,760 Profiles by Resource
= Scenario Parameters
= Outputs
= All Scenario Inputs
= Sensitivity Inputs
= Solver
Legend
109
Version 1.0 Page 18 of 41 January 2022
scenario to ensure all demand is met on an hourly basis. The modelling shows it is cheaper in this capacity than oversizing renewable energy capacity or investing in additional storage resources.
The least cost CN resource mix is much simpler in composition with only three incremental resource types required: wind, 4-hr BES and 8-hr BES, with 4-hour BES making up almost all of the storage resource. This is also unsurprising given the annual carbon balancing requirement is much less restrictive than the HBH scenario.
5.3.Portfolio Cost by Resource Type
Total estimated annual resource costs by resource category in 2030 are shown in Table 2.
Annual cost calculations used an assumed Weighted Average Cost of Capital (WACC) of 6% and the lifetime of all resources was assumed to be 20 years except for BES resources, which were assumed to have a 10-year lifetime. 8-hr and 4-hr BES resources are the highest cost across both HBH and CN portfolios, which is a reflection of their relative size in MW terms.
Ultimately, Energeia’s modelling shows that meeting every hour of demand with renewable generation in 2030 is expected to cost nearly three times more in resources alone than being carbon neutral on an annual basis for VCE. However, it is important to note that costs could turn out to be significantly different to expectations.
Table 2 – Proposed Resource Costs ($M/Yr)
Scena
rios Power Source Solar Wind Geo
thermal
Small
Hydro
Large
Hydro
4-Hr
BES
8-Hr
BES
12-Hr
PES OCGT Total $M/Yr
HBH Carbon Free $0.00 $3.30 $7.30 $0.00 $0.00 $5.30 $14.40 $3.30 $12.90 $46.50 HBH Renewable $0.00 $3.30 $7.30 $0.00 $0.00 $5.30 $14.40 $3.30 $12.90 $46.50 CN Carbon Free $0.00 $2.20 $0.00 $0.00 $0.00 $12.70 $1.70 $0.00 $0.00 $16.50 CN Renewable $0.00 $2.20 $0.00 $0.00 $0.00 $12.70 $1.70 $0.00 $0.00 $16.50 Source: Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine
Net portfolio costs, which include resource cost, resource adequacy (RA), ancillary services (AS), flexible resource adequacy (FRA) and CAISO imports/exports are shown in Table 3.
Energeia’s portfolio optimization modelling assumed an RA requirement of 115% of peak, an AS requirement of 105% of peak24F
21 and an FRA requirement25F22 of 100% of nameplate solar PV generation.
Under all scenarios, no additional RA, AS, or FRA costs were as incurred, as requirements were able to be met by the portfolio itself. Regarding CAISO import/export costs, the HBH portfolio exported $3.9m of energy, while the CN portfolio incurred $0.5m of net imports, suggesting CAISO energy purchases almost exactly balance energy exports.
Portfolio net costs were $42.6m and $17.0m for the HBH and CN portfolios, respectively.
Table 3 – Proposed Portfolio Total Costs ($M/Yr)
Scenarios Power Source Resources RA/AS/FRA CAISO Net
HBH Carbon Free $46.50 $0.00 ($3.90) $42.60
HBH Renewable $46.50 $0.00 ($3.90) $42.60
CN Carbon Free $16.50 $0.00 $0.50 $17.00
CN Renewable $16.50 $0.00 $0.50 $17.00
Source: Energeia research and analysis; Note: RA = Resource Adequacy, AS = Ancillary Services, FRA = Flexible Resource Adequacy
5.4.Portfolio Load and Resource Profiles
The following subsection visualize the daily average and peak day (August) hourly load, generation and net load of the proposed HBH and CN portfolios. The graphics include the baseline as well as incremental resources. 21 This represents a maximum level of regulating capacity, actual AS requirements are likely to be lower throughout the year. 22 Energeia is anticipating solar PV to drive flexible RA requirements in 2030 based on similar work we have done. 110
Version 1.0 Page 19 of 41 January 2022
5.4.1. Hour-by-Hour Scenario
The 2030 HBH average day profile shown in Figure 11 shows solar PV generation meets all customer demand from 7:00 to 16:00. In the morning before 7:00, all portfolio resources including storage are used to meet demand with very little OCGT generation, while the evening load is met primarily with 4-hr BES.
The negative Net Load from 9:00 to 17:00, mainly driven by excess solar generation, suggests the average 2030 day has ~45 MWh to export to CAISO. This reflects oversizing of renewable generation resources in order to be able meet demand each hour of the year using zero carbon resources at least cost.
Figure 11 – 2030 Hour-by-Hour Average Day Profile
Source: VCE (2020), Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine Figure 12 shows the HBH peak day profile, and the key item to note here is net load during every hour is zero due to the assets being sized to meet the peak day. Demand is met primarily with a much smaller range of resources compared to the average day. Only 3.0% of daily average load is met using OCGT generation whereas 21.2% of the peak day base load is met by OCGT generation.
Figure 12 – 2030 Hour-by-Hour Peak Day Profile
Source: VCE (2020), Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine It is worth noting that there is less 8-hour and 12-hour generation during the peak day than on the average day due to the lack of excess solar PV during the days surrounding the peak day.
5.4.2. Carbon Neutral Scenario
The 2030 CN average day profile, displayed in Figure 13, shows the main resources used to meet demand are solar and 4-hr BES, with solar PV meeting 66.8% and 4-hr BES meeting 23.4% of load on average, respectively.
Under the CN scenario, there is no requirement to meet demand with zero carbon generation every hour, and on average VCE will be procuring CAISO resources during the 9pm to 6am period, which can be seen in the gap between the solid baseline load and resource stack. On average, 305 MWh of electricity will need to be procured, amounting to 11.5% of average energy consumption. -150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
-150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
111
Version 1.0 Page 20 of 41 January 2022
Figure 13 – 2030 Carbon Neutral Average Day Profile
Source: VCE (2020), Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine The CN portfolio’s peak day profile is also dominated by solar and 4-hr BES as shown in Figure 14. However, the resource gap is significantly higher, with 1.1 GWh or approximately 30.1% of load needing to be procured from CAISO on the peak day.
Figure 14 – 2030 Carbon Neutral Peak Day Profile
Source: VCE (2020), Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine The above analysis highlights the large role that CAISO will need to play under the CN scenarios. If other utilities are also planning on meeting their zero carbon targets using CAISO resources, it is likely to impact on the cost of resources, which was out of scope for this study. CAISO resource costs are therefore potentially higher than estimated in this study as a result – depending on the level of CAISO reliance by other jurisdictions in 2030. -150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
-150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
112
Version 1.0 Page 21 of 41 January 2022
6. Risk Analysis
The following section discusses the key risks Energeia assessed as part of this study and estimated their impacts on portfolio net cost. Supply risks included excluding hydropower and green hydrogen availability, and CAISO revenue. Demand side risks included drought and higher than expected EV and BE uptake rates.
6.1.Key Risks
Energeia identified a range of potential risks to the cost and feasibility of the identified least cost resource portfolios, which we then vetted with VCE and the CAC, who also added to the list. A final list of seven key risks were agreed to be taken forward for quantitative analysis based on their expected materiality.
6.1.1. Green Hydrogen Powered OCGTs are Unavailable or Higher Cost This risk assessment evaluated the HBH portfolio excluding OCGT fuelled by green hydrogen as the technology is still in development stages with Siemens 26F
23 and GE27F24 aiming to run their gas turbines on 100% hydrogen by 2030. Thus, there is a possibility this technology may not be available for VCE to incorporate in its 2030 resource portfolios. There is also a risk that the forecast cost of green hydrogen does not decline as anticipated.
6.1.2. CAISO Prices Are Higher and/or Lower than Expected Both HBH and CN portfolios were assessed assuming that excess generation could not be sold in the CAISO wholesale market. This risk was evaluated due to the potential impact of other Community Choice Aggregators (CCAs), Publiclly Owned Utilities (PONs) and Investor Owned Utilities (IOUs) also trying to sell their excess renewable electricity and buy shortfalls from the market, which is likely to reduce the value of the former and increase the cost of the latter. There is also the risk that VCE stakeholders will require more self-reliance.
6.1.3. Drought Conditions Increase in Frequency and Magnitude Two potential effects of drought on VCE’s portfolio cost and feasibility were raised:
• Limited availability to hydroelectric power generation, and • increased agriculture load due to pumping ground water to meet irrigation needs.
As Table 2 showed, hydropower is not part of a least cost portfolio under any scenario, and the proposed resource mixes will therefore not be affected by limited availability of hydropower during a drought.
The effect of drought on agriculture load was evaluated using VCE’s hourly (8,760) agriculture loads from 2019, 2020 and 2030, where 2019 was used as the baseline year and 2020 was used as the drought year. Energeia developed a forecast 2030 under drought conditions by first calculating growth factors at the hourly level equal to 2020 load / 2019 load, then multiplying the hourly growth factors by VCE’s forecasted hourly 2030 load in its IRP.
The total additional annual load amounts to 57.4 GWh.
Figure 15 shows, on average, the daily added load from drought would only make up 5.4% of total load or 157 kWh, while Figure 16 shows the additional load would have a very significant impact on the peak day, constituting 58.1% of total load or 3.09 MWh – more than doubling consumption. Additionally, the peak day with added drought load is in May and driven by the high volumes of water required for crop irrigation in the Spring. 23 Siemens (2021), Zero Emission Hydrogen Turbine Center 24 General Electric (2020), The Power Couple: Renewable + Gas Can Drive Decarbonization with Greater Speed 113
Version 1.0 Page 22 of 41 January 2022
Figure 15 – Forecast Added Daily Average Load from Drought (2030) Source: SMUD (2021), Energeia modelling; Note: Agr = Agriculture Figure 16 – Forecast Added Peak Day Load from Drought (2030) Source: SMUD (2021), Energeia modelling; Note: Agr = Agriculture
6.1.4. Higher than Expected Electric Vehicle Uptake
Energeia modelled EV uptake in VCE’s service area by configuring its EV uptake model using public domain inputs such as vehicle miles travelled, EV fuel efficiency, EV model availability, current vehicle stock, fuel prices and vehicle tech prices.
Energeia’s EV uptake modelling forecast EV stock in 2030 to be 15,423. Assuming an average annual consumption of 2.5 MWh p.a. for passenger and light duty vehicles, Energeia estimate total additional annual load from EVs to be 38.5 GWh in 2030, which was scaled on an hourly basis using the IRP EV load shape.
The resulting average day and peak day load profiles are shown in Figure 17 and Figure 18, respectively. EV loads are not forecasted to change significantly between VCE’s peak and average day, as EV load sums to 392 MWh during the peak day and 405 MWh on an average day. Relative to total load, peak day EV load is 9.8% and average day EV load is 13.4% of total energy consumed.
It is worth noting that EV load is not forecast to impact on the timing of the peak day, which remains in August. 0 50
100
150
200
250
300
350
400
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Remaining Load Agr Load
0 50
100
150
200
250
300
350
400
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Remaining Load Agr Load
114
Version 1.0 Page 23 of 41 January 2022
Figure 17 – Forecast Added Daily Average Load from EV Adoption (2030) Source: VCE (2020), Energeia research and modelling
Figure 18 – Forecast Added Peak Day Load from EV Adoption (2030) Source: VCE (2020), Energeia research and modelling
6.1.5. Higher than Expected Building Electrification Uptake As all-electric construction becomes common and the potential for a ban on new gas appliances increases, VCE’s building electrification uptake is predicted to increase significantly and impact 2030 demand forecasts.
Currently, SMUD expect 80% of buildings in its service territory to be all-electric by 2040 and 33 municipalities in California including Davis have introduced building codes requiring or encouraging all-electric construction.28F 25 Energeia estimated the potential BE impact on load in 2030 by configuring our building electrification model, which models the impact of space heating, water heating and cooking end uses in residential and non-residential buildings. Appliance lifetimes, energy efficiency and hourly (8760) consumption values used in the analysis reflect the latest available figures in the public domain. Gas appliance market shares were calculated using the updated 2019 Residential Appliance Saturation Study and census data and appliance load shapes are based on US DOE load shape estimates for Sacramento under the 2010 Building Technologies Program.
Energeia’s modelling assumed 100% of new customers and end of life replacements to be electric from 2023 onwards. This assumption reflects a scenario whereby new gas appliances are banned from 2023, even on a replacement basis. It is therefore a conservative estimate of the potential impact of building electrification, actual impacts on cost are likely to be lower, and should be assessed in more detail in future work.
Average daily and peak day building electrification load profiles are show in Figure 19 and Figure 20, respectively.
On average, up to 474.3 MW of demand could added from BE by 2030, which is 15.4% of the total load. During the 2030 peak day, up to 2.7 GWh of additional demand could added from BE, which is 51.9% of the total load. 25 Green Tech Media (2020), This California Utility Is Now Measuring Building Electrification in “Avoided Carbon” 0 50
100
150
200
250
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Remaining Load EV Load
0 50
100
150
200
250
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Remaining Load EV Load
115
Version 1.0 Page 24 of 41 January 2022
Throughout the entire year, up to 173.1 GWh could be added from BE, with the largest contributions coming from residential and small business space heating.
Figure 19 – Forecast Maximum Potential Daily Average Load from Building Electrification (2030) Source: US DOE - Open EI (2010), Energeia research and modelling; Note: SFD = Single Family Dwelling, MFD = Multi Family Dwelling, SME = Small and Medium Enterprises, C&I = Commercial and Industrial, SH = Space Heating, WH = Water Heating Figure 20 – Forecast Maximum Potential Peak Day Load from Building Electrification (2030) Source: US DOE - Open EI (2010), Energeia research and modelling; Note: SFD = Single Family Dwelling, MFD = Multi Family Dwelling, SME = Small and Medium Enterprises, C&I = Commercial and Industrial, SH = Space Heating, WH = Water Heating Finally, high levels of BE load on the peak day would significantly change the shape of the curve, giving it a double peak and shifting the annual peak from August in summer to December in winter.
6.2.Portfolio Cost Impacts
The results of Energeia’s modelling of the net portfolio cost of each risk adjusted HBH and CN portfolio are shown Figure 21 and Figure 22, respectively. Detailed views of the associated resource mixes and total costs by portfolio are reported in Appendix C – Detailed Portfolio Results.
Energeia’s modelling of key risks found that each risk factor increased annual costs, however the impact depended on the portfolio scenario.
Excluding hydropower from the HBH scenario did not impact costs because the least cost portfolio does not include hydropower. Removing the green hydrogen powered OCGT, on the other hand, increased HBH costs by $7.2m p.a. or 17.0% over the least cost portfolio. Removing CAISO revenue increased costs by $3.9m, or 9.2%.
Excluding both CAISO revenue and OCGT generation increased costs by $13m, which is 30.6% higher, but lower than the sum of each risk individually. In terms of demand side risks, drought increased annual costs by $8.1m or 19%, higher EV uptake increased costs by $6.5m or 15% and, finally, higher BE uptake increased costs by $16.4m or 38.4%.
Portfolio optimization of the range of resources considered as part of this study is complex, and it is therefore difficult to pick apart how each demand side risk factor is driving portfolio costs. However, the main driver of HBH cost differentials across demand side risk factors appears to be total annual energy impacts. Changes in system peak demand, or the hourly shape of the impact, appear to exert a lesser impact on portfolios costs. 0 50
100
150
200
250
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh Remaining Load SFD-WH SFD-SH MFD-WH MFD-SH SME-WH SME-SH C&I-WH C&I-SH 0 50
100
150
200
250
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh Remaining Load SFD-WH SFD-SH MFD-WH MFD-SH SME-WH SME-SH C&I-WH C&I-SH 116
Version 1.0 Page 25 of 41 January 2022
Figure 21 – Hour-by-Hour Portfolio Cost Impacts
Source: Energeia modelling
The impact of supply side risk factors on CN portfolio costs is nil as the least cost CN portfolio does not include hydropower or OCGT generation. CAISO revenue was not assessed as a risk factor as it was considered a core element of this scenario. Energeia recommends that the risk of CAISO costs being significant different to today’s levels be explored in a future piece of work, as we consider it to be potentially material.
Regarding the impact of demand side risks, they range from 32% to 86% higher than the least cost portfolio. The drought-impacted portfolio is the highest cost impact at $14.6 or 86% higher, followed by the BE-impacted portfolio at $8.3m or 49% higher cost. The EV-impacted portfolio was the lowest cost impact at $5.5m or 32% higher than the least cost portfolio.
The impact of risk factors on CN portfolio costs are higher in percentage terms than the impact of risk factors on HBH portfolio costs due to the use of latter’s use of excess generation. The CN portfolios also appear to be more sensitive to the impacts of the risk factor on the shape of demand, as drought increases costs more than BE uptake, despite the latter risk factors larger impact on annual energy consumption.
Figure 22 – Carbon Neutral Portfolio Cost Impacts
Source: Energeia modelling
$42.6 $42.6
$49.8 $46.5
$55.6 $50.7 $49.1
$59.0
$0
$15
$30
$45
$60
$75
Base
No Hydropower
No OCGT
No CAISO
Revenue
No OCGT,
No CAISO
Revenue
Drought
EV Uptake
BE Uptake
$M/Yr
Series1
$17.0
$31.6
$22.5 $25.3
$0
$15
$30
$45
$60
$75
Base
No Hydropower
No OCGT
No CAISO
Revenue
No OCGT,
No CAISO
Revenue
Drought
EV Uptake
BE Uptake
$M/Yr
Series1
117
Version 1.0 Page 26 of 41 January 2022
7. Portfolio Implementation Considerations
Based on the results of our least cost portfolio optimization analysis, including assessment of the impact of seven key risk factors, Energeia developed the following key recommendations regarding implementing the identified least cost portfolios:
• Focus on no regrets opportunities – Resources present in both portfolios, including wind, 4-hour and 8-hour lithium-ion storage could be purchased initially allowing VCE to head in the direction of carbon neutrality under the CN scenario, and potentially change to the HBH scenario in the future. • Consider deferring lithium-ion projects – Lithium-ion battery storage system costs are expected to decline significantly over the next decade. VCE should therefore consider delaying storage contracts, and/or requesting that storage embedded in future renewables projects to be built closer to 2030. • Benefit from co-location – Regarding resource placement, co-locating batteries at solar or wind sites, if possible, may minimize revenue lost to curtailment, which is expected to increase in California over the next 10 years. Battery asset timing should therefore consider curtailment and future cost declines. • Address key risk factors – Developing risk mitigation programs to increase the efficiency of agriculture pumping load, and to increase the flexibility of transportation and building electrification loads, could help reduce the associated impact on portfolio costs.
It is important to evaluate these recommendations over time, as key risk factors could change due to unforeseen changes in policy, regulation, technology, market and industry conditions. 118
Version 1.0 Page 27 of 41 January 2022
Appendix A – Existing Power Purchase Agreements
Table A1 lists VCEs current and planned resource contracts.
Table A1 – Valley Clean Energy’s Current and Planned Resource Contracts Name of Counter
Party Project Name Project Technology
Hydro
(MW)
Solar
(MW)
Storage
(MW) DR (MW)
Geo-thermal
(MW)
VCE
Allocation
Project
Start Year
Project
Start
Month
PPA Term
(Years)
California Joint
Powers Authority
Indian Valley
Short Term PPA
Hydroelectric
Generation 2.9 0 0 0 0 100% 2020 May 5
Aquamarine
Westside LLC PPA AC Solar PV 0 50 0 0 0 100% 2021 Oct 15 Putah Creek
Solar Farms LLC Renewable PPA AC Solar PV 0 3 3 (4-hrs) 0 0 100% 2022(?) Jan 20 VESI 10 LLC Tierra Buena
Energy Storage
Lithium (RAR
Attributes) 0 0 2.5 (4-hrs) 0 0 100% 2022 June 10
Leapfrog Power
Inc.
Resource
Adequacy
Agreement
Demand
Response (RAR
Attributes)
0 0 0 7 0 100% 2021 June 10
Gibson
Renewables LLC Renewable PPA Solar PV, Lithium Battery Storage 0 20 6.5 (4-hrs) 0 0 100% 2023 Oct 20 Resurgence Solar
I, LLC Renewable PPA
Solar PV AC
Coupled w/ Li-Ion
Storage
0 90 75 (4-hrs) 0 0 100% 2023 Jan 20
Willow Springs
Solar 3 LLC
Willow Springs
Solar 3 Solar + Storage 0 72 36 (4-hrs) 0 0 100% 2024 Jan 15 TBA TBA Geothermal 0 0 0 0 15 100% 2026 TBA 20
TBA TBA Long-Duration
Storage 0 5 (8-hrs) 0 0 100% 2026 TBA 15
Source: VCE (2021)
119
Version 1.0 Page 28 of 41 January 2022
Appendix B – Technology Findings
The following tables (Table B1 and B2) summarize findings from Energeia’s comprehensive desktop research of zero carbon energy generation and storage technologies.
Each table provides descriptions, advantages, disadvantages, availability and potential breakthroughs by technology. Capacity factors are reported for generation technologies, and roundtrip losses are reported for storage technologies.
Table B1 – Key Future Zero Carbon Generation Technologies Name Category Capacity
Factor Description Advantages Disadvantages Availability Potential Breakthroughs Onshore Wind Wind 51%
A windmill is used to
turn a turbine to
generate electricity on
land
• Mature technology
• Relatively low $/kWh
capex
• Relatively constant
generation
• Community resistance
• Limited resource
availability
• Commercially available
• Limited to areas of
high wind resource
• Larger turbines
increasing efficiency and
reducing costs
Offshore Wind Wind 40-50%
Floating windmills are
used to generate
electricity in the ocean
• Mature technology
• Relatively low $/kWh
capex
• Relatively constant
generation
• Community resistance
• Limited resource
availability
• Commercially available
• Limited to areas of
high wind resource
• Limited to coast areas
• Larger turbines
increasing efficiency and
reducing costs
Single Axis
Solar PV Solar 30-35%
Photovoltaic (PV) panels
on a single axis tracking
system are used to
generate electricity
• Mature technology
• Relatively low $/kWh
capex
• Strongly seasonal
• Limited resource
availability
• Commercially available
• Limited to areas of
high solar resource
• Solar technology
increasing efficiency and
lowering costs
Concentrated
Solar Power
(CSP)
Solar
25% or
40% when
paired with
storage
Mirrors are used to
concentrate solar
energy on a working
fluid, which is used to
transfer heat to a steam
turbine
• Includes storage
• Firm capacity
• Relatively low $/kWh
• Strongly seasonal
• Limited resource
availability
• Relatively immature
• Commercially available
• Limited to areas of
high solar resource
• Pilot scale
• High temp steam
turbines can reduce
costs
Geothermal Geothermal 72%
Underground
geothermal energy is
used to drive a steam
turbine
• Relatively high
capacity factor
• Firm capacity
• Mature technology
• Limited resource
availability
• Relatively high $/kWh
capex
• Commercially available
• Limited to areas of
high geothermal
resource
Ocean Tidal Tidal 20-35%
Tidal energy is used to
drive an electric
generator
• Predictable resource
• Complementary
generation profile
• Requires tidal estuary
• Relatively expensive
per kWh
• Immature technology
• Commercially available
• Limited to coastal
areas
• Limited to tidal areas
120
Version 1.0 Page 29 of 41 January 2022
Ocean Wave Wave 25-32%
Wave energy is used to
drive an electric
generator
• Predictable resource
• Complementary
generation profile
• Requires coast access
• Relatively expensive
per kWh
• Immature technology
• Commercially available
• Limited to coastal
areas
Run-of-River
Hydro Hydropower 40-80%
Water flow is used to
drive an electric
generator
• Relatively low $/kWh
capex
• Firm capacity
• Community resistence
• Subject to rainfall
• Commercially available
• Limited to areas of
high hydro potential
Reservoir
Hydro Hydropower 35-43%
Water is stored in dams
and then released to
drive an electric
generator
• Relatively low $/kWh
capex
• Includes storage
• Firm capacity
• Community resistance
• Subject to rainfall
• Subject to other uses,
e.g. fish
• Commercially available
• Limited to areas of
high hydro potential
Waste-to-Energy Waste 70%
Methane is captured
from waste and used to
drive a combustion
turbine
• Relatively low $/kWh
cost
• Methane reduction
boost
• Firm capacity
• Local emissions from
combustion
• Commercially available
• Limited to areas with
significant waste
streams
Biomass Biomass 50-60%
Methane is captured
from biomass or
biomass is burned
directly to drive a
combustion turbine
• Firm capacity • Local emissions from
combustion
• Commercially available
• Limited to areas with
significant biomass
streams
• Improvements in bio-digester technology
increases efficiency and
reduces cost
Source: Energeia research
121
Version 1.0 Page 30 of 41 January 2022
Table B2 – Key Future Storage Technologies
Name Category Roundtrip
Losses Description Advantages Disadvantages Availability Potential Breakthroughs Capacitors Seconds 5%
Capacitors used to
rapidly charge and
discharge small
amounts of electricity
directly
• Fastest response of
any technology
• Mature technology
• Relatively expensive
per kWh
• Unable to store
significant energy
• 10-20% losses per day
• Widely available
Flywheels Seconds 5%-50%
Uses a flywheel to
rapidly charge and
discharge relatively
small amounts of
electricity using an
electric generator
• Relative fast response
times
• Mature technology
• Relatively large
footprint
• Relatively expensive
per kWh
• 20-50% losses over 2
hours
• Widely available
Battery Hours 10%
Electrochemical
reactions are used to
store and discharge
electricity directly
• Relatively responsive
• Relatively low losses
• Mature technology
• Relatively high cost per
kWh
• Thermal runaway
• Widely available
• Metal air and liquid
metal formulations may
improve cost
effectiveness
Flow Hours 40%
Stores electricity in two
chemicals, which can be
stored indefinitely
• No standing losses if
turned off
• Relatively safe
• Unproven technology
• High parasitic losses
while on
• Relatively high $/kWh
• Commercially available
• Pilot scale
CSP Hours 1%
Stores energy as heat in
working fluid, which is
then used to drive a
heat recovery-based
steam generator
• Very low round trip
losses
• Can be coupled with
CSP
• Relatively low $/kWh
capex
• Unproven technology
• Safety of high
operating temp
• Commercially available
• Pilot scale
• High temp steam
turbine technology could
increase efficiency,
lower $/kWh
Hydrogen-Compression Hours 53%
Uses steel or carbon
fiber based receiving
vessels to store
relatively small amounts
of hydrogen
• Mature technology
• Relatively compact
footprint
• Relatively low $/kWh
capex
• Amount of space
required
• High round trip losses
• Widely available
• Material science could
reduce cost
Hydrogen-Salt
Cavern Weeks 42-55%
Uses air compressors to
store large amounts of
hydrogen in salt caverns
• Relatively low cost per
kWh
• Mature technology
• Requires access to a
salt cavern
• High losses
• Relatively slow
response
• Limited availability of
salt caverns
122
Version 1.0 Page 31 of 41 January 2022
Compressed
Air Energy
Storage
(CAES)
Weeks 42-55%
CAES stores electricity
in underground
formations including salt
caverns and an
expander to drive a
turbine generator
• Relatively low $/kWh
capex
• Mature technology
• Requires access to a
salt cavern
• High losses
• Relatively slow
response
• Limited availability of
salt caverns
• Isobaric systems
potentially reduce
volume by 77%
Hydrogen-Organics Months 59-89%
Uses chemical
processes to store
hydrogen, typically as
ammonia or methanol
• Mature technology
• Relatively high energy
density
• Storage of volatile
chemicals
• Relatively high losses
• Relatively high $/kWh
• Widely available
• High potential for cost
reduction
Pumped
Hydro Months 80%
Pumps water into
reservoirs for later use
to drive water turbine
generators
• Mature technology
• Relatively low $/kWh
capex
• Relatively low standing
losses
• Requires access to
reservoir
• Scale required
• Relatively slow
response
• Limited availability of
reservoirs
Source: Energeia research
123
Version 1.0 Page 32 of 41 January 2022
Appendix C – Detailed Portfolio Results
This appendix contains detailed resource capacities (Table C1), resource costs (Table C2) and total costs (Table C3) for each risk-impacted portfolio Energeia assessed. The grey rows indicate scenarios which were not assessed due to not being feasible given the scenario assumptions.
Table C1 – Resource Capacities by Portfolio (MW)
# Scenario Electricity Type Scenario Summary Solar Wind Geothermal Small Hydro
Large
Hydro 4-Hr 8-Hr 12-Hr OCGT
Sensitivity
1 HBH Carbon Free 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.6 112.3 2 HBH Renewable 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.6 112.3 3 HBH Carbon Free No Hydro
4 HBH Renewable No Hydro 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.6 112.3 5 HBH Carbon Free No OCGT 0.0 28.4 29.1 0.0 0.0 83.5 74.3 24.2 0.0 6 HBH Renewable No OCGT 0.0 28.4 29.1 0.0 0.0 83.5 74.3 24.2 0.0 7 HBH Carbon Free No CAISO Revenue 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.6 112.3 8 HBH Renewable No CAISO Revenue 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.6 112.3 9 HBH Carbon Free No OCGT, No CAISO Revenue 0.0 28.4 29.1 0.0 0.0 83.5 74.3 24.2 0.0 10 HBH Renewable No OCGT, No CAISO Revenue 0.0 28.4 29.1 0.0 0.0 83.5 74.3 24.2 0.0 11 HBH Carbon Free No Hydro, No OCGT
12 HBH Renewable No Hydro, No OCGT 0.0 28.4 29.1 0.0 0.0 83.5 74.3 24.2 0.0 13 HBH Carbon Free No Hydro, No OCGT, No CAISO Revenue
14 HBH Renewable No Hydro, No OCGT, No CAISO Revenue 0.0 28.4 29.1 0.0 0.0 83.5 74.3 24.2 0.0 15 CN Carbon Free 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0 16 CN Renewable 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0
17 CN Carbon Free No Hydro
18 CN Renewable No Hydro 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0 19 CN Carbon Free No OCGT 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0 20 CN Renewable No OCGT 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0 21 CN Carbon Free No CAISO Revenue
22 CN Renewable No CAISO Revenue
23 CN Carbon Free No OCGT, No CAISO Revenue
24 CN Renewable No OCGT, No CAISO Revenue
25 CN Carbon Free No Hydro, No OCGT
26 CN Renewable No Hydro, No OCGT 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0 27 CN Carbon Free No Hydro, No OCGT, No CAISO Revenue
28 CN Renewable No Hydro, No OCGT, No CAISO Revenue
Risk
2 HBH Renewable Drought 36.0 72.4 7.2 0.0 0.0 31.1 13.1 12.4 282.9 3 HBH Renewable Electric Vehicle Uptake 39.0 71.7 3.3 0.0 0.0 0.0 10.0 7.2 273.5 4 HBH Renewable Building Electrification Uptake 0.0 100.0 16.6 0.0 0.0 0.0 0.0 0.0 267.4 6 CN Renewable Drought 15.4 5.1 0.0 9.3 0.0 49.2 11.5 15.2 0.0 7 CN Renewable Electric Vehicle Uptake 0.0 0.0 2.6 5.3 0.0 12.5 22.0 6.5 0.0 8 CN Renewable Building Electrification Uptake 2.3 33.2 0.0 7.4 0.0 14.7 8.1 6.1 0.0 Source: Energeia modelling
124
Version 1.0 Page 33 of 41 January 2022
Table C2 – Resource Costs by Portfolio ($M/Yr)
# Scenario Electricity Type Scenario Summary Solar Wind Geothermal Small Hydro
Large
Hydro 4-Hr 8-Hr 12-Hr OCGT
Sensitivity
1 HBH Carbon Free $0.0 $3.3 $7.3 $0.0 $0.0 $5.3 $14.4 $3.3 $12.9 2 HBH Renewable $0.0 $3.3 $7.3 $0.0 $0.0 $5.3 $14.4 $3.3 $12.9 3 HBH Carbon Free No Hydro
4 HBH Renewable No Hydro $0.0 $3.3 $7.3 $0.0 $0.0 $5.3 $14.4 $3.3 $12.9 5 HBH Carbon Free No OCGT $0.0 $2.4 $18.8 $0.0 $0.0 $10.6 $16.4 $7.5 $0.0 6 HBH Renewable No OCGT $0.0 $2.4 $18.8 $0.0 $0.0 $10.6 $16.4 $7.5 $0.0 7 HBH Carbon Free No CAISO Revenue $0.0 $3.3 $7.3 $0.0 $0.0 $5.3 $14.4 $3.3 $12.9 8 HBH Renewable No CAISO Revenue $0.0 $3.3 $7.3 $0.0 $0.0 $5.3 $14.4 $3.3 $12.9 9 HBH Carbon Free No OCGT, No CAISO Revenue $0.0 $2.4 $18.8 $0.0 $0.0 $10.6 $16.4 $7.5 $0.0 10 HBH Renewable No OCGT, No CAISO Revenue $0.0 $2.4 $18.8 $0.0 $0.0 $10.6 $16.4 $7.5 $0.0 11 HBH Carbon Free No Hydro, No OCGT
12 HBH Renewable No Hydro, No OCGT $0.0 $2.4 $18.8 $0.0 $0.0 $10.6 $16.4 $7.5 $0.0 13 HBH Carbon Free No Hydro, No OCGT, No CAISO Revenue
14 HBH Renewable No Hydro, No OCGT, No CAISO Revenue $0.0 $2.4 $18.8 $0.0 $0.0 $10.6 $16.4 $7.5 $0.0 15 CN Carbon Free $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 16 CN Renewable $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 17 CN Carbon Free No Hydro
18 CN Renewable No Hydro $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 19 CN Carbon Free No OCGT $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 20 CN Renewable No OCGT $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 21 CN Carbon Free No CAISO Revenue
22 CN Renewable No CAISO Revenue
23 CN Carbon Free No OCGT, No CAISO Revenue
24 CN Renewable No OCGT, No CAISO Revenue
25 CN Carbon Free No Hydro, No OCGT
26 CN Renewable No Hydro, No OCGT $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 27 CN Carbon Free No Hydro, No OCGT, No CAISO Revenue
28 CN Renewable No Hydro, No OCGT, No CAISO Revenue
Risk
2 HBH Renewable Drought $2.4 $6.0 $4.7 $0.0 $0.0 $3.9 $2.9 $3.8 $28.3 3 HBH Renewable Electric Vehicle Uptake $2.6 $5.9 $2.1 $0.0 $0.0 $0.0 $2.2 $2.2 $34.8 4 HBH Renewable Building Electrification Uptake $0.0 $8.3 $10.8 $0.0 $0.0 $0.0 $0.0 $0.0 $38.1 6 CN Renewable Drought $1.0 $0.4 $0.0 $7.9 $0.0 $6.2 $2.5 $4.7 $0.0 7 CN Renewable Electric Vehicle Uptake $0.0 $0.0 $1.7 $4.5 $0.0 $1.6 $4.8 $2.0 $0.0 8 CN Renewable Building Electrification Uptake $0.2 $2.8 $0.0 $6.3 $0.0 $1.9 $1.8 $1.9 $0.0 Source: Energeia modelling
125
Version 1.0 Page 34 of 41 January 2022
Table C3 – Total Portfolio Costs by Portfolio ($M/Yr)
# Scenario Electricity Type Scenario Summary Resources RA/AS/FRA CAISO Net Cost Sensitivity
1 HBH Carbon Free $46.5 $0.0 -$3.9 $42.6
2 HBH Renewable $46.5 $0.0 -$3.9 $42.6
3 HBH Carbon Free No Hydro
4 HBH Renewable No Hydro $46.5 $0.0 -$3.9 $42.6
5 HBH Carbon Free No OCGT $55.6 $0.0 -$5.8 $49.8
6 HBH Renewable No OCGT $55.6 $0.0 -$5.8 $49.8
7 HBH Carbon Free No CAISO Revenue $46.5 $0.0 $0.0 $46.5 8 HBH Renewable No CAISO Revenue $46.5 $0.0 $0.0 $46.5
9 HBH Carbon Free No OCGT, No CAISO Revenue $55.6 $0.0 $0.0 $55.6 10 HBH Renewable No OCGT, No CAISO Revenue $55.6 $0.0 $0.0 $55.6 11 HBH Carbon Free No Hydro, No OCGT
12 HBH Renewable No Hydro, No OCGT $55.6 $0.0 -$5.8 $49.8 13 HBH Carbon Free No Hydro, No OCGT, No CAISO Revenue
14 HBH Renewable No Hydro, No OCGT, No CAISO Revenue $55.6 $0.0 $0.0 $55.6 15 CN Carbon Free $16.5 $0.0 $0.5 $17.0
16 CN Renewable $16.5 $0.0 $0.5 $17.0
17 CN Carbon Free No Hydro
18 CN Renewable No Hydro $16.5 $0.0 $0.5 $17.0
19 CN Carbon Free No OCGT $16.5 $0.0 $0.5 $17.0
20 CN Renewable No OCGT $16.5 $0.0 $0.5 $17.0
21 CN Carbon Free No CAISO Revenue
22 CN Renewable No CAISO Revenue
23 CN Carbon Free No OCGT, No CAISO Revenue
24 CN Renewable No OCGT, No CAISO Revenue
25 CN Carbon Free No Hydro, No OCGT
26 CN Renewable No Hydro, No OCGT $16.5 $0.0 $0.5 $17.0 27 CN Carbon Free No Hydro, No OCGT, No CAISO Revenue
28 CN Renewable No Hydro, No OCGT, No CAISO Revenue
Risk
2 HBH Renewable Drought $52.0 $0.0 -$5.0 $47.0
3 HBH Renewable Electric Vehicle Uptake $49.9 $0.0 -$4.3 $45.6 4 HBH Renewable Building Electrification Uptake $57.1 $0.0 -$2.4 $54.8 6 CN Renewable Drought $22.8 $0.0 $1.6 $24.4
7 CN Renewable Electric Vehicle Uptake $14.6 $0.0 $2.8 $17.4 8 CN Renewable Building Electrification Uptake $14.7 $0.0 $4.9 $19.6 Source: Energeia modelling
126
Version 1.0 Page 35 of 41 January 2022
Appendix D – Additional Portfolio Views
This appendix includes additional hourly HBH and CN portfolio profile charts for average summer and winter days and the annual minimum demand day.
Across both scenarios, summer days experiences higher demand on average compared to winter days. All HBH charts show load being met every hour of every day, while the CN charts show gaps between resources and load where CAISO energy must be purchased. Additionally, the HBH minimum day exports almost no excess generation to CAISO, and the CN minimum day does not have any excess generation to export.
Hour-by-Hour
Figure D1 – 2030 Hour-by-Hour Average Summer Day Profile Source: VCE (2020), Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine Figure D2 – 2030 Hour-by-Hour Average Winter Day Profile Source: VCE (2020), Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine Figure D3 – 2030 Hour-by-Hour Min Day Profile
Source: VCE (2020), Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine -150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
-150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
-150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
127
Version 1.0 Page 36 of 41 January 2022
Carbon Neutral
Figure D4 – 2030 Carbon Neutral Average Summer Day Profile Source: VCE (2020), Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine Figure D5 – 2030 Carbon Neutral Average Winter Day Profile Source: VCE (2020), Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine Figure D6 – 2030 Carbon Neutral Min Day Profile
Source: VCE (2020), Energeia analysis; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine -150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
-150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
-150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
128
Version 1.0 Page 37 of 41 January 2022
Appendix E – Bibliography
1. California Energy Commission (2019), 2019 Residential Appliance Saturation Study, https://www.energy.ca.gov/data-reports/surveys/2019-residential-appliance-saturation-study
2. ICF (2019), Renewable Sources of Natural Gas: Supply and Emissions Reduction Assessment, https://www.gasfoundation.org/wp-content/uploads/2019/12/AGF-2019-RNG-Study-Full-Report-FINAL-12-18-19.pdf
3. International Energy Agency (2010), Energy Technology Systems Analysis Program: Gas-Fired Power, https://iea-etsap.org/E-TechDS/PDF/E02-gas_fired_power-GS-AD-gct.pdf
4. National Renewable Energy Lab (2020), 2020 Annual Technology Baseline (ATB) Cost and Performance Data for Electricity Generation Technologies, https://data.nrel.gov/system/files/145/2020- ATB-data-MAC.xlsm
5. U.S. Department of Energy (2010), Open EI: Building Technologies Program, https://openei.org/datasets/files/961/pub/COMMERCIAL_LOAD_DATA_E_PLUS_OUTPUT/ and https://openei.org/datasets/files/961/pub/RESIDENTIAL_LOAD_DATA_E_PLUS_OUTPUT/
6. U.S. Energy Information Agency (2021), Cost and Performance Characteristics of New Generating Technologies, Annual Energy Outlook 2021,
https://www.eia.gov/outlooks/aeo/assumptions/pdf/table_8.2.pdf
7. Valley Clean Energy (2020), Integrated Resource Plan 46 MMT Calculations
8. Valley Clean Energy (2021), Request for Proposals for 100% Carbon Free Portfolio Study 129
Version 1.0 Page 38 of 41 January 2022
Appendix F – About Energeia USA
Energeia USA (Energeia) understands the CCA and utility businesses, and key technical elements required to transform our industry into a clean, sustainable, and still reliable system with affordability as a key objective. We are passionate about helping our clients achieve their 100% carbon free goals.
Energeia was established in 2015 in Davis, CA as the US headquarters of Energeia Pty Ltd, an Australia company founded in 2009. Energeia Pty Ltd has grown since 2009 to become the largest specialist energy consultancy in Australia. Energeia’s US ambitions are to establish the best emerging energy focused consultancy in the country in Davis, CA.
Figure D1 – Energeia USA Office in Davis, CA – Same Block as Valley Clean Energy Energeia specializes in providing advisory, research and analytical tool development services in the following areas:
• Energy system and network planning and optimization
• Cost-of-service and advanced rate / tariff design
• Energy storage, including lithium, pumped hydro, hydrogen and carbon-based • Electric vehicles and charging infrastructure
• Distributed generation and storage technologies
• Demand management and energy efficiency
• Building electrification
• Hydrogen integration
Energeia delivers its services across three lines of business:
1. Proprietary research – We provide in-depth reports on distributed energy resource related markets and technologies of strategic interest, including EVs, solar PV and storage, smart grids, microgrids, energy efficiency and home energy management.
2. uSim and wSim Utility and Market Simulators – We have developed industry leading utility simulation software that models customer behaviour, bills, DER adoption, 8760 load profiles, production cost, capacity expansion, rates and financial performance, on an integrated basis.
3. Professional Services – We offer tailored services in the areas of rate and incentive design, cost of service analysis, DER and load forecasting, system planning, production cost modelling, and DER technology related strategy and plan development.
130
Version 1.0 Page 39 of 41 January 2022
We are organized into research, consulting and software development functional units, but there is significant cross-over between the working groups due to the significant quantitative analysis that we perform on behalf of our clients, much of which requires custom tooling.
Proprietary Research Advantage
Through our research capability we are continually monitoring emerging threats and opportunities and assessing their implications. This investment in knowledge ensures that we are able to offer our clients the latest thinking on emerging energy technologies.
Some of our recent reports include:
• Sound and Fury: The Outlook for Storage to 2024
• Brave New World: The Outlook for Smart Meters to 2024 • Awakening: The Outlook for Smart Grid Investment to 2029 • Over the Edge: The Outlook for Embedded Microgrids to 2027 • Off-target: The Residential Energy Efficiency Market to 2020 • Personal Power Stations: Residential micro-CHP Market to 2021 Relevant Experience
Energeia’s experience and track record from relevant projects has been summarised below.
Table D1 – Project Descriptions
Client Project Relevant Experience
The Green
Hydrogen
Coalition
HyDeal LA
HyDeal LA is an initiative to achieve at-scale green hydrogen procurement at $1.50/kg in the Los Angeles Basin by 2030. Energeia is part of a team leading the Industrial Plan and Economics workstream, which will collect data on LA's electricity network, establish demand scenarios and design the first global system designs for the prioritized supply options.
Orlando
Utilities
Commission
Battery
Valuation and
Framework
Energeia developed a production cost and capacity expansion tool to support OUC’s evaluation of future battery energy storage projects.
We defined the key value streams and methodologies to quantify monetary and non-monetary benefits as they apply to OUC and the Florida Municipal Power Pool (FMPP) and identified the key use cases for battery storage for value stacking.
Confidential
Client
Scenario Based
Integrated
System
Modelling
Energeia modelled a regional power market serving 7 million connections across 5 states over a 20 year period across 10 scenarios. Energeia used its behind-the-meter to transmission system simulator and production cost and capacity expansion software to model the system.
The City of
Davis
Climate Action
and Adaption
Plan Analysis
Energeia will be assessing the Davis CAAP through analysis of vehicle and building electrification, rooftop PV and energy efficiency opportunities and the associated costs and benefits. This project will also involve modelling of all connection points and vehicles in Davis.
Los Angeles
Department of
Water and
Power
Distributed
Energy
Resources
Integration
Study
Energeia analyzed LADWP’s cost-of-service at the system, transmission, 34.5kV and 4.8kV level, and by time period, to identify optimized DER programs, incentives and cost-reflective rate design for delivery of optimized DER adoption patterns and minimization of LADWP’s overall cost-of-service and customer electricity costs 131
Version 1.0 Page 40 of 41 January 2022
Client Project Relevant Experience
Los Angeles
Department of
Water and
Power
Once Through
Cooling
Reliability Study
Energeia developed specific, reliable, implementable, practical and least cost DER solutions tailored to address LADWP’s forecast system constraints expected to arise under a range of alternative 1.5 GW thermal generation plant repowering scenarios, including a no repowering scenario.
Fresno
County Rural
Transit
Agency
EV Grid
Integration
Analysis
Energeia assessed and optimized the impact of vehicle electrification including public transit and DER adoption on PG&E’s grid. Energeia evaluated different rate configurations against multiple onsite DER solutions to identify the optimal electric fleet charging and load management solution for our client. We also identified least-cost grid upgrade solutions.
Sacramento
Municipal
Utilities
District
Integrated
Distributed
Resource Plan
Energeia used its advanced, in-house utility simulator tool, uSim, to determine the distribution system impacts and associated costs and benefits of DERs as envisioned in the Sacramento Municipal Utility District’s 2018 Integrated Resources Plan. Energeia also estimated DER values as avoided distribution capital and O&M for distribution.
Sacramento
Municipal
Utilities
District
Alternative
Fuels
Assessment
Energeia was engaged to perform an alternative fuels assessment to identify optimal low cost, low carbon fuels for retooling of five aeroderivative LM6000 engines. Energeia performed wheel to well analyses of multiple pathways for renewable gas production and ultimately identified multiple key pathways for SMUD to pursue to decarbonize their peaker plants.
Placer County
Solar Cost of
Service and Net
Benefits
Analysis
Energeia was engaged to provide an estimate of net benefits from the County's proposed Cincinnati Solar Project. For this project, Energeia will compile metered hourly loads and develop a billing model to produce shadow bills for each meter based on the current rate schedule applying to each meter to identify the net impacts of the proposed investment.
Roseville
Electric Utility
Building
Electrification
Program Design
Energeia reviewed the state of the art in building electrification and fuel switching program designs and then developed a best practice building electrification program including sales targets, incentive levels, funding sources, budgeting and investment case.
Roseville
Electric Utility
EV Charging
Demand Plan
Energeia configured its EV uptake model to forecast EV adoption and charging demand by customer segment and time of day.
Energeia also developed a spatial model which indicates charging locations and the utility assets most likely to be impacted by the different kinds of EV charging demand for the City of Roseville.
Finally, we identified EV program elements that could help mitigate these impacts, including load management and Vehicle-to-Grid technology.
Smarter Grid
Solutions
Microgrid
Market Analysis
Study
Energeia was commissioned to perform a comprehensive study of California's microgrid market and microgrid-related legislation to determine the optimal position for SGS to enter the CA market.
During this project, Energeia performed extensive desktop research and leveraged both CEC and EIA datasets to deliver a complete, up to date report with data-driven recommendations.
Australian
Solar
Research
Institute
Concentrated
Solar Power
Cost Targets
Energeia identified grid-scale storage requirements at different locations in the system over time under a range of future scenarios by updating and configuring its whole-of-system National Electricity Market (NEM) simulation platform to provide estimates of when and where peak to off-peak pricing differentials, and therefore marginal storage opportunities, emerge on a geo-spatial and time-of-day basis.
132
Version 1.0 Page 41 of 41 January 2022
Energeia USA
132 E St. #310
Davis, CA 95616
[email protected]
www.energeia-usa.com
Energeia’s mission is to empower our clients by
providing the evidence-based advice using the best
analytical tools and information available
Heritage
Energeia was founded in 2009 to pursue a gap foreseen in the professional services market for specialist information, skills and expertise that would be required for the industry’s transformation over the coming years.
Since then the market has responded strongly to our unique philosophy and value proposition, geared towards those at the forefront and cutting edge of the energy sector.
Energeia has been working on landmark projects focused
on emerging opportunities and solving complex issues
transforming the industry to manage the overall impact. 133
Item 14
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 14
____________________________________________________________________________________ TO: Board of Directors
FROM: Gordon Samuel, Assistant General Manager & Director of Power Services SUBJECT: CC Power Tumbleweed Energy Storage Project
DATE: February 10, 2022
Recommendation
1) Authorize the Interim General Manager to execute on behalf of Valley Clean Energy as a member of CC Power the following agreements and any necessary ancillary documents for the Tumbleweed long duration storage project with a delivery term of 15 years starting at the commercial operation date on or about June 1, 2026:
a. Project Participation Share Agreement between Valley Clean Energy, California Community Power and other participating CCAs
b. Buyer Liability Pass Through Agreement between Valley Clean Energy, California Community Power and Tumbleweed Energy Storage, LLC.
Background
Joint CCA Request for Information and Offers
In June 2020, Valley Clean Energy along with 10 other CCAs issued a request for information (RFI) from long duration storage (LDS) technology providers and project developers (LDS >=8hrs). The information collected through the RFI was used to develop a request for offers (RFO). This RFO was issued on October 15, 2020, and bids were due on December 1, 2020.
The joint CCAs received a robust response with 51 entities submitting offers representing over 9,000 MW. In collaboration with staff from the participating CCAs, these projects were evaluated through a two round evaluation process. Projects were scored based on value to the CCAs, locational value, development status, project viability and ability to meet resource adequacy requirements, technology viability, project team experience, compliance with workforce policy and environmental impact. The top 17 projects were moved to a second round of evaluation. All 17 projects were sent a follow-up questionnaire on labor, environmental and developer experience. Developers representing non-Li-Ion projects (such as: Emerging technologies defined as non-Li-Ion including 2nd life EV, Gravity, Hydrogen, Liquid Air, Compressed Air, Iron Redox Flow, and Pumped Storage Hydro) were interviewed about their project and technology as well.
Formation of CC Power
In 2020, a group of CCAs came together to discuss forming a joint powers authority (JPA) called California Community Power (CC Power) to leverage their combined buying power to provide cost 134
2 effective joint services, programs, and procurement of energy resources and products. In February 2021, Valley Clean Energy’s Board voted for VCE to become a member of CC Power (topic was presented to the CAC in January 2021). The other CCAs that are members of CC Power include MCE, 3CE, SVCE, SJCE, RCEA, VCE, SCP, EBCE, and CPSF. Once CC Power was formed, CC Power as an organization took over the LDS RFO work that had been underway.
CPUC Mid-Term Reliability Procurement Mandate
On June 24, 2021, the California Public Utilities Commission (CPUC) adopted D.21-06-035. This decision is commonly known as the mid-term reliability (MTR) procurement mandate. It directs load serving entities (LSEs) to collectively procure 11,500 MW of new resources between 2023 to 2026 to meet mid-term grid reliability needs. The requirement is measured as net qualifying capacity (NQC) rather than nameplate capacity. The CPUC issued a report identifying what percent of a technology’s nameplate capacity would count toward this requirement. This means that each LSE’s nameplate capacity is higher than the requirement identified in the decision. The decision requires that contracts have a term of at least 10 years and that resources be zero-emission or eligible under the California renewable portfolio standard (RPS).
Procurement Category 2023 2024 2025 2026 Total
Zero-emissions
generation, generation
paired with storage, or
demand response
resources
- - 2,500 - 2,500
Firm zero-emitting
resources
- - - 1,000 1,000
Long-duration storage
resources
- - - 1,000 1,000
Remaining New Capacity
Required
- - 7,000
Total Annual Net
Qualifying Capacity (NQC)
Requirements
2,000 6,000 1,500 2,000 11,500
One of the categories identified in the decision was long duration energy storage. Once this decision was issued, the CCAs focused the RFO negotiations to ensure that the identified project and contract terms would allow the project to count toward each of the CCAs obligations under this decision.
The requirements were allocated to each LSE based on load share. Under the decision, VCE was allocated a requirement for 4 MW of LDS NQC, which is approximately equivalent to 5.1 MW of nameplate capacity.
135
3 Shortlist and Negotiations
Staff conducted an extensive analysis of projects submitted through the LDS RFO to identify a shortlist of projects. The Tumbleweed project was determined to be in the top tier of projects that would provide the most value to the CCAs. This shortlist was identified in June 2021 and at that time CC Power entered exclusivity with shortlisted projects and began negotiations.
CC Power conducted a solicitation process to identify counsel and a key negotiator to represent CC Power in its negotiations with counterparties identified through the LDS RFO process. CC Power retained Keyes and Fox and Gridwell Consulting to conduct the negotiations.
Representatives from each of the participating CCAs met with the CC Power General Manager and the negotiating team on a weekly basis to receive updates on negotiating status and provide input to the negotiating process.
Overview of Project
Project Name Tumbleweed Energy Storage, LLC
Technology Li-Ion Storage
Storage Capacity 69 MW / 552 MWh
Commercial Operation Date 6/1/2026
Developer REV Renewables, a subsidiary of LS Power
Location Kern County, CA
The Tumbleweed project is a 69 MW / 552 MWh lithium-ion battery storage facility located near Rosamond, CA in Kern County. The Commercial Operation Date is June 1, 2026. VCE’s share of this project is 2.86 MW / 22.88 MWh
The project has an executed interconnection agreement with Full Capacity Deliverability Status (FCDS) for the energy storage component, meaning it will provide resource adequacy attributes in addition to energy benefits. The project will interconnect to SCE’s Whirlwind substation. The project is sited in an area with multiple operating solar and wind generation resources. Given the concentration of existing energy resources, Tumbleweed is considered an “in-fill” development. The project is expected to start construction by December 31, 2025.
Under the contract, CC Power will pay for the use of the storage project at a fixed-price rate per kW-month, with no escalation, for the full term of the contract (15 years). CC Power is entitled to all product attributes from the facility, including energy arbitrage, ancillary services, and resource adequacy.
Developer
The project is being developed by REV Renewables, which is a subsidiary of LS Power. LS Power was founded in 1990 and is a development, investment and operating company focused on the power and energy infrastructure sector. LS Power has developed more than 660 miles of high voltage transmission, and developed, constructed, managed, or acquired more than 45,000 MW of power 136
4 generation, including utility-scale solar, wind, hydro, natural gas-fired and battery energy storage projects. Additionally, LS Power actively invests in distributed energy resources and other clean energy platforms, such as CPower Energy Management, Endurant Energy, EVgo and Rise Light & Power, as well as renewable fuels.
LS Power formed REV Renewables to accelerate investment in renewable energy and storage technologies. REV owns 1.9 GW of operating energy storage across the U.S. including 600MW of operating battery energy storage. REV has an additional 1.3 GW of battery energy storage in development.
Environmental Review
Each bidder provided a geospatial footprint of their project. During the evaluation period, CC Power studied the geospatial footprint of the project to evaluate whether the project is located in a restricted or high conflict area for renewable energy development. These areas include but are not limited to:
• Protected areas at the federal, state, regional, local level (e.g. County-designated conservation areas, BLM Areas of Critical Environmental Concern, critical habitat for listed species, national, state, county parks, etc.).
• Identified and mapped important habitat and habitat linkages, especially for threatened and endangered species (either state or federally listed).
Further, projects that are located in areas designated for renewable energy development or in areas that are not suitable for other developmental activities, such as EPA re-power sites, receive positive environmental scores.
For this project, the analysis showed that the project was not located in a protected area based on the USGS Protected Areas Database1(PAD-US). Additionally, the project is not located in an area not suitable for renewable energy development as identified by the Renewable Energy Transmission Initiative (RETI)2.
Workforce Requirements
The project has committed that the construction of the project will comply with California prevailing wage requirements and be conducted using a project labor agreement, community workforce agreement, work site agreement, collective bargaining agreement, or other similar agreement providing for terms and conditions of employment with applicable labor organizations.
Participating CCAs
1 USGS PAD-US: https://www.usgs.gov/core-science-systems/science-analytics-and-synthesis/gap/science/protected-areas 2 RETI: https://reti.databasin.org/
137
5 Seven of the CC Power CCAs are participating in this contract. The CCAs and their shares of the project are identified in the table below. The project’s capacity was allocated to the CCAs based on their obligation under the CPUC MTR procurement mandate.
CCA
CPUC Capacity
Obligation
MW NQC
Entitlement
Share
Tumbleweed
Allocation
(MW)
Tumbleweed
Allocation
NQC
Credit Rating
CPSF 15.5 16.06% 11.08 8.67 Moody’s A2
PCE 19 19.69% 13.59 10.62 Moody’s Baa2
Fitch BBB+
RCEA 3.5 3.62% 2.50 1.95 -
SJCE 21.5 22.28% 15.37 12.02 -
SVCE 20.5 21.25% 14.66 11.47 Moody’s Baa2
S&P A
SCPA 12.5 12.95% 8.94 6.99 S&P A
VCE 4 4.15% 2.86 2.24 -
Total 96.5 100.00% 69.00 53.96
Contract Structure
VCE will execute the following agreements:
• Project Participation Share Agreement (PPSA): This agreement will be executed by CC Power and each of the participating CCAs. This agreement conveys the project benefits (energy arbitrage, resource adequacy, ancillary services) from CC Power to each of the CCAs. It also details payment timelines from each CCA to CC Power and covers terms and procedures if a CCA does not make payments when due and if a CCA needs to be removed from the contract for non-performance. Under this agreement, each CCA commits to a 25% “step-up” obligation.
If one of the participating CCAs defaults and is removed from the agreement, each CCA commits to take additional capacity up to 25% of its initial share. Under this agreement, each CCA also commits to pre-pay three months of expected project payments. This provides a cushion to CC Power to allow it to make payments to the project developer on a timely basis. • Buyer Liability Pass Through Agreement (BLPTA): This agreement will be executed by VCE, CC Power and Tumbleweed Energy Storage, LLC. The form of this agreement is an appendix to the Energy Storage Services Agreement (ESSA). This agreement is a guaranty by VCE of its share of payment obligations under the ESSA.
• Coordinated Operations Agreement (COA): This agreement will be executed by CC Power and each of the participating CCAs. This agreement details how the CCAs and CC Power will work together to operate the project including hiring a scheduling coordinator and making decisions on charging and discharging the project. This contract will be finalized and executed closer to the start of project operations.
138
6 On January 19, 2022, the CC Power Board approved the Tumbleweed ESSA. The ESSA gives CC Power 90 days to secure approval from each of the participating CCAs governing Boards.
Strategic Plan
The Tumbleweed project supports the following objectives in VCE’s strategic plan:
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 -2.3 Objective: Deploy storage and other strategies to achieve renewable, carbon neutral, resource adequacy, and resiliency objectives.
Discussion/Conclusion
VCE’s expected share of the Tumbleweed project is approximately 4% of the project which is equivalent to 2.86 MW nameplate capacity or 2.24 MW NQC. This will satisfy approximately 56% of the LDS mandate assigned to VCE.
Staff is asking the Board to approve VCE’s participation in the Tumbleweed project. In addition, each participating CCA is asking its Board for cushion to allow them to proceed with this project in case there are changes in share allocation due to any CCA not receiving their Board’s approval (note: VCE will seek approval for up to 5MW). This will also cover situations where there is a step-up event. Staff anticipates that all CCA’s will receive approval to participate, but in the event one or more do not, this buffer will help avoid the need to go back to each of the CCA Boards for re-approval.
The Tumbleweed project is the first project for CCAs to procure together through CC Power, and the first LDS project contract to be executed to meet the MTR procurement mandate. CC Power is actively negotiating another LDS project, which will satisfy the remaining MTR need and staff plans to bring that project to the CAC and Board in the very near future.
Attachment
1. Project Participation Share Agreement (PPSA - Draft)
2. Energy Storage Services Agreement (ESSA - redacted)
139
TUMBLEWEED ENERGY STORAGE
PROJECT PARTICIPATION SHARE AGREEMENT
among
CITY AND COUNTY OF SAN FRANCISCO, ACTING BY AND THROUGH ITS
PUBLIC UTILITIES COMMISSION CLEANPOWERSF
and
PENINSULA CLEAN ENERGY
and
REDWOOD COAST ENERGY AUTHORITY
and
CITY OF SAN JOSÉ, ADMINISTRATOR OF SAN JOSÉ CLEAN ENERGY and
SILICON VALLEY CLEAN ENERGY
and
SONOMA CLEAN POWER
and
VALLEY CLEAN ENERGY
and
CALIFORNIA COMMUNITY POWER
140
ARTICLE 1 DEFINITIONS....................................................................................................... 1
1.1. Definitions.............................................................................................................. 1
1.2. Rules of Interpretation ......................................................................................... 15 ARTICLE 2 EFFECTIVE DATE AND TERM ...................................................................... 16
2.1. Term. .................................................................................................................... 16 ARTICLE 3 AGREEMENT ..................................................................................................... 16
3.1. Transaction ........................................................................................................... 16 ARTICLE 4 ENTITLEMENT SHARE ................................................................................... 17
4.1. Initial Entitlement Share ...................................................................................... 17
4.2. Change of Entitlement Share. .............................................................................. 17
4.3. Reduction of Entitlement Share to Zero .............................................................. 17 ARTICLE 5 OBLIGATIONS OF CCP; ROLE OF CCP BOARD AND CCP MANAGER .................................................................................................. 17
5.1. Obligations of CCP .............................................................................................. 17
5.2. Role of CCP Board. ............................................................................................. 21
5.3. Role of CCP Manager. ......................................................................................... 23 ARTICLE 6 PROJECT COMMITTEE .................................................................................. 23
6.1. Establishment and Authorization of the Project Committee ................................ 23
6.2. Project Committee Membership .......................................................................... 23
6.3. Project Committee Operations, Meetings, and Voting. ....................................... 24
6.4. Project Committee Responsibilities. .................................................................... 24
6.5. Subcommittees ..................................................................................................... 27
6.6. Representative’s Expenses ................................................................................... 27
6.7. Inaction by Committee ......................................................................................... 27
6.8. Delegation ............................................................................................................ 27 ARTICLE 7 OPERATING COMMITTEE ............................................................................ 27
7.1. Operating Committee ........................................................................................... 27 ARTICLE 8 OPERATING ACCOUNT .................................................................................. 28
8.1. Calculation of Estimated Monthly Project Cost. ................................................. 28
8.2. Operating Account ............................................................................................... 28 ARTICLE 9 BILLING .............................................................................................................. 29
9.1. Monthly Costs ...................................................................................................... 29
9.2. Billing Statements ................................................................................................ 29
9.3. Disputed Monthly Billing Statement ................................................................... 29
9.4. Payment Adjustments; Billing Errors .................................................................. 29 141
9.5. Payment of Invoice Amount ................................................................................ 29
9.6. Withdrawal of Invoice Amount from Operating Account.. ................................. 30
9.7. Late Payments. ..................................................................................................... 30 ARTICLE 10 UNCONDITIONAL PAYMENT OBLIGATIONS;
AUTHORIZATIONS; CONFLICTS; LITIGATION. ............................. 30
10.1. Unconditional Payment Obligation ...................................................................... 30
10.2. Authorizations ...................................................................................................... 31
10.3. Conflicts ............................................................................................................... 31
10.4. Litigation .............................................................................................................. 31
10.5. San José Clean Energy. ........................................................................................ 31
10.6. Clean Power San Francisco.. ............................................................................... 31 ARTICLE 11 PROJECT SPECIFIC MATTERS AND PROJECT
PARTICIPANTS’ RIGHTS AND OBLIGATIONS UNDER THE
ESSA.............................................................................................................. 32
11.1. CCP Rights and Obligations under the ESSA ..................................................... 32 ARTICLE 12 NONPERFORMANCE AND PAYMENT DEFAULT. ................................. 32
12.1. Nonperformance by Project Participants ............................................................. 32
12.2. Payment Default ................................................................................................... 33
12.3. Payment Default Notice ....................................................................................... 33
12.4. Cured Payment Default ........................................................................................ 33
12.5. Suspension of Project Participant’s Project Revenue Rights ............................... 33
12.6. Termination and Disposal of Project Participant’s Project Rights ...................... 34
12.7. Step-Up Invoices. ................................................................................................. 34
12.8. Step-Up Allocation of Project Participant’s Project Rights ................................. 35
12.9. Elimination or Reduction of Payment Obligations .............................................. 37 ARTICLE 13 LIABILITY ........................................................................................................ 37
13.1. Project Participants’ Obligations Several ............................................................ 37
13.2. No Liability of CCP or Project Participants, Their Directors, Officers, Etc.; CCP, The Project Participants’ and CCP Manager’s Directors, Officers, Employees Not Individually Liable ...................................................... 38
13.3. Extent of Exculpation; Enforcement of Rights .................................................... 38
13.4. No General Liability of CCP ............................................................................... 38
13.5. Indemnification .................................................................................................... 38 ARTICLE 14 NOTICES ........................................................................................................... 39
14.1. Addresses for the Delivery of Notices ................................................................. 39
14.2. Acceptable Means of Delivering Notice .............................................................. 39 ARTICLE 15 ASSIGNMENT .................................................................................................. 39
15.1. General Prohibition on Assignments ................................................................... 39 ARTICLE 16 GOVERNING LAW AND DISPUTE RESOLUTION .................................. 39
16.1. Governing Law .................................................................................................... 39 142
16.2. Dispute Resolution ............................................................................................... 40 ARTICLE 17 MISCELLANEOUS .......................................................................................... 40
17.1. Entire Agreement; Integration; Exhibits .............................................................. 40
17.2. Amendments ........................................................................................................ 40
17.3. No Waiver ............................................................................................................ 40
17.4. Severability .......................................................................................................... 40
17.5. Counterparts ......................................................................................................... 40
17.6. Electronic Delivery .............................................................................................. 40
17.7. Binding Effect ...................................................................................................... 41
17.8. Forward Contract ................................................................................................. 41
17.9. City of San Francisco Standard Provisions. ......................................................... 41
17.10. City of San José Standard Provisions. ................................................................. 42
17.11. Further Assurances............................................................................................... 43 EXHIBIT A NOTICES ............................................................................................................. A-1
EXHIBIT B SCHEDULE OF PROJECT PARTICIPANT ENTITLEMENT SHARES AND STEP-UP ALLOCATION CAPS ...................................................... B-1
EXHIBIT C PROCEDURE FOR VOLUNTARY REDUCTION OF PROJECT
PARTICIPANT’S ENTITLEMENT SHARE .......... C-Error! Bookmark not defined.
EXHIBIT D PROJECT COMMITTEE OPERATIONS, MEETINGS, AND VOTING D-Error! Bookmark not defined.
143
TUMBLEWEED ENERGY STORAGE
PROJECT PARTICIPATION SHARE AGREEMENT
PREAMBLE
This Project Participation Share Agreement (“Agreement”) is entered into as of _________ (the “Effective Date”), by and among the City and County of San Francisco acting by and through its Public Utilities Commission, CleanPowerSF, Peninsula Clean Energy, a California joint powers authority, Redwood Coast Energy Authority, a California joint powers authority, City of San José, a California municipality, Silicon Valley Clean Energy, a California joint powers authority, Sonoma Clean Power, a California joint powers authority, and Valley Clean Energy, a California joint powers authority (each individually a “Project Participant” and collectively referred to as the “Project Participants”) and California Community Power (“CCP”), a California joint powers authority. CCP and the Project Participants are sometimes referred to herein individually as a “Party” and jointly as the “Parties.” All capitalized terms used in this Agreement are used with the meanings ascribed to them in Article 1 to this Agreement.
RECITALS
WHEREAS CCP is a Joint Powers Authority, was formed for the purpose of developing, acquiring, constructing, owning, managing, contracting for, engaging in, or financing electric energy generation and storage projects, and for other purposes; and WHEREAS, the Project Participants have participated with CCP in the negotiation of an agreement for purchase of the certain energy storage products of Tumbleweed Energy Storage (the “Project” as defined in Exhibit A of the ESSA), and CCP is to enter into an Energy Storage Service Agreement (“ESSA”), which is incorporated herein by this reference, with Tumbleweed Energy Storage, LLC, a Delaware limited liability company (“Project Developer”), providing for purchase of the energy storage products, and associated rights, benefits, and credits from the Project on behalf of the Project Participants.
WHEREAS, pursuant to this Agreement, CCP shall cause to deliver to each Project Participant the Project Participant’s associated share of the energy storage products and associated rights, benefits, and credits of the Project.
NOW THEREFORE, in consideration of the mutual covenants and agreements herein contained, and for other good and valuable consideration, the sufficiency and adequacy of which are hereby acknowledged, the Parties agree to the following:
ARTICLE 1
DEFINITIONS
1.1. Definitions. The following terms, when used herein with initial capitalization, shall have the meanings set forth below:
144
“AC” means alternating current.
“Affiliate” means, with respect to any Person, each Person that directly or indirectly controls, is controlled by, or is under common control with such designated Person. For purposes of this definition and the definition of “Permitted Transferee”, “control” (including, with correlative meanings, the terms “controlled by” and “under common control with”), as used with respect to any Person, shall mean (a) the direct or indirect right to cast at least fifty percent (50%) of the votes exercisable at an annual general meeting (or its equivalent) of such Person or, if there are no such rights, ownership of at least fifty percent (50%) of the equity or other ownership interest in such Person, or (b) the right to direct the policies or operations of such Person. “Agreement” has the meaning set forth in the Preamble and any Exhibits, schedules, and any written supplements hereto.
“Amended Annual Budget” means the budget approved by the Project Committee and adopted by the CCP Board pursuant to Section 5.1(c) of this Agreement. “Ancillary Services” means frequency regulation, spinning reserve, non-spinning reserve, regulation up, regulation down, black start, voltage support, and any other ancillary services that the Facility is capable of providing consistent with the Operating Restrictions set forth in Exhibit Q of the ESSA, as each is defined in the CAISO Tariff.
“Annual Budget” means the budget approved by the Project Committee and adopted by the CCP Board pursuant to Section 5.1(c) of this Agreement. “Bankrupt” or “Bankruptcy” means, with respect to any entity, such entity that (a) files a petition or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause of action under any bankruptcy, insolvency, reorganization or similar Law, (b) has any such petition filed or commenced against it which remains unstayed or undismissed for a period of ninety (90) days, (c) makes an assignment or any general arrangement for the benefit of creditors, (d) otherwise becomes bankrupt or insolvent (however evidenced), (e) has a liquidator, administrator, receiver, trustee, conservator or similar official appointed with respect to it or any substantial portion of its property or assets, or (f) is generally unable to pay its debts as they fall due.
“Billing Statement” has the meaning set forth in Section 9.2 of this Agreement. “Buyer Liability Pass Through Agreement” or “BLPTA” means, for each Project Participant, the form set forth in Exhibit L of the ESSA, as executed by such Project Participant, countersigned by CCP, and delivered to the Project Developer. “Business Day” means any day except a Saturday, Sunday, or a Federal Reserve Bank holiday in California. A Business Day begins at 8:00 a.m. and ends at 5:00 p.m. local time for the Party sending a Notice, or payment, or performing a specified action. “CAISO” means the California Independent System Operator Corporation or any successor entity performing similar functions.
145
“CAISO Balancing Authority Area” has the meaning set forth in the CAISO Tariff. “CAISO Certification” means the certification and testing requirements for a storage unit set forth in the CAISO Tariff that are applicable to the Facility, including certification and testing for all Ancillary Services, PMAX, and PMIN associated with such storage units, that are applicable to the Facility.
“CAISO Grid” has the same meaning as “CAISO Controlled Grid” as defined in the CAISO Tariff.
“CAISO Tariff” means the California Independent System Operator Corporation Agreement and Tariff, Business Practice Manuals (BPMs), and Operating Procedures, including the rules, protocols, procedures, and standards attached thereto, as the same may be amended or modified from time-to-time and approved by FERC.
“California Renewables Portfolio Standard” or “RPS” means the renewable energy program and policies established by California State Senate Bills 1038 (2002), 1078 (2002), 107 (2008), X-1 2 (2011), 350 (2015), and 100 (2018) as codified in, inter alia, California Public Utilities Code Sections 399.11 through 399.31 and California Public Resources Code Sections 25740 through 25751, as such provisions are amended or supplemented from time to time. “Capital Improvements” means any unit of property, property right, land or land right which is a replacement, repair, addition, improvement or betterment to the Project or any transmission facilities relating to, or for the benefit of, the Project, the betterment of land or land rights or the enlargement or betterment of any such unit of property constituting a part of the Project or related transmission facilities which is (i) consistent with Prudent Utility Practices and determined necessary and/or desirable by the CCP Board or (ii) required by any governmental agency having jurisdiction over the Project.
“CCP Board” means the Board of Directors of California Community Power. “CCP Manager” means the General Manager of California Community Power. “CEC” means the California Energy Commission, or any successor agency performing similar statutory functions.
“Capacity Attribute” means any current or future defined characteristic, certificate, tag, credit, or accounting construct associated with the amount of power that the Facility can charge, discharge, and deliver to the Delivery Point at a particular moment and that can be purchased, sold, or conveyed under CAISO or CPUC market rules, including Resource Adequacy Benefits. “CEQA” means the California Environmental Quality Act, as amended or supplemented from time to time.
“Chairperson” has the meaning set forth in Exhibit D.
“Change of Control” has the meaning set forth in Section 1.1 of the ESSA. 146
“Charging Energy” means the Energy delivered to the Facility pursuant to a Charging Notice as measured at the Facility Metering Point by the Facility Meter, as such meter readings are adjusted by the CAISO for any applicable Electrical Losses. “Charging Notice” means the operating instruction, and any subsequent updates, given by CCP’s SC or the CAISO to Project Developer, directing the Facility to charge at a specific MW rate for a specified period of time or amount of MWh; provided, any such operating instruction shall be in accordance with the Operating Restrictions. “Commercial Operation” has the meaning set forth in Section 1.1 of the ESSA. “Commercial Operation Date” or “COD” has the meaning set forth in Section 1.1 of the ESSA.
“Commercial Operation Delay Damages” has the meaning set forth in Section 1.1 of the ESSA.
“Communications Protocols” has the meaning set forth in Section 1.1 of the ESSA. “Community Choice Aggregator” has the meaning set forth in California Public Utilities Code § 331.1.
“Confidential Information” has the meaning set forth in Section 18.1 of the ESSA. “Construction Start” has the meaning set forth in Exhibit B of the ESSA. “Construction Start Date” has the meaning set forth in Exhibit B of the ESSA. “Contract Price” has the meaning set forth on the Cover Sheet of the ESSA. “Contract Term” has the meaning set forth in Section 2.1 of the ESSA. “Contract Year” means a period of twelve (12) consecutive months. The first Contract Year shall commence on the Commercial Operation Date and each subsequent Contract Year shall commence on the anniversary of the Commercial Operation Date. “Coordinated Operations Agreement” means the agreement by and among CCP and all Project Participants for purposes of operating the Project. “Costs” means, with respect to a Project Participant assuming all or a portion of a Defaulting Project Participant’s Entitlement Share pursuant to the process set forth in Section
12.8(b) or 12.8(c), brokerage fees, commissions and other similar third-party transaction costs and expenses reasonably incurred by such Project Participant in terminating any arrangement pursuant to which it has hedged its obligations; and all reasonable attorneys’ fees and expenses incurred by the Project Participant in connection with the Step-Up Allocation. “CPUC” means the California Public Utilities Commission, or successor entity. 147
“Cured Payment Default” means a Payment Default that has been cured in accordance with Section 12.4 of this Agreement.
“Daily Delay Damages” has the meaning set forth in Section 1.1 of the ESSA. “Damage Payment” means the amount to be paid by the ESSA Defaulting Party to the ESSA Non-Defaulting Party after a Terminated Transaction occurring prior to the Commercial Operation Date, in a dollar amount set forth in Section 11.3(a) of the ESSA. “Day-Ahead Market” has the meaning set forth in the CAISO Tariff. “Day-Ahead Schedule” has the meaning set forth in the CAISO Tariff. “Defaulting Project Participant” has the meaning set forth in Section 12.1. “Delivery Point” means the Facility Pnode on the CAISO grid. “Delivery Term” means the period of Contract Years set forth on the Cover Sheet of the ESSA beginning on the Commercial Operation Date, unless terminated earlier in accordance with the terms and conditions of the ESSA.
“Designated Fund” has the meaning set forth in Section 10.5. “Development Security” means (a) cash or (b) a Letter of Credit in the amount set forth on the Cover Sheet of the ESSA.
“Discharging Energy” means the Energy delivered from the Facility to the Delivery Point pursuant to a Discharging Notice during any Settlement Interval or Settlement Period, as measured at the Facility Metering Point by the Facility Meter, as such meter readings are adjusted by the CAISO for any applicable Electrical Losses.
“Discharging Notice” means the operating instruction, and any subsequent updates, given by CCP’s SC or the CAISO to the Facility, directing the Facility to discharge Facility Energy at a specific MW rate for a specified period of time or to an amount of MWh. “Effective Date” has the meaning set forth in the Preamble. “Electrical Losses” means all transmission or transformation losses (a) between the Delivery Point and the Facility Metering Point associated with delivery of Charging Energy, and (b) between the Facility Metering Point and the Delivery Point associated with delivery of Facility Energy.
“Emission Reduction Credits” or “ERCs” means emission reductions that have been authorized by a local air pollution control district pursuant to California Division 26 Air Resources; Health and Safety Code Sections 40709 and 40709.5, whereby a district has established a system by which all reductions in the emission of air contaminants that are to be used to offset certain future increases in the emission of air contaminants shall be banked prior to use to offset future increases in emissions.
148
“Energy” means electrical energy, measured in kilowatt-hours or Megawatt-hours or multiple units thereof.
“Energy Management System” or “EMS” means the Facility’s energy management system.
“Energy Storage Service Agreement” or “ESSA” means the agreement between CCP and Project Developer for the purchase of energy storage products of Tumbleweed Energy Storage, executed on _________________.
“ESSA Defaulting Party” has the meaning set forth in Section 11.1(a) of the ESSA. “ESSA Non-Defaulting Party” has the meaning set forth in Section 11.2 of the ESSA. “Entitlement Share” means the percentage entitlement of each Project Participant as set forth in Exhibit B of this Agreement (entitled “Schedule of Project Participant Entitlement Shares and Step-Up Allocation Caps”) attributable to each such Project Participant, as may be amended pursuant to Section 4.2 or 12.8.
“Entitlement Share Reduction Amount” has the meaning set forth in Exhibit C. “Entitlement Share Reduction Compensation Amount” has the meaning set forth in Exhibit C.
“Entitlement Share Reduction Notice” has the meaning set forth in Exhibit C. “Environmental Attributes” shall mean any and all attributes under the RPS regulations or under any and all other international, federal, regional, state or other law, rule, regulation, bylaw, treaty or other intergovernmental compact, decision, administrative decision, program (including any voluntary compliance or membership program), competitive market or business method (including all credits, certificates, benefits, and emission measurements, reductions, offsets and allowances related thereto) that are attributable now, or in the future to the Facility and its displacement of conventional energy generation.
“Estimated Monthly Project Cost” has the meaning set forth in Section 8.1. “Event of Default” has the meaning set forth in Section 11.1 of the ESSA. “Expected Commercial Operation Date” means the date set forth on the Cover Sheet of the ESSA.
“Facility” means the energy storage facility described on the Cover Sheet of the ESSA and in Exhibit A of the ESSA, located at the Site and including mechanical equipment and associated facilities and equipment required to deliver Product (but excluding any Shared Facilities), as such storage facility may be expanded or otherwise modified from time to time in accordance with the terms of the ESSA.
149
“Facility Energy” means the Energy delivered from the Facility to the Delivery Point during any Settlement Interval or Settlement Period, as measured at the Facility Metering Point by the Facility Meter, as such meter readings are adjusted by the CAISO for any applicable Electrical Losses or Station Use.
“Facility Meter” has the meaning set forth in Section 1.1 of the ESSA. “Facility Metering Point” means the location(s) of the Facility Meter shown in Exhibit R of the ESSA.
“FERC” means the Federal Energy Regulatory Commission or any successor government agency.
“Flexible Capacity” means, with respect to any particular Showing Month, the number of MWs of Product which are eligible to satisfy Flexible RAR. “Flexible RAR” means the flexible capacity requirements established for load-serving entities by the CAISO pursuant to the CAISO Tariff, the CPUC pursuant to the Resource Adequacy Rulings, or by any other Governmental Authority.
“Force Majeure Event” has the meaning set forth in Section 10.1 of the ESSA. “Full Capacity Deliverability Status” or “FCDS” has the meaning set forth in the CAISO Tariff.
“Full Capacity Deliverability Status Finding” means a written confirmation from the CAISO that the Facility is eligible for Full Capacity Deliverability Status. “Gains” means, with respect to a Project Participant assuming all or a portion of a Defaulting Project Participant’s Entitlement Share pursuant to the process set forth in Section
12.8(b) or 12.8(c), an amount equal to the present value of the economic benefit to it, if any (exclusive of Costs), resulting from such Step-Up Allocation for the remaining Contract Term of the ESSA, determined in a commercially reasonable manner. Factors used in determining the economic benefit to such Project Participant may include, without limitation, reference to information supplied by one or more third parties, which shall exclude Affiliates of such Project Participant, including without limitation, quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets, comparable transactions, forward price curves based on economic analysis of the relevant markets, settlement prices for comparable transactions at liquid trading hubs (e.g., NP-15), all of which should be calculated for the remaining Contract Term, and include the value of Environmental Attributes and Capacity Attributes.
“GHG Regulations” means Title 17, Division 3 (Air Resources), Chapter 1 (Air Resources Board), Subchapter 10 (Climate Change), Article 5 (Emissions Cap), Sections 95800 to 96023 of the California Code of Regulations, as amended or supplemented from time to time. “Governmental Authority” means any federal, state, provincial, local, or municipal government, any political subdivision thereof or any other governmental, congressional, or 150
parliamentary, regulatory, or judicial instrumentality, authority, body, agency, department, bureau, or entity with authority to bind a Party at law, including CAISO; provided, “Governmental Authority” shall not in any event include any Party, except to the extent that the Party is acting solely in its governmental capacity.
“Greenhouse Gas” or “GHG” has the meaning set forth in the GHG Regulations or in any other applicable Laws.
“Guaranteed Commercial Operation Date” means the date set forth on the Cover Sheet of the ESSA, as such date may be extended pursuant to Exhibit B of the ESSA. “Guaranteed Construction Start Date” means the date set forth on the Cover Sheet of the ESSA, as such date may be extended pursuant to Exhibit B of the ESSA. “Installed Capacity” means the lesser of (a) PMAX, and (b) maximum dependable operating capacity of the Facility to discharge Energy for eight (8) hours of continuous discharge, as measured in MW AC at the Facility Meter Point by the Facility Meter and adjusted for Electrical Losses to the Delivery Point, that achieves Commercial Operation, as evidenced by a certificate substantially in the form attached as Exhibit I of the ESSA, as such capacity may be adjusted pursuant to Section 5 of Exhibit B of the ESSA.
“Interconnection Agreement” means the interconnection agreement entered into by Project Developer pursuant to which the Facility will be interconnected with the Transmission System, and pursuant to which Project Developer’s Interconnection Facilities and any other Interconnection Facilities will be constructed, operated, and maintained during the ESSA Contract Term.
“Interconnection Facilities” means the interconnection facilities, control and protective devices, and metering facilities required to connect the Facility with the Transmission System in accordance with the Interconnection Agreement.
“Interest Rate” has the meaning set forth in Section 8.2 of the ESSA. “Invoice Amount” has the meaning set forth in Section 9.2. “ITC” means the investment tax credit established pursuant to Section 48 of the United States Internal Revenue Code of 1986.
“Joint Powers Act” means the Joint Exercise of Powers Act of the State of California (Government Code Section 6500 et seq.).
“Joint Powers Agreement” means that certain Joint Powers Agreement dated January 29, 2021, as amended from time to time, under which CCP is organized as a Joint Powers Authority in accordance with the Joint Powers Act.
“kWh” means a kilowatt-hour measured in alternating current, unless expressly stated in terms of direct current.
151
“Late Payment Notice” means a notice issued by CCP to a Project Participant pursuant to Section 9.7.
“Late Payment Charge” has the meaning set forth in Section 9.7. “Law” means any applicable law, statute, rule, regulation, decision, writ, order, decree or judgment, permit or any interpretation thereof, promulgated or issued by a Governmental Authority.
“Letter(s) of Credit” has the meaning set forth in Section 1.1 the ESSA. “Local Capacity Area Resource” has the meaning set forth in the CAISO Tariff. “Local RAR” means the local Resource Adequacy Requirements established for load-serving entities by the CAISO pursuant to the CAISO Tariff, the CPUC pursuant to the Resource Adequacy Rulings, or by any other Governmental Authority. “Local RAR” may also be known as local area reliability, local resource adequacy, local resource adequacy procurement requirements, or local capacity requirements in other regulatory proceedings or legislative actions. “Losses” means, with respect to a Project Participant assuming all or a portion of a Defaulting Project Participant’s Entitlement Share pursuant to the process set forth in Section
12.8(b) or 12.8(c), an amount equal to the present value of the economic loss to it, if any (exclusive of Costs), resulting from such Step-Up Allocation for the remaining Contract Term of the ESSA, determined in a commercially reasonable manner. Factors used in determining economic loss to such Project Participant may include, without limitation, reference to information supplied by one or more third parties, which shall exclude Affiliates of the Project Participant, including without limitation, quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets, comparable transactions, forward price curves based on economic analysis of the relevant markets, settlement prices for comparable transactions at liquid trading hubs (e.g., NP-15), all of which should be calculated for the remaining Contract Term of the ESSA and must include the value of Environmental Attributes and Capacity Attributes.
“Marketable Emission Trading Credits” means emissions trading credits or units pursuant to the requirements of California Division 26 Air Resources; Health & Safety Code Section 39616 and Section 40440.2 for market-based incentive programs such as the South Coast Air Quality Management District’s Regional Clean Air Incentives Market, also known as RECLAIM, and allowances of sulfur dioxide trading credits as required under Title IV of the Federal Clean Air Act (42 U.S.C. § 7651b (a) to (f)).
“Month” means a calendar month.
“Monthly Costs” has the meaning set forth in Section 9.1. “Monthly Capacity Payment” means the payment required to be made by CCP to Project Developer each month of the Delivery Term as compensation for the Product, as calculated in accordance with Exhibit C of the ESSA.
152
“MW” means megawatts in alternating current, unless expressly stated in terms of direct current.
“MWh” means megawatt-hour measured in alternating current, unless expressly stated in terms of direct current.
“NERC” means the North American Electric Reliability Corporation. “Net Qualifying Capacity” or “NQC” has the meaning set forth in the CAISO Tariff. “Non-Defaulting Project Participant” has the meaning set forth in Section 12.1. “Normal Vote” has the meaning set forth in Exhibit D.
“Notice” shall, unless otherwise specified in the Agreement, mean written communications by a Party to be delivered by hand delivery, United States mail, overnight courier service, or electronic messaging (e-mail).
“Operating Account” means an account established by CCP for each Project Participant pursuant to Section 8.2.
“Operating Cost” means the share of the Annual Budget or Amended Annual Budget attributable to the applicable Month for a Billing Statement. “Operating Restrictions” means those restrictions, rules, requirements, and procedures set forth in Exhibit Q of the ESSA.
“Party” has the meaning set forth in the Preamble.
“Payment Default” has the meaning set forth in Section 12.2. “Payment Default Termination Deadline” has the meaning set forth in Section 12.6. “Performance Guarantees” has the meaning set forth in Section 4.3(b) of the ESSA. “Performance Security” means (i) cash or (ii) a Letter of Credit in the amount set forth on the Cover Sheet of the ESSA.
“Permitted Transferee” has the meaning set forth in Section 1.1 of the ESSA. “Person” means any individual, sole proprietorship, corporation, limited liability company, limited or general partnership, joint venture, association, joint-stock company, trust, incorporated organization, institution, public benefit corporation, unincorporated organization, government entity or other entity.
“PMAX” means the applicable CAISO-certified maximum operating level of the Facility. “PMIN” means the applicable CAISO-certified minimum operating level of the Facility. 153
“PNode” has the meaning set forth in the CAISO Tariff.
“Product” has the meaning set forth in Section 3.1
“Progress Report” means a progress report including the items set forth in Exhibit E of the ESSA.
“Project” shall be broadly construed to entail the aggregate of rights, liabilities, interests, and obligations of CCP pursuant to the ESSA, including but not limited to all rights, liabilities, interests, and obligations associated with the Product, all rights, liabilities, interests and obligations associated with the Facility, and including all aspects of the operation and administration of the Facility and the ESSA and the rights, liabilities, interests and obligations associated therewith. “Project Committee” means the committee established in accordance with Section6.1. “Project Developer” means Tumbleweed Energy Storage, LLC, a Delaware limited liability company, or assignee as permitted under the ESSA. “Project Participants” means those entities executing this Agreement, as identified in the Preamble, together in each case with each entity’s successors or assigns. “Project Revenue Rights” means all rights of a Project Participant under this Agreement to any revenue associated with the Facility Energy or Ancillary Services associated with the Facility.
“Project Rights” means all rights and privileges of a Project Participant under this Agreement, including but not limited to its Entitlement Share, its right to receive the Product from the Facility, and its right to vote on Project Committee matters. “Project Rights and Obligations” means the Project Participants’ Project Rights and obligations under the terms of this Agreement.
“Proposed Entitlement Share Reduction Compensation Amount” has the meaning set forth in Exhibit C.
“Prudent Operating Practice” means (a) the applicable practices, methods and acts required by or consistent with applicable Laws and reliability criteria, and otherwise engaged in or approved by a significant portion of the electric industry during the relevant time period with respect to grid-interconnected, utility-scale energy storage facilities in the Western United States, and (b) any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Prudent Operating Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to acceptable practices, methods or acts generally accepted in the industry with respect to grid-interconnected, utility-scale energy storage facilities in the Western United States. Prudent Operating Practice shall include compliance with applicable Laws, applicable safety and reliability criteria, and the applicable criteria, rules and standards promulgated in the National Electric Safety Code and the National Electrical Code, as 154
they may be amended or superseded from time to time, including the criteria, rules, and standards of any successor organizations.
“Qualifying Capacity” has the meaning set forth in the CAISO Tariff. “RA Compliance Showing” means the (a) Local RAR compliance or advisory showings (or similar or successor showings), (b) RAR compliance or advisory showings (or similar or successor showings), and (c) Flexible RAR compliance or advisory showings (or similar successor showings), in each case, an entity is required to make to the CAISO pursuant to the CAISO Tariff, to the CPUC (and, to the extent authorized by the CPUC, to the CAISO) pursuant to the Resource Adequacy Rulings, or to any Governmental Authority.
“RA Deficiency Amount” has the meaning set forth in Section 1.1 of the ESSA. “RA Guarantee Date” means the date by which the Facility is expected to achieve Full Capacity Deliverability Status, which is the Commercial Operation Date. “RA Shortfall Month” has the meaning set forth in Section 1.1 of the ESSA. “Real-Time Market” has the meaning set forth in the CAISO Tariff. “Receiving Party” has the meaning set forth in Section 18.2 of the ESSA. “Reliability Network Upgrades” has the meaning set forth in the CAISO Tariff. “Remedial Action Plan” has the meaning set forth in Section 2.4 of the ESSA. “Replacement RA” has the meaning set forth in Section 1.1 of the ESSA. “Resource Adequacy Benefits” means the rights and privileges attached to the Facility that satisfy any entity’s Resource Adequacy Requirements, as those obligations are set forth in any ruling issue by a Governmental Authority, including the Resource Adequacy Rulings and shall include Flexible Capacity, and any local, zonal or otherwise locational attributes associated with the Facility.
“Resource Adequacy Requirements” or “RAR” means the resource adequacy requirements applicable to an entity as established by the CAISO pursuant to the CAISO Tariff, by the CPUC pursuant to the Resource Adequacy Rulings, or by any other Governmental Authority.
“Resource Adequacy Resource” has the meaning used in Resource Adequacy Rulings. “Resource Adequacy Rulings” means CPUC Decisions 04-01-050, 04-10-035, 05-10-042, 06-04-040, 06-06-064, 06-07-031, 07-06-029, 08-06-031, 09-06-028, 10-06-036, 11-06-022, 12-06-025, 13-06-024, 14-06-050, 15-06-063, 16-06-045, 17-06-027, 18-06-030, 18- 06-031, 19-02-022, 19-06-026, 19-10-021, 20-01-004, 20-03-016, 20-06-002, 20-06-031, 20-06- 028, 20-12-006, 21-06-035 and any other existing or subsequent ruling or decision, or any other resource adequacy laws, rules or regulations enacted, adopted or promulgated by any applicable 155
Governmental Authority, however described, as such decisions, rulings, Laws, rules or regulations may be amended or modified from time-to-time throughout the Contract Term. “Schedule” has the meaning set forth in the CAISO Tariff, and “Scheduled” has a corollary meaning.
“Scheduled Energy” means the Facility Energy that clears under the applicable CAISO market based on the final Day-Ahead Schedule(s), FMM Schedule(s) (as defined in the CAISO Tariff), and/or any other financially binding Schedule(s), market instruction or dispatch for the Facility for a given period of time implemented in accordance with the CAISO Tariff. “Scheduling Coordinator” or “SC” means an entity certified by the CAISO as qualifying as a Scheduling Coordinator pursuant to the CAISO Tariff for the purposes of undertaking the functions specified in “Responsibilities of a Scheduling Coordinator,” of the CAISO Tariff, as amended from time to time.
“Scheduling Coordinator Services Agreement” means the agreement between CCP and a Scheduling Coordinator that was approved by the CCP Board pursuant to Section 5.2(a)(xiii). “Settlement Interval” has the meaning set forth in the CAISO Tariff. “Settlement Period” has the meaning set forth in the CAISO Tariff. “Shared Facilities” means the gen-tie lines, transformers, substations, or other equipment, permits, contract rights, and other assets and property (real or personal), in each case, as necessary to enable delivery of Facility Energy to the Delivery Point, including the Interconnection Facilities and the Interconnection Agreement itself, if applicable, that are used in common with third parties or by the Project Developer for electric generation or storage facilities owned by Project Developer other than the Facility.
“Showing Month” means the calendar month of the Delivery Term, commencing with the Showing Month that contains the RA Guarantee Date, that is the subject of the RA Compliance Showing, as set forth in the Resource Adequacy Rulings and outlined in the CAISO Tariff. For illustrative purposes only, pursuant to the CAISO Tariff and Resource Adequacy Rulings in effect as of the Effective Date, the monthly RA Compliance Showing made in June is for the Showing Month of August.
“Site” has the meaning set forth in Section 1.1 of the ESSA, as further described in Exhibit A of the ESSA.
“Station Use” means the Energy that is used within the Facility to power the lights, motors, temperature control systems, control systems and other electrical loads that are necessary for operation of the Facility.
“Step-Up Allocation Cap” has the meaning set forth in Section 12.8(a). “Step-Up Invoice” means an invoice sent to a Non-Defaulting Project Participant as a result of a Defaulting Project Participant’s Payment Default, which invoice shall separately 156
identify any amount owed with respect to the monthly Billing Statement of the Defaulting Project Participant, as the case may be, pursuant to Section 12.7. “Step-Up Invoice Amount” has the meaning set forth in Section 12.7. “Step-Up Invoice Amount Cap” has the meaning set forth in Section 12.7. “Step-Up Reserve Account” has the meaning set forth in Section 12.7(a)(i). “Storage Level” means, at a particular time, the amount of electric Energy in the Facility available to be discharged as Facility Energy, expressed in MWh. “System Emergency” means any condition that requires, as determined, and declared by CAISO or the Transmission Provider, automatic or immediate action to (i) prevent or limit harm to or loss of life or property, (ii) prevent loss of transmission facilities or generation supply in the immediate vicinity of the Facility, or (iii) to preserve Transmission System reliability. “Tax” or “Taxes” means all U.S. federal, state and local, and any foreign taxes, levies, assessments, surcharges, duties and other fees and charges of any nature imposed by a Governmental Authority, whether currently in effect or adopted during the Contract Term, including ad valorem, excise, franchise, gross receipts, import/export, license, property, sales and use, stamp, transfer, payroll, unemployment, income, and any and all items of withholding, deficiency, penalty, additions, interest or assessment related thereto. “Tax Credits” means any state, local and/or federal production tax credit, depreciation benefit, tax deduction and/or investment tax credit, including the ITC, specific to investments in renewable energy facilities and/or energy storage facilities. “Terminated Transaction” has the meaning set forth in Section 11.2(a) the ESSA. “Termination Payment” has the meaning set forth in Section 11.3 of the ESSA. “Transmission Provider” means any entity that owns, operates, and maintains transmission or distribution lines and associated facilities and/or has entitlements to use certain transmission or distribution lines and associated facilities for the purpose of transmitting or transporting the Facility Energy from the Delivery Point. “Transmission System” means the transmission facilities operated by the CAISO, now or hereafter in existence, which provide energy transmission service downstream from the Delivery Point.
“Unanimous Vote” has the meaning set forth in Exhibit D. “Uncontrollable Forces” means any Force Majeure event and any cause beyond the control of any Party, which by the exercise of due diligence such Party is unable to prevent or overcome, including but not limited to, failure or refusal of any other Person to comply with then existing contracts, an act of God, fire, flood, explosion, earthquake, strike, sabotage, epidemic or pandemic (excluding impacts of the disease designated COVID-19 or the related virus designated 157
SARS-CoV-2 impacts actually known by the Party claiming the Force Majeure Event as of the Effective Date), an act of the public enemy (including terrorism), civil or military authority including court orders, injunctions and orders of governmental agencies with proper jurisdiction or the failure of such agencies to act, insurrection or riot, an act of the elements, failure of equipment, a failure of any governmental entity to issue a requested order, licenseor permit, inability of any Party or any Person engaged in work on the Project to obtain or ship materials or equipment because of the effect of similar causes on suppliers or carriers. Notwithstanding the foregoing, Uncontrollable Forces as defined herein shall also include events of Force Majeure pursuant to the ESSA, as defined therein.
1.2. Rules of Interpretation. In this Agreement, except as expressly stated otherwise or unless the context otherwise requires:
(a) headings and the rendering of text in bold and italics are for convenience and reference purposes only and do not affect the meaning or interpretation of this Agreement; (b) words importing the singular include the plural and vice versa and the masculine, feminine and neuter genders include all genders; (c) the words “hereof”, “herein”, and “hereunder” and words of similar import shall refer to this Agreement as a whole and not to any particular provision of this Agreement; (d) a reference to an Article, Section, paragraph, clause, Party, or Exhibit is a reference to that Article, Section, paragraph, clause of, or that Party or Exhibit to, this Agreement unless otherwise specified;
(e) a reference to a document or agreement, including this Agreement shall mean such document, agreement or this Agreement including any amendment or supplement to, or replacement, novation, or modification of this Agreement, but disregarding any amendment, supplement, replacement, novation or modification made in breach of such document, agreement or this Agreement;
(f) a reference to a Person includes that Person’s successors and permitted assigns;
(g) the terms “include” and “including” mean “include or including (as applicable) without limitation” and any list of examples following such term shall in no way restrict or limit the generality of the word or provision in respect of which such examples are provided;
(h) references to any statute, code or statutory provision are to be construed as a reference to the same as it may have been, or may from time to time be, amended, modified, or reenacted, and include references to all bylaws, instruments, orders and regulations for the time being made thereunder or deriving validity therefrom unless the context otherwise requires; (i) in the event of a conflict, a mathematical formula or other precise description of a concept or a term shall prevail over words providing a more general description of a concept or a term;
158
(j) references to any amount of money shall mean a reference to the amount in United States Dollars;
(k) the expression “and/or” when used as a conjunction shall connote “any or all of”;
(l) words, phrases or expressions not otherwise defined herein that (i) have a generally accepted meaning in Prudent Operating Practice shall have such meaning in this Agreement or (ii) do not have well known and generally accepted meaning in Prudent Operating Practice but that have well known and generally accepted technical or trade meanings, shall have such recognized meanings;
(m) each Party acknowledges that it was represented by counsel in connection with this Agreement and that it or its counsel reviewed this Agreement and that any rule of construction to the effect that ambiguities are to be resolved against the drafting party shall not be employed in the interpretation of this Agreement; and
(n) in the event of any conflict or inconsistency between the terms of this Agreement and the terms of the ESSA or the Coordinated Operations Agreement, the terms and provisions of this Agreement shall control.
ARTICLE 2
EFFECTIVE DATE AND TERM
2.1. Term.
(a) The term of this Agreement shall commence on the Effective Date and shall remain in full force and effect until the occurrence of all of the following: (i) the termination of the ESSA and (ii) the termination of the Buyer Liability Pass Through Agreement for all the Project Participants, and (iii) all Parties have met their obligations under this Agreement (“Term”). (b) Applicable provisions of this Agreement shall continue in effect after termination to the extent necessary to enforce or complete the duties, obligations or responsibilities of the Parties arising prior to termination. All indemnity and audit rights shall remain in full force and effect for three (3) years following the termination of this Agreement.
ARTICLE 3
AGREEMENT
3.1. Transaction. Subject to the terms and conditions of this Agreement, the Project Participants authorize CCP to purchase all Facility Energy, Capacity Attributes, Ancillary Services, and Environmental Attributes associated with the Facility and any Replacement RA provided pursuant to the ESSA (collectively the “Product”), on behalf of the Project Participants.
Pursuant to the procedures set forth in the Coordinated Operations Agreement, CCP shall cause Project Developer to deliver each Project Participant’s Entitlement Share of the Product to such Project Participant, including but not limited to (i) any revenue associated with the Facility Energy, Capacity Attributes, Ancillary Services, or Environmental Attributes associated with the Facility, and (ii) the Capacity Attributes and Environmental Attributes associated with the Facility or 159
otherwise provided to CCP pursuant to the ESSA. CCP shall administer the ESSA and oversee the operation of the Project. CCP shall not sell, assign, or otherwise transfer any Product, or any portion thereof, to any third party other than to the Project Participants, unless authorized by the Project Participants pursuant to this Agreement.
ARTICLE 4
ENTITLEMENT SHARE
4.1. Initial Entitlement Share. Each Project Participant’s initial Entitlement Share as of the Effective Date shall be set forth in Column B of the Table provided in Exhibit B of this Agreement (entitled “Schedule of Project Participant Entitlement Shares and Step-Up Allocation Caps”). Any revisions to the Entitlement Share specified in Exhibit B pursuant to Section 4.2. or Section 12.8 shall be considered an element of the administration of this Agreement and shall not require the consent of the Parties hereto.
4.2. Change of Entitlement Share. Any Project Participant may reduce its Entitlement Share of the Project pursuant to the process set forth in Exhibit C.
4.3. Reduction of Entitlement Share to Zero. If any Project Participant’s Entitlement Share is reduced to zero through any process specified in Exhibit C, such Project Participant shall remain a Party to this Agreement and shall be subject to all rights, obligations, and liabilities of this Agreement, including but not limited to any liabilities for Monthly Capacity Payments, Damage Payment or Termination Payment, as applicable, and any other damage payments or reimbursement amounts under the ESSA.
ARTICLE 5
OBLIGATIONS OF CCP; ROLE OF CCP BOARD AND CCP MANAGER
5.1. Obligations of CCP.
(a) CCP shall take such commercially reasonable actions or implement such commercially reasonable measures as may be necessary or desirable for the utilization, maintenance, or preservation of the rights and interests of the Project Participants in the Project including, if appropriate, such enforcement actions or other measures as the Project Committee or CCP Board deems to be in the Project Participants’ best interests. To the extent not inconsistent with the ESSA or other applicable agreements, CCP may also be authorized by the Project Participants to assume responsibilities for planning, designing, financing, developing, acquiring, insuring, contracting for, administering, operating, and maintaining the Project to effectuate the conveyance of the Product to Project Participants in accordance with Project Participants’ Entitlement Shares.
(b) To the extent such services are available and can be carried forth in accordance with the ESSA, CCP shall also provide such other services, as approved by the Project Committee or CCP Board, as may be deemed necessary to secure the benefits and/or satisfy the obligations associated with the ESSA.
(c) Adoption of Annual Budget. The Annual Budget and any amendments to the Annual Budget shall be prepared and approved in accordance with this Section 5.1(c). 160
(i) The CCP Manager will prepare and submit to the Project Committee a proposed Annual Budget at least ninety (90) days prior to the beginning of each Contract Year during the term of this Agreement. The proposed Annual Budget shall be based on the prior Contract Year’s actual costs and shall include reasonable estimates of the costs CCP expects to incur during the applicable Contract Year in association with the administration of the ESSA, including the cost of insurance coverages that are determined to be attributable to the Project by action of the CCP Board. Upon approval of the proposed Annual Budget by a Normal Vote of the Project Committee, the CCP Manager shall present the proposed Annual Budget to the CCP Board.
The CCP Board shall adopt the Annual Budget no later than thirty (30) days prior to the beginning of such Contract Year and shall cause copies of such adopted Annual Budget to be delivered to each Project Participant.
(ii) At any time after the adoption of the Annual Budget for a Contract Year, the CCP Manager may prepare and submit to the Project Committee a proposed Amended Annual Budget for and applicable to the remainder of such Contract Year. The proposal shall (A) explain why an amendment to the Annual Budget is needed, (B) compare estimated costs against actual costs, and (C) describe the events that triggered the need for additional funding. Upon approval of the proposed Amended Annual Budget by a Normal Vote of the Project Committee, the CCP Manager shall present the proposed Amended Annual Budget to the CCP Board. Upon adoption of the Amended Annual Budget by the CCP Board, such Amended Annual Budget shall apply to the remainder of the Contract Year and the CCP Board shall cause copies of such adopted Amended Annual Budget to be delivered to each Project Participant. (iii) Reports. CCP will prepare and issue to Project Participants the following reports each quarter of a year during the Term:
(A) Financial and operating statement relating to the Project. (B) Variance report comparing the costs in the Annual Budget versus actual costs, and the status of other cost-related issues with respect to the Project. (d) Records and Accounts. CCP will keep, or cause to be kept, accurate records and accounts of the Project as well as of the operations relating to the Project, all in a manner similar to accepted accounting methodologies associated with similar projects. All transactions of CCP relating to the Project with respect to each Contract Year shall be subject to an annual audit.
Each Project Participant shall have the right at its own expense to examine and copy the records and accounts referred to above on reasonable notice during regular business hours. (e) Information Sharing. Upon CCP’s request, each Project Participant agrees to coordinate with CCP to provide such information, documentation, and certifications that are reasonably necessary for the design, financing, refinancing, development, operation, administration, maintenance, and ongoing activities of the Project, including information required to respond to requests for such information from any federal, state, or local regulatory body or other authority.
(f) Consultants and Advisors Available. CCP shall make available to the Project Committee all consultants and advisors, including financial advisors and legal counsel that 161
are retained by CCP, and such consultants, counsel and advisors shall be authorized to consult with and advise the Project Committee on Project matters. CCP agrees to waive any conflicts of interest or any other applicable professional standards or rules as required by consultants, counsel, and advisors to advise the Project Committee on Project matters. (g) Deposit of Insurance Proceeds. CCP shall promptly deposit any insurance proceeds received by CCP from any insurance obtained pursuant to this Agreement or otherwise associated with the Project into the Operating Accounts of the Project Participants based on each Project Participants’ Entitlement Shares.
(h) Liquidated and Other Damages. Any amounts paid to CCP, or applied against payments otherwise due by CCP pursuant to the ESSA or each Project Participant’s respective BLPTA, by the Project Developer shall be deposited on a pro rata share, based on each Project Participant’s Entitlement Share into each Project Participant’s Operating Account.
Liquidated Damages include, but are not limited to Daily Delay Damages, RA Deficiency Amount, Damage Payment, and Termination Payment.
(i) Charging and Discharging Energy. Subject to the direction of the Project Committee, CCP shall reasonably coordinate, schedule, and do all other things necessary or appropriate, except as otherwise prohibited under this Agreement, to provide for the delivery of Charging Energy from the grid to the Point of Delivery to enable CCP to exercise its rights and obligations in connection with Charging Energy in accordance with the requirements of the ESSA.
Subject to the direction of the Project Committee, CCP shall reasonably coordinate, schedule, and do all other things necessary or appropriate, except as otherwise prohibited under this Agreement, to provide for the delivery of Discharging Energy from the Point of Delivery to the grid to enable CCP to maximize the value of the ESSA to the Project Participants in accordance with the requirements of the ESSA.
(j) Resale of Product. Any Project Participant may direct CCP to remarket such Project Participant’s Entitlement Share of the Product, or such Project Participant’s Entitlement Share of any part of the Product. If CCP incurs any expenses associated with the remarketing activities pursuant to this Section 5.1(j), then CCP shall include the total amount of such expenses as a Monthly Cost on the Project Participant’s next Billing Statement. Prior to offering the Project Participant’s Entitlement Share of the Product, or the Project Participant’s Entitlement Share of any part of the Product to any third party, CCP shall first offer the Product or portion of the Product to the other Project Participants. The amount of compensation paid to the selling Project Participant shall be negotiated and agreed to between the selling Project Participant and the purchasing Project Participant or third party. Any payments for any resold Product pursuant to this Section 5.1(j) shall be transmitted directly from the purchasing Project Participant or purchasing third party to the reselling Project Participant. Any such resale to a third party shall not convey any rights or authority over the operation of the Project, and the Project Participant shall not make a representation to the third party that the resale conveys any rights or authority over the operation of the Project.
(k) Uncontrollable Forces. CCP shall not be required to provide, and CCP shall not be liable for failure to provide, the Product, Replacement RA, or other service under this Agreement when such failure, or the cessation or curtailment of, or interference with, the 162
service is caused by Uncontrollable Forces or by the failure of the Project Developer, or its successors or assigns, to obtain any required governmental permits, licenses, or approvals to acquire, administer, or operate the Project; provided, however, that the Project Participants shall not thereby be relieved of their obligations to make payments under this Agreement except to the extent CCP is so relieved pursuant to the ESSA, and provided further that CCP shall pursue all applicable remedies against the Project Developer under the ESSA and distribute any remedies obtained pursuant to Section 5.1(h).
(l) Insurance. Within one hundred and eighty days (180) of the Effective Date of this Agreement, CCP shall secure and maintain, during the Term, insurance coverage as follows:
(i) Commercial General Liability. CCP shall maintain, or cause to be maintained, commercial general liability insurance, including products and completed operations and personal injury insurance, in a minimum amount of One Million Dollars ($1,000,000) per occurrence, and an annual aggregate of not less than Two Million Dollars ($2,000,000), endorsed to provide contractual liability in said amount, specifically covering CCP’s obligations under this Agreement and including each Project Participant as an additional insured. (ii) Employer’s Liability Insurance. CCP, if it has employees, shall maintain Employers’ Liability insurance with limits of not less than One Million Dollars ($1,000,000.00) for injury or death occurring as a result of each accident. With regard to bodily injury by disease, the One Million Dollar ($1,000,000) policy limit will apply to each employee. (iii) Workers’ Compensation Insurance. CCP, if it has employees, shall also maintain at all times during the Term workers’ compensation and employers’ liability insurance coverage in accordance with statutory amounts, with employer’s liability limits of not less than One Million Dollars ($1,000,000.00) for each accident, injury, or illness; and include a blanket waiver of subrogation.
(iv) Business Auto Insurance. CCP shall maintain at all times during the Term business auto insurance for bodily injury and property damage with limits of One Million Dollars ($1,000,000) per occurrence. Such insurance shall cover liability arising out of CCP’s use of all owned (if any), non-owned and hired vehicles, including trailers or semi-trailers in the performance of the Agreement and shall name each Project Participant as an additional insured and contain standard cross-liability and severability of interest provisions. (v) Public Entity Liability Insurance. CCP shall maintain public entity liability insurance, including public officials’ liability insurance, public entity reimbursement insurance, and employment practices liability insurance in an amount not less than One Million Dollars ($1,000,000) per claim, and an annual aggregate of not less than One Million Dollars ($1,000,000) and CCP shall maintain such coverage for at least two (2) years from the termination of this Agreement.
(m) Evidence of Insurance. Within ten (10) days after the deadline for securing insurance coverage specified in Section 5.1(l), and upon annual renewal thereafter, CCP shall deliver to each Project Participant certificates of insurance evidencing such coverage with insurers with ratings comparable to A-VII or higher, and that are authorized to do business in the State of 163
California, in a form evidencing all coverages set forth above. Such certificates shall specify that each Project Participant shall be given at least thirty (30) days prior Notice by CCP in the event of cancellation or termination of coverage. Such insurance shall be primary coverage without right of contribution from any insurance of each Project Participant. Any other insurance maintained by CCP not associated with this Agreement is for the exclusive benefit of CCP and shall not in any manner inure to the benefit of Project Participants. The general liability, auto liability and worker’s compensation policies shall be endorsed with a waiver of subrogation in favor of each Project Participant for all work performed by CCP, its employees, agents and sub-contractors.
5.2. Role of CCP Board.
(a) The rights and obligations of CCP under the ESSA shall be subject to the ultimate control at all times of the CCP Board. The CCP Board, shall have, in addition to the duties and responsibilities set forth elsewhere in this Agreement, the following duties and responsibilities, among others:
(i) Dispute Resolution. The CCP Board shall review, discuss and attempt to resolve any disputes among CCP, any of the Project Participants, and the Project Developer relating to the Project, the operation and management of the Facility, and CCP’s rights and interests in the Facility.
(ii) ESSA. The CCP Board shall have the authority to review, modify, and approve, as appropriate, all amendments, modifications, and supplements to the ESSA. (iii) Capital Improvements. The CCP Board shall review, modify, and approve, if appropriate, all Capital Improvements undertaken with respect to the Project and all financing arrangements for such Capital Improvements. The CCP Board shall approve those budgets or other provisions for the payments associated with the Project and the financing for any development associated with the Project.
(iv) Committees. The CCP Board shall exercise such review, direction, or oversight as may be appropriate with respect to the Project Committee and any other committees established pursuant to this Agreement.
(v) Budgeting. Upon the submission of a proposed Annual Budget or proposed Amended Annual Budget, approved by a Normal Vote of the Project Committee, the CCP Board shall review, modify, and approve each Annual Budget and Amended Annual Budget in accordance with Section 5.1(c) of this Agreement.
(vi) Early Termination of ESSA. The CCP Board shall review, modify, and approve the recommendations of the Project Committee, made pursuant to Section 6.4(b)(ii) of this Agreement, as to an early termination of the ESSA pursuant to Section 11.2 of the ESSA. (vii) Assignment by Project Developer. The CCP Board shall review, modify, and approve the recommendations of the Project Committee, made pursuant to Section
6.4(b)(iii) of this Agreement, as to any assignment by Project Developer pursuant to Section 14.1 of the ESSA other than any assignment pursuant to Sections 14.2 or 14.3 of the ESSA. 164
(viii) Buyer Financing Assignment. The CCP Board shall review, modify, and approve the recommendations of the Project Committee, made pursuant to Section 6.4(b)(iv) of this Agreement, as to an assignment by CCP to a financing entity pursuant to Section 14.5 of the ESSA.
(ix) Change of Control. The CCP Board shall review, modify, and approve the recommendations of the Project Committee, made pursuant to Section 6.4(b)(v) of this Agreement, as to any Change of Control requiring CCP’s consent, as specified in Section 14.1 of the ESSA.
(x) Supervening Authority of the Board. The CCP Board has complete and plenary supervening power and authority to act upon any matter which is capable of being acted upon by the Project Committee or which is specified as being within the authority of the Project Committee pursuant to the provisions of this Agreement. (xi) Other Matters. The CCP Board is authorized to perform such other functions and duties, including oversight of those matters and responsibilities addressed by the Project Committee or CCP Manager as may be provided for under this Agreement and under the ESSA, or as may otherwise be appropriate.
(xii) Periodic Audits. The CCP Board or the Project Committee may arrange for the annual audit by certified accountants, selected by the CCP Board and experienced in electric generation or electric utility accounting, of the books and accounting records of CCP, the Project Developer to the extent authorized under the ESSA, and any other counterparty under any agreement to the extent allowable, and such audit shall be completed and submitted to the CCP Board as soon as reasonably practicable after the close of the Contract Year. CCP shall promptly furnish to the Project Participant copies of all audits. No more frequently than once every calendar year, each Project Participant may, at its sole cost and expense, audit, or cause to be audited the books and cost records of CCP, and/or the Project Developer to the extent authorized under the ESSA.
(xiii) Scheduling Coordinator Services Agreement. Upon a recommendation by Normal Vote of the Project Committee pursuant to Section 6.4(b)(vi), the CCP Board shall review, modify, and approve, or delegate the authority to approve, a Scheduling Coordinator Services Agreement or amendment thereto.
(b) Pursuant to Section 5.06 of the Joint Powers Agreement, this Agreement modifies the voting rules of the CCP Board for purposes of approving or acting on any matter identified in this Agreement, as follows:
(i) Quorum. A quorum shall consist of a majority of the CCP Board members that represent Project Participants.
(ii) Voting. Each CCP Board member that represents a Project Participant shall have one vote for any matter identified in this Agreement. Any CCP Board member representing a CCP member that is not a Project Participant shall abstain from voting on any matter identified in this Agreement. A vote of the majority of the CCP Board members 165
representing Project Participants that are in attendance shall be sufficient to constitute action, provided a quorum is established and maintained.
5.3. Role of CCP Manager.
(a) In addition to the duties and responsibilities set forth elsewhere in this Agreement, the CCP Manager is delegated the following authorities and responsibilities:
(i) Request for Tax Documentation. Respond to any requests for tax-related documentation by the Project Developer. (ii) Request for Financial Statements. Provide the Project Developer with Financial Statements as may be required by the ESSA. (iii) Request for Information by Project Participant. Respond to any request by a Project Participant for information or documents that are reasonably available to allow the Project Participant to respond to requests for such information from any federal, state, or local regulatory body or other authority.
(iv) Coordinate Response to a Request for Confidential Information.
Upon a request or demand by any third person that is not a Party to the ESSA or a Project Participant, for Confidential Information as described in Section 18.2 of the ESSA, the CCP Manager shall notify the Project Developer and coordinate the response of CCP and Project Participants.
(v) Invoices. The CCP Manager shall review each invoice submitted by Project Developer and shall request such other data necessary to support the review of such invoices.
ARTICLE 6
PROJECT COMMITTEE
6.1. Establishment and Authorization of the Project Committee. The Project Committee is hereby established and duly authorized to act on behalf of the Project Participants as provided for in this Section 6 for the purpose of (a) providing coordination among, and information to, the Project Participants and CCP, (b) making any recommendations to the CCP Board regarding the administration of the Project, and (c) execution of the Project Committee responsibilities set forth in Section 6.4.
6.2. Project Committee Membership. The Project Committee shall consist of one representative from each Project Participant. The CCP Manager shall be a non-voting member of the Project Committee. Within thirty (30) days after the Effective Date, each Project Participant shall provide notice to each other of such Project Participant’s representative on the Project Committee. Alternate representatives may be appointed by similar written notice to act on the Project Committee, or on any subcommittee established by the Project Committee, in the absence of the regular representative. An alternate representative may attend all meetings of the Project Committee but may vote only if the representative for whom they serve as alternate for is absent. 166
No Project Participant’s representative shall exercise any greater authority than permitted by the Project Participant which they represent.
6.3. Project Committee Operations, Meetings, and Voting. Project Committee operations, meetings, and voting shall be in accordance with the procedures and requirements specified in Exhibit D.
6.4. Project Committee Responsibilities. The Project Committee shall have the following responsibilities:
(a) General Responsibilities of the Project Committee.
(i) Provide a liaison between CCP and the Project Participants with respect to the ongoing administration of the Project.
(ii) Exercise general supervision over any subcommittee established pursuant to Section 6.5.
(iii) Oversee, as appropriate, the completion of any Project design, feasibility, or planning studies or activities.
(iv) Review, discuss, and attempt to resolve any disputes among the Project Participants relating to this Agreement or the ESSA. (v) Perform such other functions and duties as may be provided for under this Agreement, the ESSA, or as may otherwise be appropriate or beneficial to the Project or the Project Participants.
(b) Recommendations to the CCP Board by a Normal Vote.
(i) Budgeting. Review, modify, and approve by a Normal Vote each proposed Annual Budget and proposed Amended Annual Budget for submission to the CCP Board for final approval.
(ii) Early Termination of ESSA. Review, modify, and approve by a Normal Vote a recommendation to the CCP Board regarding an early termination of the ESSA pursuant to Section 11.2 of the ESSA.
(iii) Assignment by Project Developer. Review, modify, and approve by a Normal Vote a recommendation to the CCP Board regarding any assignment by Project Developer pursuant to Section 14.1 of the ESSA other than any assignment pursuant to Sections
14.2 or 14.3 of the ESSA.
(iv) Buyer Financing Assignment. Review, modify, and approve by a Normal Vote a recommendation to the CCP Board regarding an assignment by CCP to a financing entity pursuant to Section 14.5 of the ESSA.
167
(v) Change of Control. Review, modify, and approve by a Normal Vote a recommendation to the CCP Board regarding any Change of Control requiring CCP’s consent, as specified in Section 14.1 of the ESSA.
(vi) Scheduling Coordinator. Review, modify, and approve by a Normal Vote a recommendation to the CCP Board regarding the selection of a Scheduling Coordinator and the form of the Scheduling Coordinator Services Agreement, including any amendments thereto. Such Scheduling Coordinator Services Agreement shall: (i) require that the scheduling and dispatch of the Project is in accordance with the criteria set forth in Exhibit C of the Coordinated Operations Agreement; (ii) include the Scheduling Coordinator responsibilities specified in Exhibit D of the Coordinated Operations Agreement; and (iii) address requirements relating to CAISO settlements, the Operating Restrictions, and communications and reporting from the Scheduling Coordinator to the Project Participants. (c) Actions Delegated to the Project Committee by this Agreement Subject to a Unanimous Vote.
(i) Project Design. Review, modify, and approve by a Unanimous Vote any recommendations to the Project Developer on the design of the Project. (ii) Extension of Guaranteed Construction Start Date and Guaranteed Commercial Operation Date. Review and confirm that requirements of Exhibit B of the ESSA have been satisfied, such that the Guaranteed Construction Start Date and/or Guaranteed Commercial Operation Date has been extended.
(iii) Event of Default. Direct CCP to exercise its rights under the ESSA if an Event of Default has occurred under Section 11.1 of the ESSA or under the Scheduling Coordinator Services Agreement.
(d) Actions Delegated to the Project Committee by this Agreement Subject to a Normal Vote.
(i) Make recommendations to the CCP Manager, the CCP Board, the Project Participants or to the Project Developer, as appropriate, with respect to the development, operation, and ongoing administration of the Project.
(ii) Review, develop, and, if appropriate, modify and approve rules, procedures, and protocols for the administration of the Project, including rules, procedures, and protocols for the management of the costs of the Facility and the scheduling, handling, tagging, dispatching, and crediting of the Product, the handling and crediting of Environmental Attributes associated with the Facility and the control and use of the Facility. (iii) Review, develop, and, if appropriate, modify rules, procedures, and protocols for the monitoring, inspection, and the exercise of due diligence activities relating to the operation of the Facility.
(iv) Review, and, if appropriate, modify or otherwise act upon, the form or content of any written statistical, administrative, or operational reports, Facility-related data and 168
storage information, technical information, facility reliability data, transmission information, forecasting, scheduling, dispatching, tagging, parking, firming, exchanging, balancing, movement, or other delivery information, and similar information and records, or matters pertaining to the Project which are furnished to the Project Committee by the CCP Manager, the Project Developer, experts, consultants or others.
(v) Review, formulate, and, if appropriate, modify, or otherwise act upon, practices and procedures to be followed by Project Participants for, among other things, the production, scheduling, tagging, transmission, delivery, firming, balancing, exchanging, crediting, tracking, monitoring, remarketing, sale, or disposition of the Product, including the control and use of the Facility, and the supply, scheduling, and use of Charging Energy. (vi) Review and act upon any matters involving any arrangements and instruments entered into by the Project Developer or any affiliate thereof to, among other things, secure certain performance requirements, including, but not limited to, the ESSA, the Development Security or the Performance Security and any other letter of credit delivered to, or for the benefit of, CCP by the Project Developer and take such actions or make such recommendations as may be appropriate or desirable in connection therewith. (vii) Review, and, if appropriate, recommend, modify, or approve policies or programs formulated by CCP or Project Developer for determining or estimating storage resources or the values, quantities, volumes, or costs of the Product from the Facility. (viii) Review, and where appropriate, recommend the implementation of metering technologies and methodologies appropriate for the delivery, accounting for, transferring and crediting of the Product to the Point of Delivery (directly or through the Facility). (ix) Review, to the extent permitted by this Agreement, the ESSA, or any other relevant agreement relating to the Project, modify and approve or disapprove the specifications, vendors’ proposals, bid evaluations, or any other matters with respect to the Facility.
(x) Review and approve any Remedial Action Plan submitted by Project Developer to CCP pursuant to Section 2.4 of the ESSA.
(xi) Review and approve the submission of the written
acknowledgement of the Commercial Operation Date in accordance with Section 2.2 of the ESSA. (xii) Review and approve the return of the Development Security to Project Developer in accordance with Section 8.7 of the ESSA. (xiii) Review and approve the return of any unused Performance Security to Project Developer in accordance with Section 8.8 of the ESSA. (xiv) Review Progress Reports provided by Project Developer to CCP pursuant to Section 2.3 of the ESSA and participate in any associated regularly scheduled meetings with Project Developer to discuss construction progress. 169
(xv) Direct CCP to collect any liquidated damages owed by Project Developer to CCP under the ESSA, and to the extent authorized by ESSA, draw upon the Development Security or Performance Security.
(xvi) Review invoices received by CCP from the Project Developer and, if appropriate, direct CCP to dispute an invoice pursuant to Section 8.5 of the ESSA. (xvii) Review invoices received by CCP from the Scheduling Coordinator and, if appropriate, direct CCP to collect any damages owed by the Scheduling Coordinator to CCP under the Scheduling Coordinator Services Agreement or to take any action permitted by law to enforce its rights under the Scheduling Coordinator Services Agreement, including but not limited to bringing any suit, action or proceeding at law or in equity as may be necessary or appropriate to recover damages and/or enforce any covenant, agreement, or obligation against the Scheduling Coordinator.
6.5. Subcommittees. The CCP Manager may establish as needed subcommittees including, but not limited to, auditing, legal, financial, engineering, mechanical, weather, geologic, diurnal, barometric, meteorological, operating, insurance, governmental relations, environmental, and public information subcommittees. The authority, membership, and duties of any subcommittee shall be established by the CCP Manager; provided, however, such authority, membership or duties shall not conflict with the provisions of the ESSA or this Agreement.
6.6. Representative’s Expenses. Any expenses incurred by any representative of any Project Participant or group of Project Participants serving on the Project Committee or any other committee in connection with their duties on such committee shall be the responsibility of the Project Participant which they represent and shall not be an expense payable under this Agreement.
6.7. Inaction by Committee. It is recognized by CCP and Project Participants that if the Project Committee is unable or fails to agree with respect to any matter or dispute which it is authorized to determine, resolve, approve, disapprove or otherwise act upon after a reasonable opportunity to do so, or within the time specified herein or in the ESSA, then CCP may take such commercially reasonable action as CCP determines is necessary for its timely performance under any requirement pursuant to the ESSA or this Agreement, pending the resolution of any such inability or failure to agree, but nothing herein shall be construed to allow CCP to act in violation of the express terms of the ESSA or this Agreement.
6.8. Delegation. To secure the effective cooperation and interchange of information in a timely manner in connection with various administrative, technical, and other matters which may arise from time to time in connection with administration of the ESSA, in appropriate cases, duties and responsibilities of the CCP Board or the Project Committee, as the case may be under this Section 6, may be delegated to the CCP Manager by the CCP Board upon notice to the Project Participants.
ARTICLE 7
OPERATING COMMITTEE
7.1. Operating Committee. The Operating Committee is established through the Coordinated Operations Agreement, as may be subsequently amended. 170
7.2. Operating Committee Responsibilities. In addition to any specific roles and responsibilities identified in the Coordinated Operations Agreement, the Project Committee may, through a Normal Vote, assign additional tasks to the Operating Committee as long as such additional tasks are within the scope of the Operating Committee’s authority set forth in the Coordinated Operations Agreement.
ARTICLE 8
OPERATING ACCOUNT
8.1. Calculation of Estimated Monthly Project Cost.
(a) No later than one hundred and eighty (180) days after the Effective Date, the CCP Manager shall present to the Project Committee a proposed Estimated Monthly Project Cost, which shall be equal to a forecast of expected Monthly Capacity Payments over an entire Contract Year, divided by twelve (12). The Project Committee shall review, and, if appropriate, recommend, modify, or approve through a Normal Vote, the proposed Estimated Monthly Project Cost.
8.2. Operating Account. CCP shall establish an Operating Account for each Project Participant that is accessible to and can be drawn upon by both CCP and the applicable Project Participant. Such Operating Accounts are for the purpose of providing a reliable source of funds for the payment obligations of the Project and, taking into account the variability of costs associated with the Project for the purpose of providing a reliable payment mechanism to address the ongoing costs associated with the Project.
(a) Operating Account Amount. The Operating Account Amount for each Project Participant shall be an amount equal to the Estimated Monthly Project Cost multiplied by three, the product of which is multiplied by such Project Participant’s Entitlement Share (“Operating Account Amount”).
(b) Initial Funding of Operating Account. By no later than three hundred and sixty-five (365) days after the Effective Date, each Project Participant shall deposit into such Project Participant’s Operating Account an amount equal to that Project Participant’s Operating Account Amount.
(c) Use of Operating Account. CCP shall draw upon each Project Participant’s Operating Account each month in an amount equal to the Monthly Costs multiplied by such Project Participant’s Entitlement Share. As required by Section 9.5, each Project Participant must deposit sufficient funds into such Project Participant’s Operating Account by the deadline specified in Section 9.5.
(d) Final Distribution of Operating Account. Following the expiration or earlier termination of the ESSA, and upon payment and satisfaction of any and all liabilities and obligations to make payments of the Project Participants under this Agreement and upon satisfaction of all remaining costs and obligations of CCP under the ESSA, any amounts then remaining in any Project Participant’s Operating Account shall be paid to the associated Project Participant.
171
ARTICLE 9
BILLING
9.1. Monthly Costs. The amount of Monthly Costs for a particular Month shall be the sum of the Project Participant’s Entitlement Share multiplied by the Monthly Capacity Payments for the Product, as specified in Section 8.2 of the ESSA for such Month and to the extent such payment is made by CCP to the Project Developer, plus the Project Participant’s Entitlement Share multiplied by the Operating Cost for such Month and subtracting the Project Participant’s Entitlement Share multiplied by the positive revenue associated with the sale of any Facility Energy or Ancillary Services net of any CAISO costs or Scheduling Coordinator costs for such Month, as shown in the following formula:
Monthly Cost = ((Project Participant’s Entitlement Share) × (Monthly Capacity Payments)) + ((Project Participant’s Entitlement Share) × (Operating Costs)) – ((Project Participant’s Entitlement Share) × (revenue from sale of Facility Energy or Ancillary Services, net of any CAISO costs or Scheduling Coordinator costs))
9.2. Billing Statements. By no later than ten (10) calendar days after CCP receives an invoice from Project Developer for the prior Month of each Contract Year pursuant to Section 8.1 of the ESSA, CCP shall issue to each Project Participant a copy of the invoice and a “Billing Statement,” which specifies such Project Participant’s Monthly Costs, itemized by each part of such Monthly Cost. The amount of Monthly Costs attributable to a Project Participant, and specified in such Billing Statement, shall be the “Invoice Amount.”
9.3. Disputed Monthly Billing Statement. A Project Participant may dispute, by written Notice to CCP, any portion of any Billing Statement submitted to that Project Participant by CCP pursuant to Section 9.2, provided that the Project Participant shall pay the full amount of the Billing Statement when due. If CCP determines that any portion of the Billing Statement is incorrect, CCP will deposit the difference between such correct amount and such full amount, if any, including interest at the rate received by CCP on any overpayment into the Project Participant’s Operating Account. If CCP and a Project Participant disagree regarding the accuracy of a Billing Statement, CCP will give consideration to such dispute and will advise all Project Participants with regard to CCP’s position relative thereto within thirty (30) days following receipt of written Notice by Project Participant of such dispute.
9.4. Payment Adjustments; Billing Errors. If CCP or Project Developer determines that a prior invoice or Billing Statement was inaccurate, CCP shall credit against or increase as appropriate each Project Participant’s subsequent Monthly Costs according to such adjustment.
The accompanying Billing Statement shall describe the cause of such adjustment and the amount of such adjustment.
9.5. Payment of Invoice Amount. Each Project Participant shall deposit the Invoice Amount for the applicable Month into such Project Participant’s Operating Account by no later than the twentieth (20th) calendar day of the following Month after the Billing Statement is issued, unless CCP has failed to issue the Billing Statement by the deadline specified in Section 9.2, in which case, each Project Participant shall deposit the Invoice Amount for the applicable Month by no later than thirty (30) days after the date on which CCP issues the Billing Statement to the Project Participant.
172
9.6. Withdrawal of Invoice Amount from Operating Account. No sooner than five (5) calendar days after CCP issues a Billing Statement to a Project Participant or a Step-Up Invoice to a Project Participant, CCP shall withdraw the Invoice Amount or the Step-Up Invoice Amount from each Project Participant’s Operating Account. If the Monthly Cost attributable to such Project Participant is a negative number, CCP shall deposit such funds into the Operating Account of that Project Participant.
9.7. Late Payments.
(a) If any Project Participant fails to deposit the Invoice Amount into the Project Participant’s Operating Account by the deadline specified in Section 9.5, then CCP will issue such Project Participant a Late Payment Notice within five (5) days of the deadline specified in Section 9.5 directing the Project Participant to immediately deposit the Invoice Amount into the Project Participant’s Operating Account and informing the Project Participant that such Project Participant must pay a charge (“Late Payment Charge”). Upon issuing a Late Payment Notice to any Project Participant, CCP shall promptly provide Notice of such occurrence to all other Project Participants.
(b) The Late Payment Charge shall be equal to the Invoice Amount minus any partial payment that was deposited into such Project Participant’s Operating Account multiplied by the Interest Rate specified in Section 8.2 of the ESSA for the period from the deadline specified in Section 9.5 until the date on which the Project Participant deposits the Invoice Amount plus the Late Payment Charge into such Project Participant’s Operating Account. Upon payment, CCP shall withdraw the full amount of such Late Payment Charge from the Project Participant’s Operating Account and deposit any such Late Payment Charge into the Operating Accounts of all other Project Participants on a pro rata share, based on such other Project Participants’ Entitlement Shares.
ARTICLE 10
UNCONDITIONAL PAYMENT OBLIGATIONS; AUTHORIZATIONS; CONFLICTS; LITIGATION.
10.1. Unconditional Payment Obligation. Beginning with the earliest of (i) the date CCP is obligated to pay any portion of the costs of the Project, (ii) the date of the COD, or (iii) the date of the first delivery of the Product to Project Participants and continuing through the term of this Agreement, Project Participants shall pay CCP the amounts of Monthly Costs set forth in the Billing Statements submitted by CCP to Project Participants in accordance with the provisions of Section 9, whether or not the Project or any part thereof has been completed, is functioning, producing, operating or operable or its output or the provision of Facility products are suspended, interrupted, interfered with, reduced or curtailed or terminated in whole or in part, and such payments shall not be subject to reduction whether by offset or otherwise and shall not be conditional upon the performance or nonperformance by any party of any agreement for any cause whatsoever, provided that the obligation of Project Participants to pay amounts associated with the Monthly Capacity Payment shall be limited to the amount of Monthly Capacity Payment charged by the Project Developer to CCP and paid by CCP to the Project Developer. 173
10.2. Authorizations. Each Project Participant hereby represents and warrants that no order, approval, consent, or authorization of any governmental or public agency, authority, or person, is required on the part of such Project Participant for the execution and delivery by the Project Participant, or the performance by the Project Participant of its obligations under this Agreement except for such as have been obtained.
10.3. Conflicts. Each Project Participant represents and warrants to CCP as of the Effective Date that, to the Project Participant’s knowledge, the execution and delivery of this Agreement by the Project Participants and the Project Participants’ performance hereunder will not constitute a default under any agreement or instrument to which it is a party, or any order, judgment, decree or ruling of any court that is binding on the Project Participant, or a violation of any applicable law of any governmental authority, which default or violation would have a material adverse effect on the financial condition of the Project Participant.
10.4. Litigation. Each Project Participant represents and warrants to CCP that, as of the Effective Date, to the Project Participant’s knowledge, except as disclosed, there are no actions, suits or proceedings pending against the Project Participant (service of process on the Project Participant having been made) in any court that questions the validity of the authorization, execution or delivery by the Project Participant of this Agreement, or the enforceability on the Project Participant of this Agreement.
10.5. San José Clean Energy.
(a) The City of San José is a municipal corporation and is precluded under the California State Constitution and applicable law from entering into obligations that financially bind future governing bodies without an appropriation for such obligation, and, therefore, nothing in the Agreement shall constitute an obligation of future legislative bodies of the City of San José to appropriate funds for purposes of the Agreement; provided, however, that the City of San José has created and set aside a designated fund (being the San Jose Energy Operating Fund established pursuant to City of San Jose Municipal Code, Title 4, Part 63, Section 4.80.4050 et. seq.) (“Designated Fund”) for payment of its obligations under this Agreement. (b) Limited Obligations. The City of San José’s payment obligations under this Agreement are special limited obligations of San José Clean Energy payable solely from the Designated Fund and are not a charge upon the revenues or general fund of the City of San José or upon any non- San José Clean Energy moneys or other property of the Community Energy Department or the City of San José.
10.6. Clean Power San Francisco. With regard to Clean Power San Francisco only, (1) obligations under this Agreement are special limited obligations of Clean Power San Francisco payable solely from the revenues of Clean Power San Francisco, and shall not be a charge upon the revenues or general fund of the San Francisco Public Utilities Commission or the City and County of San Francisco or upon any non-Clean Power San Francisco moneys or other property of the San Francisco Public Utilities Commission or the City and County of San Francisco, (2) cannot exceed the amount certified by the San Francisco City Controller for the purpose and period stated in such certification, and (3) absent an authorized emergency per the San Francisco City Charter or Code, no San Francisco City representative is authorized to offer or promise, nor is San 174
Francisco required to honor, any offered or promised payments under this Agreement for work beyond the agreed upon scope or in excess of the certified maximum amount without the San Francisco City Controller having first certified the additional promised amount.
ARTICLE 11
PROJECT SPECIFIC MATTERS AND PROJECT PARTICIPANTS’ RIGHTS AND OBLIGATIONS UNDER THE ESSA.
11.1. CCP Rights and Obligations under the ESSA. Notwithstanding anything to the contrary contained in this Agreement: (i) the obligation of CCP to cause the delivery of the Project Participants’ Entitlement Shares of the Product during the Delivery Term of this Agreement is limited to the Product which CCP receives from the Facility (or the Project Developer, as applicable); (ii) the obligation of CCP to pay any amount to Project Participants hereunder or to give credits against amounts due from Project Participants hereunder is limited to amounts CCP receives in connection with the transaction to which the payment or credit relates (or is otherwise available to CCP in connection with this Agreement for which such payment or credit relates); (iii) any purchase costs, operating costs, energy costs (including costs related to Charging Energy), capacity costs, Facility costs, environmental attribute costs, transmission costs, tax costs, insurance costs, indemnifications, other costs or other charges for which CCP is responsible under the ESSA shall be considered purchase costs, operating costs, energy costs, capacity costs, Facility costs, environmental attribute costs, transmission costs, tax costs, insurance costs, indemnifications, other costs or other charges incurred by CCP and payable by Project Participants as provided in this Agreement; (iv) CCP shall carry out its obligations and exercise its rights under the ESSA in a commercially reasonable manner; (v) all remedies provided to CCP pursuant to the ESSA or the Scheduling Coordinator Services Agreement shall be provided to Project Participants in accordance with Section 5.1(h); and (vi) any Force Majeure under the ESSA or other event of force majeure affecting the delivery of Product pursuant to applicable provisions of the ESSA shall be considered an event caused by Uncontrollable Forces affecting CCP with respect to the delivery of the Product hereunder and CCP forwarding to Project Participants notices and information from the Project Developer concerning an event of Force Majeure upon receipt thereofshall be sufficient to constitute a Notice that Uncontrollable Forces have occurred pursuant to Section 5.1 of this Agreement. Any net proceeds received by CCP from the sale of the Product by the Project Developer to any third-party as a result of a Force Majeure event or failure by CCP to accept delivery of Product pursuant to the ESSA and any reimbursement received by CCP for purchase of Replacement RA shall be remitted by CCP to the Project Participants in accordance with their respective Entitlement Shares.
ARTICLE 12
NONPERFORMANCE AND PAYMENT DEFAULT.
12.1. Nonperformance by Project Participants. If a Project Participant fails to perform any covenant, agreement, or obligation under this Agreement or shall cause CCP to be in default with respect to any undertaking entered into for the Project or to be in default under the ESSA (“Defaulting Project Participant”), CCP may, in the event the performance of any such obligation remains unsatisfied after thirty (30) days’ prior written notice thereof to such Project Participant and a demand to so perform, take any action permitted by law to enforce its rights under this Agreement, including but not limited to termination of such Project Participant’s rights under 175
this Agreement including any rights to its Entitlement Share of the Product, and/or bring any suit, action or proceeding at law or in equity as may be necessary or appropriate to recover damages and/or enforce any covenant, agreement or obligation against such Project Participant with regard to its failure to so perform. Any Project Participant that is not the Defaulting Project Participant (“Non-Defaulting Project Participant”) may submit Notice directly to the CCP Board, if such Non-Defaulting Project Participant determines that CCP is or may not be fully taking appropriate actions to enforce CCP’s rights under this Agreement against a Defaulting Project Participant.
The CCP Board shall consider such Notice and direct CCP to take appropriate action, if any.
12.2. Payment Default. If any Project Participant fails to deposit the Invoice Amount into the Project Participant’s Operating Account by the deadline specified in Section 9.5, and if such Participant has not deposited the Invoice Amount plus the Late Payment Charge into such Project Participant’s Operating Account within ten (10) calendar days of the issuance of the Late Payment Notice to such Project Participant by CCP, then such occurrence shall constitute a “Payment Default.”
12.3. Payment Default Notice. Upon the occurrence of a Payment Default, CCP shall issue a Notice of Payment Default to the Project Participant notifying such Project Participant that as a result of a Payment Default, it is in default under this Agreement and has assumed the status of a Defaulting Project Participant and that such Defaulting Project Participant’s Project Revenue Rights have been suspended and that such Defaulting Project Participant’s Project Rights are subject to termination and disposal in accordance with Sections 12.6 and 12.8 of this Agreement.
CCP shall provide a copy of such Notice of Default to all other Project Participants within five (5) calendar days after the issuance of the written Notice of Payment Default by CCP to the Defaulting Project Participant.
12.4. Cured Payment Default. If after a Payment Default, the Defaulting Project Participant cures such Payment Default within forty-five (45) calendar days after the issuance of the Late Payment Notice by CCP, the Defaulting Project Participant’s Project Revenue Rights shall be reinstated and its Project Rights shall not be subject to termination and disposal as provided for in Sections 12.6 and 12.8. In order to cure a Payment Default, the Defaulting Project Participant must deposit the full amount of any unpaid Invoice Amounts and any associated Late Payment Penalties into its Operating Account.
12.5. Suspension of Project Participant’s Project Revenue Rights and Treatment of Capacity Attributes.
(i) Upon the occurrence of a Payment Default, the Defaulting Project Participant’s Project Revenue Rights shall be suspended until such time as such Defaulting Project Participant cures the Payment Default pursuant to the requirements of Section 12.4. Any revenue associated with the Facility Energy or Ancillary Services associated with the Facility shall be deposited by CCP into the Step-Up Reserve Account, as specified in Section 12.7. (ii) For any Month where the funds remaining in a Defaulting Project Participant’s Operating Account are sufficient to pay the entire Invoice Amount, CCP shall withdraw the Invoice Amount from such Defaulting Project Participant’s Operating Account and shall cause the delivery of the Defaulting Project Participant’s Entitlement Share of the Capacity 176
Attributes and Environmental Attributes associated with the Facility or otherwise provided for pursuant to the ESSA. For any Month where the funds remaining in a Defaulting Project Participant’s Operating Account are less than the amount necessary to pay the entire Invoice Amount, CCP shall withdraw all remaining funds from the Defaulting Project Participant’s Operating Account, and to the extent reasonably possible, in CCP’s sole discretion, CCP shall cause the delivery of a quantity of Capacity Attributes and Environmental Attributes proportionate to the portion of the Invoice Amount that the remaining funds were sufficient to pay for. For any Month where the Defaulting Project Participant’s Operating Account has no funds remaining, the Defaulting Project Participant shall have no right to any such Capacity Attributes or Environmental Attributes associated with the Facility or otherwise provided for under the ESSA.
12.6. Termination and Disposal of Project Participant’s Project Rights. If a Defaulting Project Participant has not cured a Payment Default within forty-five (45) calendar days after the payment deadline specified in Section 9.5 by CCP (“Payment Default Termination Deadline"), then all Project Rights and Obligations pursuant to this Agreement shall be terminated and disposed in accordance with Sections 12.6 and 12.8 of this Agreement; provided, however, that the Defaulting Project Participant shall be liable for all outstanding payment obligations accrued prior to the Payment Default Termination Deadline and shall remain subject to all rights, obligations, and liabilities of this Agreement, including but not limited to any liabilities for Damage Payment or Termination Payment, as applicable, and any other damage payments or reimbursement amounts under the ESSA. CCP shall provide to the Defaulting Project Participant a separate monthly invoice of any such payment obligations of such Defaulting Project Participant.
CCP shall immediately notify the other Project Participants of such termination of the Defaulting Project Participant’s Project Rights and Obligations.
12.7. Step-Up Invoices.
(a) Upon the occurrence of a Payment Default, CCP shall, concurrently with the Late Payment Notice issued pursuant to Section 9.7(a), issue a Step-Up Invoice to each Non-Defaulting Project Participant that specifies such Non-Defaulting Project Participant’s pro rata payment obligation, calculated based on the Entitlement Share of such Non-Defaulting Project Participant, of the amount of the Payment Default for the Defaulting Project Participant (the “Step-Up Invoice Amount”); provided, however, that a Non-Defaulting Project Participant’s Step-Up Invoice Amount shall not exceed twenty-five percent (25%) of such Non-Defaulting Project Participant’s Invoice Amount for the same month for which the Payment Default occurred (the “Step-Up Invoice Amount Cap”).
(i) Each Non-Defaulting Project Participant shall deposit the Step-Up Invoice Amount into such Non-Defaulting Project Participant’s Operating Account by the later of the twentieth (20th) calendar day of the following Month or thirty (30) days after the date on which CCP issues the Step-Up Invoice to the other Project Participants. No sooner than five (5) calendar days after CCP issues the Step-Up Invoice, CCP may withdraw the amount of the Step-Up Invoice from each Project Participant’s Operating Account and deposit such funds in a separate account (“Step-Up Reserve Account”), which shall be accessible only by CCP, and which CCP may in its sole discretion draw upon in order to ensure that CCP can meet the payment obligations of the ESSA. CCP first shall withdraw all funds from a Defaulting Project Participant’s Operating Account before withdrawing funds from the Step-Up Reserve Account. 177
(ii) Application of Moneys Received from a Defaulting Project Participant. If a Defaulting Project Participant cures a Payment Default on or before the Payment Default Termination Deadline, any funds remaining in the Step-Up Reserve Account shall be deposited into the Operating Accounts of the other Project Participants on a pro rata share, based on the Entitlement Share of such other Project Participant. If a Defaulting Project Participant fails to cure a Payment Default and the Defaulting Project Participant’s Project Rights and Obligations are terminated and disposed of in accordance with Section 12.8, any funds remaining in the Step-Up Reserve Account shall be deposited into the Operating Accounts of the Non-Defaulting Project Participants on a pro rata share, based on the Entitlement Share, subject to the Step-Up Invoice Amount Cap, of such other Project Participant. If any Non-Defaulting Project Participant has not deposited the full amount of its share of the Step-Up Invoice Amount into its Operating Account by the deadline specified in Section 12.7(a)(i), then such occurrence shall be a Late Payment as specified in Section 9.7(a) and is subject to a Late Payment Charge pursuant to Section 9.7(b), and any such Non-Defaulting Project Participant shall not be entitled to its share of any moneys received from the Defaulting Project Participant or any funds remaining in the Step-Up Reserve Account in accordance with this Section 12.7(a)(ii) until such Non-Defaulting Project Participant has deposited the full amount of its Step-Up Invoice Amount and the Late Payment Charge into its Operating Account.
12.8. Step-Up Allocation of Project Participant’s Project Rights. In the event that a Defaulting Project Participant’s Project Rights are terminated pursuant to Section 12.6, then such Defaulting Project Participant’s Entitlement Share shall be allocated to the other Project Participants (“Step-Up Allocation”) pursuant to the process set forth in this Section 12.8. If a Project Participant has defaulted in the performance of any of its obligations under its BLPTA, and any applicable cure periods under the BLPTA have expired, the Project Participants shall, to the extent required by each respective Project Participant’s BLPTA, utilize the procedures set forth in this Section 12.8 to allocate the Project Rights and Obligations of the Project Participant that has defaulted under the BLPTA to the Project Participants that have not defaulted under the BLPTA, subject to the Step-Up Allocation Cap specified in Section 12.8(a). (a) Step-Up Allocation Cap. If a Defaulting Project Participant’s Entitlement Share is allocated to the Non-Defaulting Project Participants pursuant to this Section 12.8, no individual Non-Defaulting Project Participant shall be obligated to assume an allocation that exceeds that Project Participant’s Step-Up Allocation Cap set forth in Column E of the Table in Exhibit B of this Agreement. Each Non-Defaulting Project Participant’s initial Step-Up Allocation Cap shall be equal to the Non-Defaulting Project Participant Entitlement Share as of the Effective Date and set forth in Column B of the Table in Exhibit B of this Agreement, multiplied by one hundred and twenty-five percent (125%). If a Project Participant modifies its Entitlement Share pursuant to Section 4.2 of this Agreement, then that Project Participant’s Step-Up Allocation Cap shall be equal to the Project Participant’s Entitlement Share as modified pursuant to Section 4.2 multiplied by one hundred and twenty-five percent (125%). Upon a modification of a Project Participant’s Entitlement Share pursuant to Section 4.2, the CCP Manager shall cause the Step-Up Allocation Cap specified in Column E of the Table in Exhibit B of this Agreement to be modified in accordance with this Section 12.8(a). For avoidance of doubt, if a Project Participant’s Entitlement Share is increased pursuant to Section 12.8(b) or (c), then such Project Participant’s Step-Up Allocation Cap shall not be modified.
178
(b) Step-Up Allocation Share. If a Defaulting Project Participant’s Project Rights are terminated pursuant to Section 12.6, then such Defaulting Project Participant’s Entitlement Share shall be allocated to each Non-Defaulting Project Participant based on such Non-Defaulting Project Participant’s pro rata share, calculated based on its Entitlement Share of the entire project minus the Entitlement Share of the Defaulting Project Participant, unless such allocation would cause any individual Non-Defaulting Project Participant to exceed its Step-Up Allocation Cap, in which case Section 12.8(c) shall apply. Upon allocation of a defaulting Project Participant’s Entitlement Share pursuant to this Section 12.8(b), the CCP Manager shall cause each affected Project Participant’s Entitlement Share specified in Column D of the Table in Exhibit B to be modified in accordance with this Section 12.8.
(c) Voluntary Allocation of Project Rights in Excess of the Step-Up Allocation Caps. If the allocation of a Defaulting Project Participant’s Entitlement Share pursuant to Section
12.8(b) would cause any Non-Defaulting Project Participant’s Entitlement Share to exceed its Step-Up Allocation Cap, then no allocation shall occur pursuant to Section 12.8(b). In such case, the CCP Manager shall oversee the offering of the total amount of the Defaulting Project Participant’s Entitlement Share to the Non-Defaulting Project Participants on a voluntary basis.
The initial offering shall be to each Non-Defaulting Project Participant on a pro rata share, based on such Non-Defaulting Project Participant’s Entitlement Share. Each Project Participant may accept or reject the portion of the Defaulting Project Participant’s Entitlement Share. If any portion of the Defaulting Project Participant’s Entitlement Share remains unclaimed after the initial offering, then the remaining portion shall be offered to any Non-Defaulting Project Participant that accepted its full share of the Defaulting Project Participant’s Entitlement Share in the initial offering on a pro rata share, based on such Non-Defaulting Project Participant’s Entitlement Share as a percentage of the total Entitlement Shares of all Project Participants that are participating in the subsequent round of offerings. The CCP Manager shall conduct subsequent offering rounds until either the total amount of the Defaulting Project Participant’s Entitlement Share is accepted by one or more of the Non-Defaulting Project Participants or some portion of the Defaulting Project Participant’s Entitlement Share remains, but all Non-Defaulting Project Participants have rejected such remaining amount.
(d) Step-Up Allocation Damage Payment. A Defaulting Project Participant shall owe to each Non-Defaulting Project Participant that assumes any portion of the Defaulting Project Participant’s Entitlement Share pursuant to the process set forth in Section 12.8(b) or
12.8(c) a “Step-Up Allocation Damage Payment” equal to the Costs and Losses, on the one hand, netted against its Gains, on the other. If the Non-Defaulting Project Participant’s Costs and Losses exceed its Gains, then the Step-Up Allocation Damage Payment shall be an amount owing to such Non-Defaulting Project Participant. If the Non-Defaulting Project Participant’s Gains exceed its Costs and Losses, then the Step-Up Allocation Damage Payment shall be zero dollars ($0). A Defaulting Project Participant shall not be entitled to any Step-Up Allocation Damage Payment or any other damages otherwise authorized under this Agreement from any other Project Participant.
The Step-Up Allocation Damage Payment does not include consequential, incidental, punitive, exemplary, or indirect or business interruption damages. Each Non-Defaulting Project Participant that assumes any portion of the Defaulting Project Participant’s Entitlement Share pursuant to the process set forth in Section 12.8(b) or 12.8(c) shall calculate, in a commercially reasonable manner, the Step-Up Allocation Damage Payment for the Defaulting Project Participant’s Entitlement Share assumed by the Non-Defaulting Project Participant as of the effective date of such Step-Up 179
Allocation. Third parties supplying information for purposes of the calculation of Gains or Losses may include, without limitation, dealers in the relevant markets, end-users of the relevant product, information vendors and other sources of market information. If the Defaulting Project Participant disputes the Non-Defaulting Project Participant’s calculation of the Step-Up Allocation Damage Payment, in whole or in part, the Defaulting Project Participant shall, within five (5) Business Days of receipt of the Non-Defaulting Project Participant’s calculation of the Step-Up Allocation Damage Payment, provide to the Non-Defaulting Project Participant a detailed written explanation of the basis for such dispute. Disputes regarding the Step-Up Allocation Damage Payment shall be determined in accordance with Article 16. Each Party agrees and acknowledges that (i) the actual damages that the other Project Participant would incur in connection with a Step-Up Allocation would be difficult or impossible to predict with certainty, (ii) the Step-Up Allocation Damage Payment described in this Section 12.8(d) is a reasonable and appropriate approximation of such damages, and (iii) the Step-Up Allocation Damage Payment described in this Section
12.8(d) is the exclusive remedy of a Project Participant in connection with a Step-Up Allocation pursuant to the process set forth in Sections 12.8(b) or 12.8(c) against a Defaulting Project Participant but shall not otherwise act to limit any of the Non-Defaulting Project Participant’s rights or remedies under this Agreement.
(e) Remarketing of Unclaimed Defaulting Project Participant’s Entitlement Share. If after the process set forth in Section 12.8(c), some portion of the Defaulting Project Participant’s Entitlement Share remains unclaimed, the CCP Manager, in their discretion or as directed by the Non-Defaulting Project Participants, may take any action to generate revenue from such unclaimed Entitlement Share in order to meet CCP’s payment obligation under the ESSA.
For avoidance of doubt, the CCP Manager shall not be limited by the requirements of Section 4.2 or 5.1(j) of this Agreement in remarketing or generating revenue base on the unclaimed share.
12.9. Elimination or Reduction of Payment Obligations. Notwithstanding anything to the contrary in this Agreement, upon termination of a Defaulting Project Participant’s Project Rights pursuant to Section 12.6 and the disposal of such Defaulting Project Participant’s Project Rights and Obligations pursuant to Section 12.8, such Defaulting Project Participant’s obligation to make payments under this Agreement (notwithstanding anything to the contrary herein) shall not be eliminated or reduced; provided, however, such payment obligations for the Defaulting Project Participant may be eliminated or reduced to the extent permitted by law, through an amendment to this Agreement, which shall be subject to the consent and approval of all Parties to this Agreement.
ARTICLE 13
LIABILITY
13.1. Project Participants’ Obligations Several. No Project Participant shall be liable under this Agreement for the obligations of any other Project Participant or for the obligations of CCP incurred on behalf of other Project Participants. Each Project Participant shall be solely responsible and liable for performance of its obligations under this Agreement, except as otherwise provided for herein. The obligation of Project Participants to make payments under this Agreement is a several obligation and not a joint obligation with those of the other Project Participants.
180
13.2. No Liability of CCP or Project Participants, Their Directors, Officers, Etc.; CCP, The Project Participants’ and CCP Manager’s Directors, Officers, Employees Not Individually Liable. Except as provided for under Section 13.5 herein, the Parties agree that neither CCP, Project Participants, nor any of their past, present or future directors, officers, employees, board members, agents, attorneys or advisors (collectively, the “Released Parties”) shall be liable to any other of the Released Parties for any and all claims, demands, liabilities, obligations, losses, damages (whether direct, indirect or consequential), penalties, actions, loss of profits, judgments, orders, suits, costs, expenses (including attorneys’ fees and expenses) or disbursements of any kind or nature whatsoever in law, equity or otherwise (including, without limitation, death, bodily injury or personal injury to any person or damage or destruction to any property of Project Participants, CCP, or third persons) suffered by any Released Party as a result of the action or inaction or performance or non-performance by the Project Developer under the ESSA. Except as provided for under Section 13.5 herein, each Party shall release each of the other Released Parties from any claim or liability that such Party may have cause to assert as a result of any actions or inactions or performance or non-performance by any of the other Released Parties under this Agreement (excluding gross negligence and willful misconduct, which, unless otherwise agreed to by the Parties, are both to be determined and established by a court of competent jurisdiction in a final, non-appealable order). Notwithstanding the foregoing, no such action or inaction or performance or non-performance by any of the Released Parties shall relieve CCP or any Project Participants from their respective obligations under this Agreement, including, without limitation, the Project Participants’ obligation to make payments required under Section 9.5 of this Agreement and CCP’s obligation to make payments under Section 8.2 of the ESSA. The provisions of this Section 13.2 shall not be construed so as to relieve the CCP or the Project Developer from any obligation or liability under this Agreement or the ESSA.
13.3. Extent of Exculpation; Enforcement of Rights. The exculpation provision set forth in Section 13.2 hereof shall apply to all types of claims or actions including, but not limited to, claims or actions based on contract or tort. Notwithstanding the foregoing, any Party may protect and enforce its rights under this Agreement by a suit or suits in equity for specific performance of any obligations or duty of any other Party, and each Party shall at all times retain the right to recover, by appropriate legal proceedings, any amount determined to have been an overpayment, underpayment or other monetary damages owed by the other Party in accordance with the terms of this Agreement.
13.4. No General Liability of CCP. The undertakings under this Agreement by CCP shall not constitute a debt or indebtedness of CCP within the meaning of any provision or limitation of the Constitution or statutes of the State of California, and shall not constitute or give rise to a charge against its general credit.
13.5. Indemnification. Each Party shall indemnify, defend, protect, hold harmless, and release the other Parties, their directors, board members, officers, employees, agents, attorneys and advisors, past, present or future, from and against any and all claims, demands, liabilities, obligations, losses, damages (whether direct, indirect or consequential), penalties, actions, loss of profits, judgments, orders, suits, costs, expenses (including attorneys’ fees and expenses) or disbursements of any kind or nature whatsoever in law, equity or otherwise, which include, without limitation, death, bodily injury, or personal injury to any person or damage or destruction to any property of Project Participants, CCP, or third persons, that may be imposed on, incurred by or 181
asserted against any Party arising by manner of any breach of this Agreement, or the negligent acts, errors, omissions or willful misconduct incident to the performance of this Agreement on the part of any Party or any Party’s directors, board members, officers, employees, agents and advisors, past, present or future.
ARTICLE 14
NOTICES
14.1. Addresses for the Delivery of Notices. Any Notice required, permitted, or contemplated hereunder shall be in writing, shall be addressed to the Party to be notified at the address set forth in Exhibit A or at such other address or addresses as a Party may designate for itself from time to time by Notice hereunder.
14.2. Acceptable Means of Delivering Notice. Each Notice required, permitted, or contemplated hereunder shall be deemed to have been validly served, given or delivered as follows: (a) if sent by United States mail with proper first class postage prepaid, five (5) Business Days following the date of the postmark on the envelope in which such Notice was deposited in the United States mail; (b) if sent by a regularly scheduled overnight delivery carrier with delivery fees either prepaid or an arrangement with such carrier made for the payment of such fees, the next Business Day after the same is delivered by the sending Party to such carrier; (c) if sent by electronic communication (including electronic mail or other electronic means) at the time indicated by the time stamp upon delivery and, if after 5:00 pm, on the next Business Day; or (d) if delivered in person, upon receipt by the receiving Party. Notwithstanding the foregoing, Notices of outages or other scheduling or dispatch information or requests, may be sent by electronic communication and shall be considered delivered upon successful completion of such transmission.
ARTICLE 15
ASSIGNMENT
15.1. General Prohibition on Assignments. No Party may assign this Agreement, or its rights or obligations under this Agreement, without the prior written consent of all other Parties, in each Party’s sole discretion.
ARTICLE 16
GOVERNING LAW AND DISPUTE RESOLUTION
16.1. Governing Law. This Agreement and the rights and duties of the Parties hereunder shall be governed by and construed, enforced, and performed in accordance with the laws of the state of California, without regard to principles of conflicts of Law. To the extent enforceable at such time, each Party waives its respective right to any jury trial with respect to any litigation arising under or in connection with this Agreement. The Parties agree that any suit, action, or other legal proceeding by or against any Party with respect to or arising out of this Agreement shall be brought in the federal or state courts located in the State of California in a location to be mutually chosen by all Parties, or in the absence of mutual agreement, the County of San Francisco. 182
16.2. Dispute Resolution. In the event of any dispute arising under this Agreement, within ten (10) days following the receipt of a Notice from either Party identifying such dispute, the Parties shall meet, negotiate, and attempt, in good faith, to resolve the dispute quickly and informally without significant legal costs. If the Parties are unable to resolve a dispute arising hereunder within thirty (30) days after Notice of the dispute, the Parties may pursue all remedies available to them at Law or in equity.
ARTICLE 17
MISCELLANEOUS
17.1. Entire Agreement; Integration; Exhibits. This Agreement, together with the Exhibits attached hereto constitutes the entire agreement and understanding by and among the Parties with respect to the subject matter hereof and supersedes all prior agreements relating to the subject matter hereof, which are of no further force or effect. The Exhibits attached hereto are integral parts hereof and are made a part of this Agreement by reference. The headings used herein are for convenience and reference purposes only. This Agreement shall be considered for all purposes as prepared through the joint efforts of the Parties and shall not be construed against one Party or the other as a result of the preparation, substitution, submission, or other event of negotiation, drafting or execution hereof.
17.2. Amendments. This Agreement may only be amended, modified, or supplemented by an instrument in writing executed by duly authorized representatives of all Parties; provided, this Agreement may not be amended by electronic mail communications. Any revisions to the Entitlement Share specified in Exhibit B pursuant to Section 4.2. or Section 12.8 shall be considered an element of the administration of this Agreement and shall not require the consent of the Parties hereto.
17.3. No Waiver. Waiver by a Party of any default by the other Party shall not be construed as a waiver of any other default.
17.4. Severability. In the event that any provision of this Agreement is unenforceable or held to be unenforceable, the Parties agree that all other provisions of this Agreement have force and effect and shall not be affected thereby. The Parties shall, however, use their best endeavors to agree on the replacement of the void, illegal or unenforceable provision(s) with legally acceptable clauses which correspond as closely as possible to the sense and purpose of the affected provision and this Agreement as a whole.
17.5. Counterparts. This Agreement may be executed in one or more counterparts, all of which taken together shall constitute one and the same instrument and each of which shall be deemed an original.
17.6. Electronic Delivery. This Agreement may be duly executed and delivered by a Party by electronic format (including portable document format (.pdf)). Delivery of an executed counterpart in .pdf electronic version shall be binding as if delivered in the original. The words “execution,” “signed,” “signature,” and words of like import in this Agreement shall be deemed to include electronic signatures or electronic records, each of which shall be of the same legal effect, 183
validity, or enforceability as a manually executed signature or the use of a paper-based record keeping system, as the case may be, to the extent and as provided for in any applicable law.
17.7. Binding Effect. This Agreement shall inure to the benefit of and be binding upon the Parties and their respective successors and permitted assigns.
17.8. Forward Contract. The Parties acknowledge and agree that this Agreement constitutes a “forward contract” within the meaning of the U.S. Bankruptcy Code, and that the Parties are “forward contract merchants” within the meaning of the U.S. Bankruptcy Code. Each Party further agrees that, for all purposes of this Agreement, each Party waives and agrees not to assert the applicability of the provisions of 11 U.S.C. § 366 in any Bankruptcy proceeding wherein such Party is a debtor. In any such proceeding, each Party further waives the right to assert that the other Party is a provider of last resort to the extent such term relates to 11 U.S.C. §366 or another provision of 11 U.S.C. § 101-1532.
17.9. City of San Francisco Standard Provisions.
(a) False Claims. Pursuant to San Francisco Administrative Code § 21.35, any Party to this Agreement who submits a false claim shall be liable to the City and County of San Francisco for the statutory penalties set forth in that section. A Party will be deemed to have submitted a false claim to the City and County of San Francisco if the Party: (a) knowingly presents or causes to be presented to an officer or employee of the City and County of San Francisco a false claim or request for payment or approval; (b) knowingly makes, uses, or causes to be made or used a false record or statement to get a false claim paid or approved by the City and County of San Francisco; (c) conspires to defraud the City and County of San Francisco by getting a false claim allowed or paid by the City and County of San Francisco; (d) knowingly makes, uses, or causes to be made or used a false record or statement to conceal, avoid, or decrease an obligation to pay or transmit money or property to the City and County of San Francisco; or (e) is a beneficiary of an inadvertent submission of a false claim to the City and County of San Francisco, subsequently discovers the falsity of the claim, and fails to disclose the false claim to the City and County of San Francisco within a reasonable time after discovery of the false claim. (b) Political Activity. In performing its responsibilities under this Agreement, CCP shall comply with San Francisco Administrative Code Chapter 12G, which prohibits funds appropriated by the City and County of San Francisco for this Agreement from being expended to participate in, support, or attempt to influence any political campaign for a candidate or for a ballot measure.
(c) Non-discrimination Requirements.
(i) Non-discrimination in Contracts. CCP shall comply with the provisions of Chapters 12B and 12C of the San Francisco Administrative Code. CCP shall incorporate by reference in all subcontracts the provisions of Sections12B.2(a), 12B.2(c)-(k), and 12C.3 of the San Francisco Administrative Code and shall require all subcontractors to comply with such provisions. CCP is subject to the enforcement and penalty provisions in Chapters 12B and 12C.
184
(ii) Non-discrimination in the Provision of Employee Benefits. San Francisco Administrative Code 12B.2. CCP does not as of the date of this Agreement, and will not during the term of this Agreement, in any of its operations in San Francisco, on real property owned by San Francisco, or where work is being performed for the City elsewhere in the United States, discriminate in the provision of employee benefits between employees with domestic partners and employees with spouses and/or between the domestic partners and spouses of such employees, subject to the conditions set forth in San Francisco Administrative Code Section 12B.2. (d) Consideration of Criminal History in Hiring and Employment Decisions.
CCP agrees to comply fully with and be bound by all of the provisions of Chapter 12T, “City Contractor/Subcontractor Consideration of Criminal History in Hiring and Employment Decisions,” of the San Francisco Administrative Code, including the remedies provided, and implementing regulations, as may be amended from time to time. The requirements of Chapter 12T shall only apply to CCP’s operations to the extent those operations are in furtherance of the performance of this Agreement, shall apply only to applicants and employees who would be or are performing work in furtherance of this Agreement, and shall apply when the physical location of the employment or prospective employment of an individual is wholly or substantially within the City. Chapter 12T shall not apply when the application in a particular context would conflict with federal or state law or with a requirement of a government agency implementing federal or state law. MacBride Principles – Northern Ireland. Pursuant to San Francisco Administrative Code § 12F.5, the City and County of San Francisco urges companies doing business in Northern Ireland to move towards resolving employment inequities, and encourages such companies to abide by the MacBride Principles. The City and County of San Francisco urges San Francisco companies to do business with corporations that abide by the MacBride principles. (e) MacBride Principles – Northern Ireland. Pursuant to San Francisco Administrative Code § 12F.5, the City and County of San Francisco urges companies doing business in Northern Ireland to move towards resolving employment inequities, and encourages such companies to abide by the MacBride Principles. The City and County of San Francisco urges San Francisco companies to do business with corporations that abide by the MacBride Principles. (f) Tropical Hardwood and Virgin Redwood Ban. The City and County of San Francisco urges contractors not to import, purchase, obtain, or use for any purpose, any tropical hardwood, tropical hardwood product, virgin redwood or virgin redwood product. If this order is for wood products or a service involving wood products: (a) Chapter 8 of the Environment Code is incorporated herein and by reference made a part hereof as though fully set forth. (b) Except as expressly permitted by the application of Sections 802(B), 803(B), and 804(B) of the Environment Code, CCP shall not provide any items to the City in performance of this Agreement which are tropical hardwoods, tropical hardwood products, virgin redwood or virgin redwood products. (c) Failure of CCP to comply with any of the requirements of Chapter 8 of the Environment Code shall be deemed a material breach of contract.
17.10. City of San José Standard Provisions.
(a) Nondiscrimination/Non-Preference. The Parties shall not, and shall not cause or allow its subcontractors to, discriminate against or grant preferential treatment to any person on the basis of race, sex, color, age, religion, sexual orientation, actual or perceived gender 185
identity, disability, ethnicity or national origin. This prohibition applies to recruiting, hiring, demotion, layoff, termination, compensation, fringe benefits, advancement, training, apprenticeship and other terms, conditions, or privileges of employment, subcontracting and purchasing. The Parties will inform all subcontractors of these obligations. This prohibition is subject to the following conditions: (i) the prohibition is not intended to preclude Parties from providing a reasonable accommodation to a person with a disability; (ii) the City of San José’s Compliance Officer may require the Parties to file, and cause any Party’s subcontractor to file, reports demonstrating compliance with this section. Any such reports shall be filed in the form and at such times as the City’s Compliance Officer designates. They shall contain such information, data and/or records as the City’s Compliance Officer determines is needed to show compliance with this provision.
(b) Conflict of Interest. The Parties represent that they are familiar with the local and state conflict of interest laws, and agrees to comply with those laws in performing this Agreement. The Parties certify that, as of the Effective Date, are unaware of any facts constituting a conflict of interest or creating an appearance of a conflict of interest. The Parties shall avoid all conflicts of interest or appearances of conflicts of interest in performing this Agreement. The Parties have the obligation of determining if the manner in which it performs any part of this Agreement results in a conflict of interest or an appearance of a conflict of interest, and a Party shall immediately notify the City of San José in writing if it becomes aware of any facts giving rise to a conflict of interest or the appearance of a conflict of interest. A Party’s violation of this Section 17.10(b) is a material breach.
(c) Environmentally Preferable Procurement Policy. Parties shall perform its obligations under this Agreement in conformance with San José City Council Policy 1-19, entitled “Prohibition of City Funding for Purchase of Single serving Bottled Water,” and San José City Council Policy 4-6, entitled “Environmentally Preferable Procurement Policy,” as those policies may be amended from time to time. The Parties acknowledge and agree that in no event shall a breach of this Section 17.10(c) be a material breach of this Agreement or otherwise give rise to an Event of Default or entitle the City of San José to terminate this Agreement. (d) Gifts Prohibited. The Parties represent that they are familiar with Chapter
12.08 of the San José Municipal Code, which generally prohibits a City of San José officer or designated employee from accepting any gift. The Parties shall not offer any City of San José officer or designated employee any gift prohibited by Chapter 12.08. A Party’s violation of this Section 17.10(d) is a material breach.
(e) Disqualification of Former Employees. The Parties represent that they are familiar with Chapter 12.10 of the San José Municipal Code, which generally prohibits a former City of San José officer and former designated employee from providing services to the City of San José connected with his/her former duties or official responsibilities. Parties shall not use either directly or indirectly any officer, employee or agent to perform any services if doing so would violate Chapter 12.10.
17.11. Further Assurances. Each of the Parties hereto agrees to provide such information, execute, and deliver any instruments and documents and to take such other actions as may be necessary or reasonably requested by the other Party which are not inconsistent with the provisions 186
of this Agreement and which do not involve the assumptions of obligations other than those provided for in this Agreement, to give full effect to this Agreement and to carry out the intent of this Agreement.
[Signatures on following page]
187
IN WITNESS WHEREOF, the Parties have caused this Agreement to be duly executed as of the Effective Date.
California Community Power
By:
Name:
Title:
Approved as to form by Counsel
By:
Name:
Title:
Clean Power San Francisco
By:
Name:
Title:
Approved as to form by Counsel
By:
Name:
Title:
Peninsula Clean Energy
By:
Name:
Title:
Approved as to form by Counsel
By:
Name:
Title:
Redwood Coast Energy Authority
By:
Name:
Title:
Approved as to form by Counsel
By:
Name:
Title:
188
San José Clean Energy
By:
Name:
Title:
Approved as to form by Counsel
By:
Name:
Title:
Silicon Valley Clean Energy
By:
Name:
Title:
Approved as to form by Counsel
By:
Name:
Title:
Sonoma Clean Power
By:
Name:
Title:
Approved as to form by Counsel
By:
Name:
Title:
Valley Clean Energy
By:
Name:
Title:
Approved as to form by Counsel
By:
Name:
Title:
189
EXHIBIT A
NOTICES
Party All Notices Invoices
California
Community Power
California Community Power
Tim Haines
____________________
____________________
timhaines@powergridsymmetry
.com
Clean Power San
Francisco
Clean Power San Francisco
Barbara Hale, Assistant General
Manager, Power
San Francisco Public Utilities
Commission
525 Golden Gate Ave, 13th
Floor
San Francisco, CA 94102
[email protected]
Peninsula Clean
Energy
Peninsula Clean Energy
Jan Pepper, CEO
Peninsula Clean Energy
2075 Woodside Road
Redwood City, California 94061
jpepper@peninsulacleanenergy.
com
Redwood Coast
Energy Authority
Redwood Coast Energy
Authority
Matthew Marshall, CEO
Redwood Coast Energy
Authority
633 3rd Street
Eureka, CA 95501
[email protected]
190
Party All Notices Invoices
San José Clean
Energy
San José Clean Energy
Lori Mitchell, Director
cc: Luisa Elkins, Senior Deputy
City Attorney
San José Clean Energy
200 E. Santa Clara Street, 14th
Floor
San José, CA 95113
[email protected]
[email protected]
Silicon Valley Clean
Energy
Silicon Valley Clean Energy
Girish Balachandran, CEO
Silicon Valley Clean Energy
Authority
333 W. El Camino Real, Suite
330
Sunnyvale, CA 94087
[email protected]
Sonoma Clean
Power
Sonoma Clean Power
Geof Syphers, CEO
Sonoma Clean Power
50 Santa Rosa Avenue, 5th Floor
Santa Rosa, CA 95404
[email protected]
rg
Valley Clean
Energy
Valley Clean Energy
Gordon Samuel
Assistant General Manager &
Director of Power Resource
604 2nd Street
Davis, CA 95616
gordon.samuel@valleycleanene
rgy.org
191
EXHIBIT B
SCHEDULE OF PROJECT PARTICIPANT ENTITLEMENT SHARES
AND STEP-UP ALLOCATION CAPS
Dated:________________________
A B C D E
Project Participant
Entitlement Share
As of Effective Date
Entitlement Share
As Modified Pursuant to
Section 4.2
Entitlement Share
As Modified Pursuant to
Section 12.8(b) or 12.8(c)
Step-Up Allocation Cap
125% multiplied by Column B
or C as applicable
Clean Power San Francisco 16.06%
Peninsula Clean Energy 19.69%
Redwood Coast Energy Authority 3.62%
San José Clean Energy 22.28%
Silicon Valley Clean Energy 21.25%
Sonoma Clean Power 12.95%
Valley Clean Energy 4.15%
Total 100%
Instructions: If the CCP Manager modifies one or more Project Participant’s Entitlement Share pursuant to Section 4.2, the CCP Manager shall prepare an updated Exhibit B that shows the prior Entitlement Share (Column B or D) in strikeout and specifies the new Entitlement Share values and the effective date of such modification in Column C. If the CCP Manager modifies one or more Project Participant’s Entitlement Share pursuant to Section 12.8, the CCP Manager shall prepare an updated Exhibit B that shows the prior Entitlement Share (Column B or Column C) in strikeout and specifies the new Entitlement Share values and the effective date of such modification in Column D. 192
EXHIBIT C
PROCEDURE FOR VOLUNTARY REDUCTION OF
PROJECT PARTICIPANT’S ENTITLEMENT SHARE
(a) Offer to Other Project Participants. A Project Participant proposing to reduce its Entitlement Share of the Project shall provide Notice to all other Project Participants and CCP specifying the quantity of the proposed reduction of Entitlement Share (“Entitlement Share Reduction Amount”) and the first Month for which the Project Participant Proposes that the change of Entitlement Share would become effective (such Notice referred to as the “Entitlement Share Reduction Notice”).
(i) Upon receiving an Entitlement Share Reduction Notice from any Project Participant, the CCP Manager shall promptly do all of the following:
(A) Establish Entitlement Share Reduction Compensation
Amount. The CCP Manager shall secure at least one (1), but no more than three (3), valuations of the net present value of the Entitlement Share Reduction Amount over the remaining term of the ESSA from one or more qualified firm(s) with the requisite experience to determine such valuation. The valuation, or if more than one valuation is obtained, the average of all valuations received, shall be the “Proposed Entitlement Share Reduction Compensation Amount.” The CCP Manager shall call a meeting of the Project Committee and present the Proposed Entitlement Share Reduction Compensation Amount to the Project Committee. The Project Committee shall by a Normal Vote either approve the Proposed Entitlement Share Reduction Compensation Amount or direct the CCP Manager to secure additional valuations. The Proposed Entitlement Share Reduction Compensation Amount approved by the Project Committee shall be the “Entitlement Share Reduction Compensation Amount.” The Project Participant proposing to reduce its Entitlement Share may modify the quantity of the Entitlement Share Reduction Amount associated with its proposal or withdraw its proposal at any time prior to the initiation of the process set forth in paragraph (a)(i)(B).
(B) Oversee the Offering of the Entitlement Share Reduction Amount to Other Project Participants. The CCP Manager shall facilitate the offering of the Entitlement Share Reduction Amount to the other Project Participants through multiple rounds of offerings.
a) The initial offering shall be to each Project
Participant on a pro rata share, based on such Project Participant’s Entitlement Share. Each Project Participant may accept or reject the portion of the Entitlement Share Reduction Amount offered to the Project Participant through this process. If any portion of the Entitlement Share Reduction Amount remains after the initial offering, then the remaining portion shall be offered to any Project Participant that accepted the share of the Entitlement Share Reduction Amount offered in the initial offering on a pro rata share, based on such Project Participant’s Entitlement Share as a percentage of the total Entitlement Shares of all Project Participants that accepted the portion of the Entitlement Share Reduction Amount offered to them in the initial offering. 193
b) The CCP Manager shall conduct subsequent offering
rounds until either the total Entitlement Share Reduction Amount is accepted by one or more of the other Project Participants or some portion of the Entitlement Share Reduction Amount remains, but all Project Participants have rejected such amount. c) Any Project Participant accepting a share of the
offered Entitlement Share Reduction Amount shall either pay the offering Project Participant or be compensated by the offering Project Participant at the Entitlement Share Reduction Compensation Amount multiplied by the quantity of the portion being accepted. d) Before a transfer of all or a portion of any Project Participant’s Entitlement share to another Project Participant can become effective, the proposed transfer must be submitted to and approved by the Project Committee through a Normal Vote. e) After acceptance and payment for such portion of the Entitlement Share Reduction Amount, and upon approval of such transfer by the Project Committee, the CCP Manager shall cause the Entitlement Share specified in Exhibit B to be modified accordingly, and such modification shall be considered an element of the administration of this Agreement and shall not require the consent of the Parties hereto. (C) Oversee the Offering of the Entitlement Share Reduction Amount to CCP Members that are not Project Participants. If there is any portion of the Entitlement Share Reduction Amount that remains unaccepted after the process specified in paragraph (a)(i)(B) is complete, then the Project Participant proposing to reduce its Entitlement Share may request that the CCP Manager offer the remaining portion of the Entitlement Share Reduction Amount to CCP Members that are not Project Participants. If any CCP Member wishes to accept any or all of the remaining portion of the Entitlement Share Reduction Amount, such action shall require the CCP Member to become a Project Participant through an amendment to this Agreement, which shall be subject to the consent and approval of all Parties to this Agreement and the CCP Member becoming a Project Participant. The compensation amount associated with the CCP Member accepting the remaining portion of the Entitlement Share Reduction Amount shall be negotiated between the CCP Member and the offering Project Participant. (D) Oversee the Offering of the Entitlement Share Reduction Amount to a Community Choice Aggregator that is not a CCP Member. If there is any portion of the Entitlement Share Reduction Amount that remains unaccepted after the process specified in both paragraphs (a)(i)(B) and (a)(k)(C) is complete, then the Project Participant proposing to reduce its Entitlement Share, may request that the CCP Manager offer the remaining portion of the Entitlement Share Reduction Amount to a community choice aggregator that is not a CCP Member. If any community choice aggregator wishes to accept any or all of the remaining portion of the Entitlement Share Reduction Amount, such action shall require the community choice aggregator to become a CCP Member, and subsequent to becoming a CCP Member, to become a Project Participant through an amendment to this Agreement that is subject to the consent and approval of all Parties to this Agreement and the community choice aggregator becoming a Project Participant. The compensation amount associated with the community choice aggregator accepting the remaining portion of the Entitlement Share Reduction Amount shall be negotiated between the community choice aggregator and the offering Project Participant. 194
EXHIBIT D
PROJECT COMMITTEE OPERATIONS, MEETINGS, AND VOTING
(a) Chairperson of Project Committee. The chairperson of the Project Committee (“Chairperson”) shall be the CCP Manager. The Chairperson shall be responsible for calling and presiding over meetings of the Project Committee in a manner and to the extent permitted by law.
(b) Conducting Meetings. Conducting of Project Committee meetings and actions taken by the Project Committee may be taken by vote given in an assembled meeting, by telephone, by video conferencing, or by any combination thereof, to the extent permitted by law. (c) Calling of Meetings.
(i) The Chairperson may call a meeting of the Project Committee at their discretion.
(ii) The Chairperson shall promptly call a meeting of the Project Committee at the request of any representative of a Project Participant. (d) Unanimous Votes. Certain actions, as designated in Section 6.4(c), require a unanimous affirmative vote by all Project Participants (“Unanimous Vote”). No such vote may be taken unless a representative from every Project Participant is present at the meeting of the Project Committee. If any Project Participant’s Entitlement Share is reduced to zero through the process specified in Exhibit C, such Project Participant shall not be required to be present or be entitled to vote in order for such vote to be a Unanimous Vote. (e) Normal Votes. All actions not designated as requiring unanimous vote, shall proceed pursuant to the “Normal Vote” process set forth in this paragraph (e). (i) Quorum. No Normal Vote of the Project Committee shall be taken unless a representative is present for at least fifty percent (50%) of the total number of Project Participants, without regard to each Project Participant’s Entitlement Share. (ii) Initial Normal Vote. Unless a representative requests an Alternate Normal Vote, pursuant to paragraph (e)(iii), all actions requiring a Normal Vote, as specified in Section 6.4(b) or 6.4(d), shall require an affirmative vote of at least fifty-one percent (51%) of the total number of Project Participants, without regard to each Project Participant’s Entitlement Share.
(iii) Alternate Normal Vote. Any representative may request that any Normal Vote be taken on an Entitlement Share basis (referred to as an “Alternate Normal Vote”).
If a representative requests an Alternate Normal Vote, then the following vote requirements shall apply:
195
(A) If any individual Project Participant has an Entitlement Share exceeding fifty percent (50%), then all actions for which an Alternate Normal Vote is taken shall require that the Project Participant with an Entitlement Share exceeding fifty percent (50%) plus any other Project Participant vote in the affirmative. (B) If no individual Project Participant has an Entitlement Share exceeding fifty percent (50%), then all actions for which an Alternate Normal Vote is taken shall require an affirmative vote of Project Participants having Entitlement Shares aggregating at least fifty-one percent (51%) of the total Entitlement Shares. 196
Execution Version
ENERGY STORAGE SERVICE AGREEMENT
COVER SHEET
Seller: Tumbleweed Energy Storage, LLC, a Delaware limited liability company Buyer: California Community Power, a California joint powers authority Description of Facility: 69 MW/552 MWh grid-connected battery energy storage facility (CAISO Queue 1217) located near Rosamond, Kern County, California, as further described in Exhibit A.
Milestones:
Milestone Expected Date for
Completion
Evidence of Site Control 8/12/2019
Conditional Use Permit obtained
Phase I and Phase II Interconnection study results
obtained 6/1/2018
Interconnection Agreement executed 11/12/2018
Major equipment procured
Federal and state discretionary permits issued
Expected Construction Start Date
Guaranteed Construction Start Date 12/31/2025
Initial Synchronization 4/1/2026
Network Upgrades completed 12/31/2025
Partial Capacity Deliverability Status sufficient to fully deliver the Facility’s Guaranteed Capacity is obtained 3/16/2018 Expected Commercial Operation Date 4/15/2026
Guaranteed Commercial Operation Date 6/1/2026
Delivery Term: 15 Contract Years
Guaranteed Capacity: 69 MW of Installed Capacity at eight (8) hours of continuous discharge Dedicated Interconnection Capacity: 69 MW
197
Guaranteed Efficiency Rate:
Contract Year Guaranteed Efficiency Rate
1-15 83.3%
Contract Price:
Contract Year Contract Price
1 – 15 $ /kW-mo. (flat) with no escalation
and subject to adjustments in Exhibit C
Product:
☒ Discharging Energy
☒ Installed Capacity and Effective Capacity
☒ Ancillary Services
☒ Capacity Attributes
Scheduling Coordinator:
Prior to Commercial Operation Date: Seller
From Commercial Operation Date through the Delivery Term: Buyer Security Amount:
Development Security: $ /kW of Guaranteed Capacity
Performance Security: $ /kW of Guaranteed Capacity
198
TABLE OF CONTENTS
Page
i
TABLE OF CONTENTS
ARTICLE 1 DEFINITIONS .......................................................................................................... 1
1.1 Contract Definitions ............................................................................................... 1
1.2 Rules of Interpretation ......................................................................................... 21 ARTICLE 2 TERM; CONDITIONS PRECEDENT ................................................................... 22
2.1 Contract Term. ..................................................................................................... 22
2.2 Commercial Operation; Conditions Precedent .................................................... 23
2.3 Development; Construction; Progress Reports .................................................... 24
2.4 Remedial Action Plan .......................................................................................... 24
2.5 Pre-Commercial Operation Actions ..................................................................... 25 ARTICLE 3 PURCHASE AND SALE ....................................................................................... 25
3.1 Product ................................................................................................................. 25
3.2 Discharging Energy ............................................................................................. 25
3.3 Capacity Attributes .............................................................................................. 25
3.4 Ancillary Services; Environmental Attributes. .................................................... 26
3.5 Resource Adequacy Failure. ................................................................................ 26
3.6 Buyer’s Re-Sale of Product ................................................................................. 27 ARTICLE 4 OBLIGATIONS AND DELIVERIES .................................................................... 27
4.1 Delivery ................................................................................................................ 27
4.2 Interconnection .................................................................................................... 28
4.3 Performance Guarantees ...................................................................................... 28
4.4 Facility Testing .................................................................................................... 28
4.5 Testing Costs and Revenues ................................................................................ 29
4.6 Facility Operations ............................................................................................... 30
4.7 Dispatch Notices .................................................................................................. 30
4.8 Facility Unavailability to Receive Dispatch Notices ........................................... 30
4.9 Energy Management. ........................................................................................... 31
4.10 Capacity Availability Notice. ............................................................................... 33
4.11 [Reserved]. ........................................................................................................... 33
4.12 Outages ................................................................................................................ 33 ARTICLE 5 TAXES, GOVERNMENTAL AND ENVIRONMENTAL COSTS ...................... 34
5.1 Allocation of Taxes and Charges ......................................................................... 34
5.2 Cooperation .......................................................................................................... 35
5.3 Environmental Costs ............................................................................................ 35 ARTICLE 6 MAINTENANCE AND REPAIR OF THE FACILITY ........................................ 35
6.1 Maintenance of the Facility. ................................................................................ 35
6.2 Maintenance of Health and Safety. ...................................................................... 36
6.3 Shared Facilities. .................................................................................................. 36 ARTICLE 7 METERING ............................................................................................................ 36 199
ii
7.1 Metering. .............................................................................................................. 36
7.2 Meter Verification. ............................................................................................... 37 ARTICLE 8 INVOICING AND PAYMENT; CREDIT ............................................................. 37
8.1 Invoicing .............................................................................................................. 37
8.2 Payment ................................................................................................................ 37
8.3 Books and Records .............................................................................................. 38
8.4 Payment Adjustments; Billing Errors .................................................................. 38
8.5 Billing Disputes ................................................................................................... 38
8.6 Netting of Payments ............................................................................................. 39
8.7 Seller’s Development Security ............................................................................ 39
8.8 Seller’s Performance Security .............................................................................. 39
8.9 First Priority Security Interest in Cash or Cash Equivalent Collateral ................ 39
8.10 Buyer Credit Arrangements ................................................................................. 40 ARTICLE 9 NOTICES ................................................................................................................ 41
9.1 Addresses for the Delivery of Notices ................................................................. 41
9.2 Acceptable Means of Delivering Notice .............................................................. 41 ARTICLE 10 FORCE MAJEURE .............................................................................................. 42
10.1 Definition ............................................................................................................. 42
10.2 No Liability If a Force Majeure Event Occurs .................................................... 43
10.3 Notice ................................................................................................................... 43
10.4 Termination Following Force Majeure Event ...................................................... 43 ARTICLE 11 DEFAULTS; REMEDIES; TERMINATION ...................................................... 43
11.1 Events of Default ................................................................................................. 43
11.2 Remedies; Declaration of Early Termination Date. ............................................. 46
11.3 Damage Payment; Termination Payment ............................................................ 47
11.4 Notice of Payment of Termination Payment or Damage Payment ...................... 48
11.5 Disputes With Respect to Termination Payment or Damage Payment ............... 48
11.6 Limitation on Seller’s Ability to Make or Agree to Third-Party Sales from the Facility after Early Termination Date ............................................................ 48
11.7 Rights And Remedies Are Cumulative ................................................................ 49
11.8 Mitigation ............................................................................................................. 49
11.9 Pass Through of Buyer Liability .......................................................................... 49 ARTICLE 12 LIMITATION OF LIABILITY AND EXCLUSION OF WARRANTIES .......... 49
12.1 No Consequential Damages ................................................................................. 49
12.2 Waiver and Exclusion of Other Damages ............................................................ 49
12.3 Limitation on Pre-COD Liability ......................................................................... 50 ARTICLE 13 REPRESENTATIONS AND WARRANTIES; COVENANTS .......................... 50
13.1 Seller’s Representations and Warranties ............................................................. 50
13.2 Buyer’s Representations and Warranties ............................................................. 51
13.3 General Covenants ............................................................................................... 52
13.4 Seller’s Covenants ............................................................................................... 52 200
iii
ARTICLE 14 ASSIGNMENT ..................................................................................................... 53
14.1 General Prohibition on Assignments ................................................................... 53
14.2 Collateral Assignment .......................................................................................... 54
14.3 Permitted Assignment .......................................................................................... 54
14.4 Portfolio Financing .............................................................................................. 54
14.5 Buyer Financing Assignment ............................................................................... 55 ARTICLE 15 DISPUTE RESOLUTION .................................................................................... 55
15.1 Governing Law. ................................................................................................... 55
15.2 Dispute Resolution. .............................................................................................. 55
15.3 Attorneys’ Fees. ................................................................................................... 55 ARTICLE 16 INDEMNIFICATION ........................................................................................... 55
16.1 Indemnification. ................................................................................................... 55
16.2 Claims. ................................................................................................................. 56 ARTICLE 17 INSURANCE ........................................................................................................ 57
17.1 Insurance .............................................................................................................. 57 ARTICLE 18 CONFIDENTIAL INFORMATION .................................................................... 58
18.1 Definition of Confidential Information ................................................................ 58
18.2 Duty to Maintain Confidentiality ......................................................................... 58
18.3 Irreparable Injury; Remedies ............................................................................... 59
18.4 Further Permitted Disclosure ............................................................................... 60
18.5 Press Releases ...................................................................................................... 60 ARTICLE 19 MISCELLANEOUS ............................................................................................. 60
19.1 Entire Agreement; Integration; Exhibits .............................................................. 60
19.2 Amendments ........................................................................................................ 60
19.3 No Waiver ............................................................................................................ 60
19.4 No Agency, Partnership, Joint Venture or Lease ................................................. 60
19.5 Severability .......................................................................................................... 60
19.6 Mobile-Sierra ....................................................................................................... 61
19.7 Counterparts ......................................................................................................... 61
19.8 Electronic Delivery .............................................................................................. 61
19.9 Binding Effect ...................................................................................................... 61
19.10 No Recourse to Members of Buyer ..................................................................... 61
19.11 Forward Contract ................................................................................................. 61
19.12 Change in Electric Market Design ....................................................................... 62
19.13 Further Assurances ............................................................................................... 62 Exhibits:
Exhibit A Facility Description
Exhibit B Facility Construction and Commercial Operation Exhibit C Compensation
Exhibit D Scheduling Coordinator Responsibilities
201
iv
Exhibit E Progress Reporting Form
Exhibit F Form of Monthly Expected Available Capacity Report Exhibit G Form of Daily Availability Notice
Exhibit H Form of Commercial Operation Date Certificate Exhibit I Form of Capacity and Efficiency Rate Test Certificate Exhibit J Form of Construction Start Date Certificate
Exhibit K Form of Letter of Credit
Exhibit L Form of Buyer Liability Pass Through Agreement Exhibit M Form of Replacement RA Notice
Exhibit N Notices
Exhibit O Capacity and Efficiency Rate Tests
Exhibit P Facility Availability Calculation
Exhibit Q Operating Restrictions
Exhibit R Metering Diagram
Exhibit S [Intentionally Omitted]
Exhibit T Form of Collateral Assignment Agreement
Exhibit U Material Permits
Exhibit V Project Participants and Liability Shares
202
1 ENERGY STORAGE SERVICE AGREEMENT
This Energy Storage Service Agreement (“Agreement”) is entered into as of 01/24/2022 (the “Effective Date”), between Buyer and Seller. Buyer and Seller are sometimes referred to herein individually as a “Party” and jointly as the “Parties.” All capitalized terms used in this Agreement are used with the meanings ascribed to them in Article 1 to this Agreement.
RECITALS
WHEREAS, Seller intends to develop, design, construct, own, and operate the Facility; and
WHEREAS, Seller desires to sell, and Buyer desires to purchase, on the terms and conditions set forth in this Agreement, the Product;
NOW THEREFORE, in consideration of the mutual covenants and agreements herein contained, and for other good and valuable consideration, the sufficiency and adequacy of which are hereby acknowledged, the Parties agree to the following:
ARTICLE 1
DEFINITIONS
1.1 Contract Definitions. The following terms, when used herein with initial capitalization, shall have the meanings set forth below:
“AC” means alternating current.
“Affiliate” means, with respect to any Person, each Person that directly or indirectly controls, is controlled by, or is under common control with such designated Person. For purposes of this definition and the definition of “Permitted Transferee”, “control” (including, with correlative meanings, the terms “controlled by” and “under common control with”), as used with respect to any Person, shall mean (a) the direct or indirect right to cast at least fifty percent (50%) of the votes exercisable at an annual general meeting (or its equivalent) of such Person or, if there are no such rights, ownership of at least fifty percent (50%) of the equity or other ownership interest in such Person, or (b) the right to direct the policies or operations of such Person.
Notwithstanding the foregoing, the Parties hereby agree and acknowledge that with respect to Buyer the public entities designated as members or participants under the Joint Powers Agreement creating Buyer shall not constitute or otherwise be deemed an “Affiliate” for purposes of this Agreement.
“Agreement” has the meaning set forth in the Preamble and includes the Cover Sheet and any Exhibits, schedules and any written supplements hereto. “Ancillary Services” means frequency regulation, spinning reserve, non-spinning reserve, regulation up, regulation down, voltage support, and any other ancillary services, in each case that the Facility is capable of providing consistent with the Operating Restrictions set forth in Exhibit Q, as each is defined in the CAISO Tariff.
203
2 “Approved Maintenance Hours” means up to per Contract Year of Planned Outages for Facility maintenance scheduled in accordance with Section 4.12. “Automated Dispatch System” or “ADS” has the meaning set forth in the CAISO Tariff. “Automatic Generation Control” or “AGC” has the meaning set forth in the CAISO Tariff.
“Availability Adjustment” has the meaning set forth in Exhibit C. “Availability Notice” has the meaning set forth in Section 4.10. “Availability Standards” has the meaning set forth in the CAISO Tariff or such other similar term as modified and approved by FERC hereafter to be incorporated in the CAISO Tariff. “Available Capacity” means the capacity of the Facility, expressed in whole MWs, that is mechanically available to charge and discharge Energy and provide Ancillary Services. “Bankrupt” or “Bankruptcy” means with respect to any entity, such entity that (a) files a petition or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause of action under any bankruptcy, insolvency, reorganization or similar Law, (b) has any such petition filed or commenced against it which remains unstayed or undismissed for a period of ninety (90) days, (c) makes an assignment or any general arrangement for the benefit of creditors, (d) otherwise becomes bankrupt or insolvent (however evidenced), (e) has a liquidator, administrator, receiver, trustee, conservator or similar official appointed with respect to it or any substantial portion of its property or assets, or (f) is generally unable to pay its debts as they fall due.
“Battery Charging Factor” means a fraction, the numerator of which is the amount of Charging Energy absorbed by the Facility after the first ten (10) hours of the charging phase of the applicable Capacity Test, and the denominator of which is the Effective Capacity. “Battery Discharging Factor” means one (1) minus a fraction, the numerator of which is the amount of Discharging Energy discharged during the first eight (8) hours of the discharging phase of the applicable Capacity Test, and the denominator of which is the Effective Capacity. “Business Day” means any day except a Saturday, Sunday, or a Federal Reserve Bank holiday in California. A Business Day begins at 8:00 a.m. and ends at 5:00 p.m. local time for the Party sending a Notice, or payment, or performing a specified action. “Buyer” has the meaning set forth on the Cover Sheet.
“Buyer Default” means an Event of Default of Buyer.
“Buyer Dispatched Test” has the meaning in Section 4.4(c). “Buyer’s Indemnified Parties” has the meaning set forth in Section 16.1(a). 204
3 “Buyer Liability Pass Through Agreement” means the form set forth in Exhibit L. “CAISO” means the California Independent System Operator Corporation or any successor entity performing similar functions.
“CAISO Balancing Authority Area” has the meaning set forth in the CAISO Tariff. “CAISO Certification” means the certification and testing requirements for a storage unit set forth in the CAISO Tariff that are applicable to the Facility, including certification and testing for all Ancillary Services that the Facility can provide, PMAX, and PMIN associated with such storage units, that are applicable to the Facility.
“CAISO Charges Invoice” has the meaning set forth in Exhibit D. “CAISO Dispatch” means any Charging Notice or Discharging Notice given by the CAISO to the Facility, whether through ADS, AGC or any successor communication protocol, communicating an Ancillary Service Award (as defined in the CAISO Tariff) or directing the Facility to charge or discharge at a specific MW rate for a specified period of time or amount of MWh.
“CAISO Grid” has the same meaning as “CAISO Controlled Grid” as defined in the CAISO Tariff.
“CAISO Tariff” means the California Independent System Operator Corporation Agreement and Tariff, Business Practice Manuals (BPMs), and Operating Procedures, as the same may be amended or modified from time-to-time and approved by FERC. “California Renewables Portfolio Standard” or “RPS” means the renewable energy program and policies established by California State Senate Bills 1038 (2002), 1078 (2002), 107 (2008), X-1 2 (2011), 350 (2015), and 100 (2018) as codified in, inter alia, California Public Utilities Code Sections 399.11 through 399.31 and California Public Resources Code Sections 25740 through 25751, as such provisions are amended or supplemented from time to time. “CEC” means the California Energy Commission, or any successor agency performing similar functions.
“Capacity Attribute” means any current or future defined characteristic, certificate, tag, credit, or accounting construct associated with the ability of the Facility to charge, discharge and deliver to the Delivery Point at a particular moment and that can be purchased, sold or conveyed under CAISO or CPUC market rules, including Resource Adequacy Benefits. “Capacity Damages” has the meaning set forth in Section 5 of Exhibit B. “Capacity Test” or “CT” means any test or retest of the Facility to establish the Installed Capacity, Effective Capacity or Efficiency Rate or, subject to the qualifications set forth in Exhibit O, any other test conducted pursuant to Exhibit O.
205
4 “CEQA” means the California Environmental Quality Act, as amended or supplemented from time to time.
“Change of Control” means, except in connection with public market transactions of equity interests or capital stock of Seller’s Ultimate Parent, any circumstance in which Ultimate Parent ceases to own, directly or indirectly through one or more intermediate entities, more than fifty percent (50%) of the outstanding equity interests in Seller; provided, in calculating ownership percentages for all purposes of the foregoing:
(a) any ownership interest in Seller held by Ultimate Parent indirectly through one or more intermediate entities shall not be counted towards Ultimate Parent’s ownership interest in Seller unless Ultimate Parent directly or indirectly owns more than fifty percent (50%) of the outstanding equity interests in each such intermediate entity; and (b) ownership interests in Seller owned directly or indirectly by any Lender (including any tax equity provider) shall be excluded from the total outstanding equity interests in Seller. “Charging Energy” means the Energy delivered to the Facility pursuant to a Charging Notice as measured at the Facility Metering Point by the Facility Meter, as such meter readings are adjusted by the CAISO for any applicable Electrical Losses. All Charging Energy not consumed in Electrical Losses or used for Station Use shall be used solely to charge the Facility. “Charging Notice” means the operating instruction, and any subsequent updates, given by Buyer’s SC or the CAISO to Seller, directing the Facility to charge at a specific MW rate for a specified period of time or amount of MWh; provided, any such operating instruction shall be in accordance with the Operating Restrictions. Any instruction to charge the Storage Facility pursuant to a Buyer Dispatched Test shall be considered a Charging Notice. “Collateral Assignment Agreement” has the meaning set forth in Section 14.2 and substantially in the form attached as Exhibit T.
“Commercial Operation” means the condition existing when Seller has fulfilled all of the conditions precedent in Section 2.2 of the Agreement and provided Notice of the same to Buyer; provided, Commercial Operation shall occur no sooner than the Expected Commercial Operation Date.
“Commercial Operation Capacity Test” means the Capacity Test conducted in connection with Commercial Operation of the Facility, including any additional Capacity Test for additional capacity installed after the Commercial Operation Date pursuant to Section 5 of Exhibit B.
“Commercial Operation Date” or “COD” means the later of (a) the Expected Commercial Operation Date or (b) the date on which Commercial Operation is achieved. “Commercial Operation Delay Damages” means an amount equal to (a) the Development Security amount required hereunder, divided by (b) ninety (90). 206
5 “Communications Protocols” means certain Operating Restrictions developed by the Parties pursuant to Exhibit Q that involve procedures and protocols regarding communication with respect to the operation of the Facility pursuant to this Agreement. “Compliant Project Participant” means a Project Participant that is not a Defaulted Project Participant.
“Confidential Information” has the meaning set forth in Section 18.1. “Construction Start” has the meaning set forth in Exhibit B. “Construction Start Date” has the meaning set forth in Exhibit B. “Contract Price” has the meaning set forth on the Cover Sheet. “Contract Term” has the meaning set forth in Section 2.1(a). “Contract Year” means a period of twelve (12) consecutive months (plus, in the case of the first Contract Year only, if the Commercial Operation Date does not occur on the first day of a calendar month, the period from the Commercial Operation Date through the end of the calendar month in which the Commercial Operation Date occurs). The first Contract Year shall commence on the Commercial Operation Date and each subsequent Contract Year shall commence on the anniversary of the Commercial Operation Date or, if the Commercial Operation Date does not occur on the first day of a calendar month, the anniversary of the first day of the first full calendar month following the Commercial Operation Date.
“Costs” means, with respect to the Non-Defaulting Party, brokerage fees, commissions and other similar third-party transaction costs and expenses reasonably incurred by such Party either in terminating any arrangement pursuant to which it has hedged its obligations or entering into new arrangements which replace the Agreement; and all reasonable attorneys’ fees and expenses incurred by the Non-Defaulting Party in connection with terminating the Agreement. “Cover Sheet” means the cover sheet to this Agreement, which is incorporated into this Agreement.
“CPM Soft Offer Cap” has he meaning set forth in the CAISO Tariff. “CPUC” means the California Public Utilities Commission, or any successor entity performing similar functions.
“Credit Rating” means, with respect to any entity, the rating then assigned to such entity’s unsecured, senior long-term debt obligations (not supported by third party credit enhancements) or if such entity does not have a rating for its senior unsecured long-term debt, then the rating then assigned to such entity as an issuer rating by S&P or Moody’s. If ratings by S&P and Moody’s are not equivalent, the lower rating shall apply.
“Cure Plan” has the meaning set forth in Section 11.1(b)(iii). 207
6 “Curtailment Order” means any of the following:
(a) CAISO orders, directs, alerts, or provides notice to a Party, including a CAISO Operating Order, to curtail deliveries of Discharging Energy for the following reasons: (i) any System Emergency, or (ii) any warning of an anticipated System Emergency, or warning of an imminent condition or situation, which jeopardizes CAISO’s electric system integrity or the integrity of other systems to which CAISO is connected; (b) a curtailment ordered by the Transmission Provider for reasons including, but not limited to, (i) any situation that affects normal function of the electric system including, but not limited to, any abnormal condition that requires action to prevent circumstances such as equipment damage, loss of load, or abnormal voltage conditions, or (ii) any warning, forecast or anticipation of conditions or situations that jeopardize the Transmission Provider’s electric system integrity or the integrity of other systems to which the Transmission Provider is connected; (c) a curtailment ordered by CAISO or the Transmission Provider due to a Transmission System Outage; or
(d) a curtailment in accordance with Seller’s obligations under its Interconnection Agreement with the Transmission Provider or distribution operator. “Cycles” means the number of equivalent charge/discharge cycles of the Facility during a specified time period, which shall be deemed to be equal to (a) the total cumulative amount of Discharging Energy discharged from the Facility (expressed in MWh) divided by (b) eight (8) hours times the weighted average Effective Capacity for such time period. “Daily Delay Damages” means an amount equal to (a) the Development Security amount required hereunder, divided by (b) one hundred twenty (120). “Damage Payment” means the amount to be paid by the Defaulting Party to the Non-Defaulting Party after a Terminated Transaction occurring prior to the Commercial Operation Date, in a dollar amount set forth in Section 11.3(a).
“Day-Ahead Market” has the meaning set forth in the CAISO Tariff. “Day-Ahead Schedule” has the meaning set forth in the CAISO Tariff. “Dedicated Interconnection Capacity” means the maximum instantaneous amount of Charging Energy and/or Discharging Energy, as applicable, that is permitted to be delivered from and/or to the Delivery Point under Seller’s Interconnection Agreement, in the amount of MWs as set forth on the Cover Sheet.
“Defaulted Liability Share” means the Liability Share of a Defaulted Project Participant. “Defaulted Project Participant” means a Project Participant that has incurred but not cured a Project Participant Payment Default, including any Project Participant whose rights under the Project Participation Share Agreement have been suspended or terminated. 208
7 “Defaulting Party” has the meaning set forth in Section 11.1(a). “Delivery Point” means the Facility Pnode on the CAISO grid. “Delivery Term” shall mean the period of Contract Years set forth on the Cover Sheet beginning on the Commercial Operation Date, unless terminated earlier in accordance with the terms and conditions of this Agreement.
“Development Cure Period” has the meaning set forth in Exhibit B. “Development Security” means (a) cash or (b) a Letter of Credit in the amount set forth on the Cover Sheet.
“Discharging Energy” means the Energy delivered from the Facility to the Delivery Point pursuant to a Discharging Notice during any Settlement Interval or Settlement Period, as measured at the Facility Metering Point by the Facility Meter, as such meter readings are adjusted by the CAISO for any applicable Electrical Losses.
“Discharging Notice” means the operating instruction, and any subsequent updates, given by Buyer’s SC or the CAISO to the Facility, directing the Facility to discharge Discharging Energy at a specific MW rate for a specified period of time or to an amount of MWh. Any instruction to discharge the Storage Facility pursuant to a Buyer Dispatched Test shall be considered a Discharging Notice.
“Disclosing Party” has the meaning set forth in Section 18.2. “Dispatch Notice” means any Charging Notice, Discharging Notice and any subsequent updates thereto, given by the CAISO, Buyer or Buyer’s SC, to Seller, directing the Facility to charge or discharge Energy at a specific MWh rate, for a specified period of time, and/or to a specified Storage Level; provided, any such operating instruction or updates shall be in accordance with the Operating Restrictions.
“Early Termination Date” has the meaning set forth in Section 11.2(a). “Effective Capacity” means the lesser of (a) PMAX, and (b) maximum dependable operating capacity of the Facility to discharge Energy for eight (8) hours of continuous discharge, as measured in MW AC at the Delivery Point (i.e., measured at the Facility Meter and adjusted for Electrical Losses to the Delivery Point) as determined pursuant to the most recent Capacity Test (including the Commercial Operation Capacity Test), and as evidenced by a certificate substantially in the form attached as Exhibit I hereto, in either case (a) or (b) up to but not in excess of (i) the Guaranteed Capacity (with respect to a Commercial Operation Capacity Test) or (ii) the Installed Capacity (with respect to any other Capacity Test). “Effective Date” has the meaning set forth on the Preamble. “Effective Flexible Capacity” or “EFC” has the meaning set forth in the CAISO Tariff. 209
8 “Efficiency Rate” means the tested rate calculated pursuant to Sections II.I(2) and III(A) of Exhibit O by dividing Discharging Energy by Charging Energy and which for a given calendar month shall be prorated as necessary if more than one Efficiency Rate test has been conducted in such calendar month and different tested Efficiency Rates apply during such calendar month. “Efficiency Rate Adjustment” has the meaning set forth in Exhibit C. “Electrical Losses” means all transmission or transformation losses (a) between the Delivery Point and the Facility Metering Point associated with delivery of Charging Energy, and (b) between the Facility Metering Point and the Delivery Point associated with delivery of Discharging Energy.
“Emission Reduction Credits” or “ERCs” means emission reductions that have been authorized by a local air pollution control district pursuant to California Division 26 Air Resources; Health and Safety Code Sections 40709 and 40709.5, whereby a district has established a system by which all reductions in the emission of air contaminants that are to be used to offset certain future increases in the emission of air contaminants shall be banked prior to use to offset future increases in emissions.
“Energy” means electrical energy, measured in kilowatt-hours, megawatt-hours, or multiple units thereof.
“Energy Management System” or “EMS” means the Facility’s energy management system.
“Environmental Attributes” shall mean any and all attributes under the RPS regulations or under any and all other international, federal, regional, state or other law, rule, regulation, bylaw, treaty or other intergovernmental compact, decision, administrative decision, program (including any voluntary compliance or membership program), competitive market or business method (including all credits, certificates, benefits, and emission measurements, reductions, offsets and allowances related thereto) that are attributable, now, or in the future to the Facility and its displacement of conventional energy generation. “Environmental Attributes” do not include (i) Tax Credits or other tax benefits or attributes, including any cash payments in lieu thereof, (ii) any governmental grants, subsidies or other incentive payments related to the construction, ownership or operation of the Facility, or (iii) any Emission Reduction Credits or Marketable Emission Trading Credits.
“Environmental Cost” means costs incurred in connection with acquiring and maintaining all environmental permits and licenses for the Facility, and the Facility’s compliance with all applicable environmental laws, rules and regulations, including capital costs for pollution mitigation or installation of emissions control equipment required to permit or license the Facility, all operating and maintenance costs for operation of pollution mitigation or control equipment, costs of permit maintenance fees and emission fees as applicable, the costs of all Emission Reduction Credits or Marketable Emission Trading Credits required by any applicable environmental laws, rules, regulations, and permits to operate the Facility, and the costs associated with the disposal and clean-up of hazardous substances introduced to the Site, and the 210
9 decontamination or remediation, on or off the Site, necessitated by the introduction of such hazardous substances on the Site.
“Event of Default” has the meaning set forth in Section 11.1. “Excused Event” has the meaning set forth in Exhibit P. “Expected Commercial Operation Date” means the date set forth on the Cover Sheet. “Facility” means the energy storage facility described on the Cover Sheet and in Exhibit A, located at the Site and including mechanical equipment and associated facilities and equipment required to deliver Product (but excluding any Shared Facilities), as such storage facility may be expanded or otherwise modified from time to time in accordance with the terms hereof. “Facility Meter” means a CAISO-approved bi-directional revenue quality meter or meters (with a 0.3% accuracy class), CAISO-approved data processing gateway or remote intelligence gateway, telemetering equipment and data acquisition services sufficient for monitoring, recording and reporting, in real time, the amount of Charging Energy delivered to the Facility Metering Point and the amount of Discharging Energy delivered to the Delivery Point for the purpose of invoicing in accordance with Section 8.1. The Facility may contain multiple measurement devices that will make up the Facility Meter, and, unless otherwise indicated, references to the Facility Meter shall mean all such measurement devices and the aggregated data of all such measurement devices, taken together.
“Facility Metering Point” means the location(s) of the Facility Meter shown in Exhibit R. “Federal Investment Tax Credit Legislation” means validly enacted federal legislation that either (a) applies the ITC in its current form to the Facility, or (b) extends federal Tax Credits associated with capital investment in the construction of energy storage facilities or equipment used to store energy for which Seller, as the owner of the Facility, is eligible. “FERC” means the Federal Energy Regulatory Commission or any successor government agency.
“Flexible Capacity” has the meaning set forth in the CAISO Tariff. “Flexible RAR” means the flexible capacity requirements established for load-serving entities by the CAISO pursuant to the CAISO Tariff, the CPUC pursuant to the Resource Adequacy Rulings, or by any other Governmental Authority.
“Forced Labor” has the meaning set forth in Section 13.4(c). “Force Majeure Event” has the meaning set forth in Section 10.1. “Full Capacity Deliverability Status” or “FCDS” has the meaning set forth in the CAISO Tariff.
211
10 “Gains” means, with respect to any Party, an amount equal to the present value of the economic benefit to it, if any (exclusive of Costs), resulting from the termination of this Agreement for the remaining Contract Term, determined in a commercially reasonable manner. Factors used in determining the economic benefit to a Party may include, without limitation, reference to information supplied by one or more third parties, which shall exclude Affiliates of the Non-Defaulting Party, including without limitation, quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets, comparable transactions, forward price curves based on economic analysis of the relevant markets, settlement prices for comparable transactions at liquid trading hubs (e.g., NP-15), all of which should be calculated for the remaining Contract Term, and include the value of Capacity Attributes.
“GHG Regulations” means Title 17, Division 3 (Air Resources), Chapter 1 (Air Resources Board), Subchapter 10 (Climate Change), Article 5 (Emissions Cap), Sections 95800 to 96023 of the California Code of Regulations, as amended or supplemented from time to time. “Governmental Authority” means any federal, state, provincial, local or municipal government, any political subdivision thereof or any other governmental, congressional or parliamentary, regulatory, or judicial instrumentality, authority, body, agency, department, bureau, or entity with authority to bind a Party at law, including CAISO; provided, “Governmental Authority” shall not in any event include any Party.
“Greenhouse Gas” or “GHG” has the meaning set forth in the GHG Regulations or in any other applicable Laws.
“Guaranteed Availability” has the meaning set forth in Section 4.3(a).
Guaranteed Amount” has the meaning set forth in each Project Participant’s Buyer Liability Pass Through Agreement, which amount may be different for each Project Participant given each Project Participant’s Liability Share.
“Guaranteed Capacity” means the maximum dependable operating capability of the Facility to discharge electric energy, as measured in MW AC at the Delivery Point for eight (8) hours of continuous discharge, as set forth on the Cover Sheet. “Guaranteed Commercial Operation Date” means the date set forth on the Cover Sheet, as such date may be extended pursuant to Exhibit B.
“Guaranteed Construction Start Date” means the date set forth on the Cover Sheet, as such date may be extended pursuant to Exhibit B.
“Guaranteed Efficiency Rate” means the minimum guaranteed Efficiency Rate of the Facility in each Contract Year of the Delivery Term, as set forth on the Cover Sheet. “Guaranteed Flexible Capacity” means, at any point in time, the maximum quantity of Flexible Capacity (in MWs) for which a storage facility having a storage capacity of 69 MW with eight (8) hours of continuous discharging at the maximum rate of discharge, having achieved PCDS sufficient to fully deliver the Facility’s Guaranteed Capacity, and performing with 212
11 operational characteristics equal to those required by the Guaranteed Availability, Guaranteed Efficiency Rate, and the Operating Restrictions may be counted in any given Showing Month pursuant to the then current Law, including counting conventions set forth in the Resource Adequacy Rulings and the CAISO Tariff applicable to Resource Adequacy Resources. “Guaranteed Net Qualifying Capacity” means, at any point in time, the maximum quantity of Net Qualifying Capacity (in MWs) for which a storage facility having a storage capacity of 69 MW with eight (8) hours of continuous discharging at the maximum rate of discharge, having achieved PCDS sufficient to fully deliver the Facility’s Guaranteed Capacity, and performing with operational characteristics equal to those required by the Guaranteed Availability, Guaranteed Efficiency Rate, and the Operating Restrictions may be counted in any given Showing Month pursuant to the then current Law, including counting conventions set forth in the Resource Adequacy Rulings and the CAISO Tariff applicable to Resource Adequacy Resources.
“Hazardous Substance” means, collectively, (a) any chemical, material or substance that is listed or regulated under applicable Laws as a “hazardous” or “toxic” substance or waste, or as a “contaminant” or “pollutant” or words of similar import, (b) any petroleum or petroleum products, flammable materials, explosives, radioactive materials, asbestos, urea formaldehyde foam insulation, and transformers or other equipment that contain polychlorinated biphenyls, and (c) any other chemical or other material or substance, exposure to which is prohibited, limited or regulated by any Laws.
“Imbalance Energy” means the amount of Energy in MWh, in any given Settlement Period or Settlement Interval, by which the amount of Charging Energy or Discharging Energy, as applicable, deviates from the amount of Scheduled Energy. “Indemnified Party” shall mean (i) Buyer, with respect to all third-party claims, demands, losses, liabilities, penalties, and expenses arising out of, resulting from, or caused by the circumstances described in Section 16.1(a), and (ii) Seller, with respect to all third-party claims, demands, losses, liabilities, penalties, and expenses arising out of, resulting from, or caused by the circumstances described in Section 16.1(b).
“Indemnifying Party” shall mean (i) Seller, with respect to all third-party claims, demands, losses, liabilities, penalties, and expenses arising out of, resulting from, or caused by the circumstances described in Section 16.1(a), and (ii) Buyer, with respect to all third-party claims, demands, losses, liabilities, penalties, and expenses arising out of, resulting from, or caused by the circumstances described in Section 16.1(b).
“Initial Liability Share” means the Liability Share of each Project Participant shown on Exhibit V as of the Effective Date.
“Initial Synchronization” means the commencement of Trial Operations (as defined in the CAISO Tariff).
“Installed Capacity” means the lesser of (a) PMAX, and (b) maximum dependable operating capacity of the Facility to discharge Energy for eight (8) hours of continuous discharge, as measured in MW AC at the Facility Meter Point by the Facility Meter and adjusted for Electrical 213
12 Losses to the Delivery Point, that achieves Commercial Operation, as evidenced by a certificate substantially in the form attached as Exhibit I hereto, as such capacity may be adjusted pursuant to Section 5 of Exhibit B, but in either case (a) or (b) up to but not in excess of the Guaranteed Capacity.
“Inter-SC Trade” has the meaning set forth in the CAISO Tariff. “Interconnection Agreement” means the interconnection agreement entered into by Seller or a Seller Affiliate pursuant to which the Facility will be interconnected with the Transmission System, and pursuant to which Seller’s Interconnection Facilities and any other Interconnection Facilities will be constructed, operated and maintained during the Contract Term. “Interconnection Facilities” means the interconnection facilities, control and protective devices and metering facilities required to connect the Facility with the Transmission System in accordance with the Interconnection Agreement.
“Interconnection Point” has the meaning set forth in Exhibit A. “Interest Rate” has the meaning set forth in Section 8.2. “ITC” means the investment tax credit established pursuant to Section 48 or other applicable provisions of the United States Internal Revenue Code of 1986. “Joint Powers Act” means the Joint Exercise of Powers Act of the State of California (Government Code Section 6500 et seq.).
“Joint Powers Agreement” means that certain Joint Powers Agreement dated January 29, 2021, as amended from time to time, under which Buyer is organized as a Joint Powers Authority in accordance with the Joint Powers Act.
“kWh” means a kilowatt-hour measured in alternating current, unless expressly stated in terms of direct current.
“Law” means any applicable law, statute, rule, regulation, decision, writ, order, decree or judgment, permit or any interpretation thereof, promulgated or issued by a Governmental Authority.
“Lender” means, collectively, any Person (a) providing senior or subordinated construction, interim, back leverage or long-term debt, equity or tax equity financing or refinancing for or in connection with the development, construction, purchase, installation or operation of the Facility, whether that financing or refinancing takes the form of private debt (including back-leverage debt), equity (including tax equity), public debt or any other form (including financing or refinancing provided to a member or other direct or indirect owner of Seller), including any equity or tax equity investor directly or indirectly providing financing or refinancing for the Facility or purchasing equity ownership interests of Seller and/or its Affiliates, and any trustee or agent or similar representative acting on their behalf, (b) providing interest rate or commodity protection under an agreement hedging or otherwise mitigating the cost of any of 214
13 the foregoing obligations and/or (c) participating in a lease financing (including a sale leaseback or leveraged leasing structure) with respect to the Facility. “Letter(s) of Credit” means one or more irrevocable, standby letters of credit issued by a U.S. commercial bank or a foreign bank with a U.S. branch with such bank (a) having a Credit Rating of at least A- with an outlook designation of “stable” from S&P or A3 with an outlook designation of “stable” from Moody’s or (b) being reasonably acceptable to Buyer, in a form substantially similar to the letter of credit set forth in Exhibit K. “Liability Share” means the percentage amount set forth for each Project Participant in Exhibit V.
“Licensed Professional Engineer” means an independent, professional engineer selected by Seller and reasonably acceptable to Buyer, licensed in the State of California. “Local Capacity Area Resource” has the meaning set forth in the CAISO Tariff. “Local RAR” means the local Resource Adequacy Requirements established for load-serving entities by the CAISO pursuant to the CAISO Tariff, the CPUC pursuant to the Resource Adequacy Rulings, or by any other Governmental Authority. “Local RAR” may also be known as local area reliability, local resource adequacy, local resource adequacy procurement requirements, or local capacity requirement in other regulatory proceedings or legislative actions. “Losses” means, with respect to any Party, an amount equal to the present value of the economic loss to it, if any (exclusive of Costs), resulting from termination of this Agreement for the remaining Contract Term, determined in a commercially reasonable manner. Factors used in determining economic loss to a Party may include, without limitation, reference to information supplied by one or more third parties, which shall exclude Affiliates of the Non-Defaulting Party, including without limitation, quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets, comparable transactions, forward price curves based on economic analysis of the relevant markets, settlement prices for comparable transactions at liquid trading hubs (e.g., NP-15), all of which should be calculated for the remaining Contract Term and must include the value of Capacity Attributes.
Seller’s lost revenue under this Agreement resulting from a Buyer Default shall not be considered to be consequential, incidental, punitive, exemplary or indirect or business interruption damages for purposes of determining Losses under this Agreement. “Marketable Emission Trading Credits” means emissions trading credits or units pursuant to the requirements of California Division 26 Air Resources; Health & Safety Code Section 39616 and Section 40440.2 for market-based incentive programs such as the South Coast Air Quality Management District’s Regional Clean Air Incentives Market, also known as RECLAIM, and allowances of sulfur dioxide trading credits as required under Title IV of the Federal Clean Air Act (42 U.S.C. § 7651b (a) to (f)).
“Master File” has the meaning set forth in the CAISO Tariff. “Material Permits” means all permits required for Seller to commence construction, as set forth on Exhibit U.
215
14 “Maximum Charging Capacity” means the highest level at which the Facility may be charged, expressed in MW and as set forth in Exhibit Q. “Maximum Discharging Capacity” means the highest level at which the Facility may be discharged, expressed in MW and as set forth in Exhibit Q. “Milestones” means the development activities for significant permitting, interconnection, and construction milestones set forth on the Cover Sheet. “Monthly Capacity Availability” has the meaning set forth in Exhibit P. “Monthly Capacity Payment” means the payment required to be made by Buyer to Seller each month of the Delivery Term as compensation for the Product, as calculated in accordance with Exhibit C.
“Moody’s” means Moody’s Investors Service, Inc., or its successor. “Most Offer Obligations” means the obligations to offer the Net Qualifying Capacity in order to satisfy Resource Adequacy Requirements, including under Section 40.6 of the CAISO Tariff.
“MW” means megawatts in alternating current, unless expressly stated in terms of direct current.
“MWh” means megawatt-hour measured in alternating current, unless expressly stated in terms of direct current.
“NERC” means the North American Electric Reliability Corporation, or any successor entity performing similar functions.
“Net Qualifying Capacity” or “NQC” has the meaning set forth in the CAISO Tariff. “Network Upgrades” has the meaning set forth in the CAISO Tariff. “Non-Defaulting Party” has the meaning set forth in Section 11.2. “Notice” shall, unless otherwise specified in the Agreement, mean written communications by a Party to be delivered by hand delivery, United States mail, overnight courier service, or electronic messaging (e-mail).
“Notification Deadline” in respect of a Showing Month shall be fifteen (15) days before the relevant deadlines for the corresponding RA Compliance Showings for such Showing Month. “NP-15” means the Existing Zone Generation Trading Hub for Existing Zone region NP15 as set forth in the CAISO Tariff.
“Operating Restrictions” means those restrictions, rules, requirements, and procedures set forth in Exhibit Q.
216
15 “Outage Schedule” has the meaning set forth in Section 4.12(a)(i). “Partial Capacity Deliverability Status” or “PCDS” has the meaning set forth in the CAISO Tariff.
“Party” has the meaning set forth in the Preamble.
“Payment Demand” has the meaning set forth in Exhibit L. “Performance Guarantees” has the meaning set forth in Section 4.3(b). “Performance Security” means (i) cash or (ii) a Letter of Credit in the amount set forth on the Cover Sheet.
“Permitted Transferee” means (i) any Affiliate of Seller or (ii) any entity that satisfies, or is controlled by another Person that satisfies, the following requirements:
(a) A tangible net worth of not less than one hundred fifty million dollars ($150,000,000) or a Credit Rating of at least BBB- from S&P or Baa3 from Moody’s; and (b) At least two (2) years of experience in the ownership and operations of energy generation or storage facilities similar to the Facility or has retained a third-party with such experience to operate the Facility.
“Person” means any individual, sole proprietorship, corporation, limited liability company, limited or general partnership, joint venture, association, joint-stock company, trust, incorporated organization, institution, public benefit corporation, unincorporated organization, government entity or other entity.
“Planned Outage” means a period during which the Facility is either in whole or in part not capable of providing service due to planned maintenance that has been scheduled in advance in accordance with Section 4.12(a).
“PMAX” means the applicable CAISO-certified maximum operating level of the Facility. “PMIN” means the applicable CAISO-certified minimum operating level of the Facility. “PNode” has the meaning set forth in the CAISO Tariff.
“Portfolio” means the portfolio of electrical energy generating, electrical energy storage, or other assets and entities, including the Facility (or the interests of Seller or Seller’s Affiliates or the interests of their respective direct or indirect parent companies), that is pledged as collateral security in connection with a Portfolio Financing.
“Portfolio Financing” means any debt incurred by an Affiliate of Seller that is secured only by a Portfolio.
“Portfolio Financing Entity” means any Affiliate of Seller that incurs debt in connection with any Portfolio Financing.
217
16 “Prevailing Wage Requirement” has the meaning set forth in Section 13.4(b). “Product” has the meaning set forth on the Cover Sheet. “Progress Report” means a progress report including the items set forth in Exhibit E. “Project Labor Agreement” has the meaning set forth in Section 13.4(b). “Project Participant” means each Person identified in Exhibit V that shall execute a Buyer Liability Pass Through Agreement in the form set forth in Exhibit L. “Project Participant Approval” means each Project Participant has obtained all necessary approvals from its board or governing authority necessary to execute a Buyer Liability Pass Through Agreement and the Project Participation Share Agreement, and that Buyer has delivered to Seller Buyer Liability Pass Through Agreements and the Project Participation Share Agreement executed by each Project Participant and countersigned by Buyer. “Project Participation Share Agreement” means that certain Tumbleweed Energy Storage Project Participation Share Agreement executed by and among Buyer and all of the Project Participants relating to their allocation among themselves of Buyer’s responsibilities and liabilities under this Agreement, and any successor agreement.
“Project Participant Payment Default” means any failure by a Project Participant to pay any material amount under the Project Participation Share Agreement as and when due (without giving effect to any extensions of time, waivers or late notices), including monthly amounts collected to fund, or to reserve funds for, payment of Buyer’s obligations under this Agreement. “Pro Rata” means, for purposes of calculating a Project Participant’s Revised Liability Share, the ratio of (i) such Project Participant’s Initial Liability Share to (ii) the sum of the Initial Liability Shares of all of the Compliant Project Participants. “Prudent Operating Practice” means (a) the applicable practices, methods and acts required by or consistent with applicable Laws and reliability criteria, and otherwise engaged in or approved by a significant portion of the electric industry during the relevant time period with respect to grid-interconnected, utility-scale energy storage facilities in the Western United States, and (b) any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Prudent Operating Practice is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to acceptable practices, methods or acts generally accepted in the industry with respect to grid-interconnected, utility-scale energy storage facilities in the Western United States. Prudent Operating Practice shall include compliance with applicable Laws, applicable safety and reliability criteria, and the applicable criteria, rules and standards promulgated in the National Electric Safety Code and the National Electrical Code, as they may be amended or superseded from time to time, including the criteria, rules and standards of any successor organizations.
“Qualifying Capacity” has the meaning set forth in the CAISO Tariff. 218
17 “RA Compliance Showing” means the (a) System RAR compliance or advisory showings (or similar or successor showings) and (b) Flexible RAR compliance or advisory showings (or similar successor showings), in each case, an entity is required to make to the CAISO pursuant to the CAISO Tariff, to the CPUC (and, to the extent authorized by the CPUC, to the CAISO) pursuant to the Resource Adequacy Rulings, or to any Governmental Authority. “RA Deficiency Amount” means the liquidated damages payment that Seller shall pay to Buyer for an applicable RA Shortfall Month, as calculated in accordance with Section 3.5(b). “RA Guarantee Date” means the Commercial Operation Date, which is the date by which the Facility is expected to have achieved Partial Capacity Deliverability Status sufficient to fully deliver the Facility’s Guaranteed Capacity.
“RA Penalties” means the RA penalties assessed against load serving entities by the CPUC for RA deficiencies that are not replaced or cured, as established by the CPUC in the Resource Adequacy Rulings and subsequently incorporated into the annual Filing Guide for System, Local and Flexible Resource Adequacy Compliance Filings that is issued by the CPUC Energy Division, or any replacement or successor documentation established by the CPUC Energy Division to reflect RA penalties that are established by the CPUC and assessed against load serving entities for RA deficiencies.
“RA Shortfall Month” means any Showing Month, commencing with the Showing Month that contains the RA Guarantee Date, during which either:
(a) the Facility has not achieved PCDS sufficient to fully deliver the Facility’s Guaranteed Capacity; or
(b) the Net Qualifying Capacity of the Facility for such Showing Month was either (i) not published by or otherwise established with the CAISO by the Notification Deadline for such Showing Month, or (ii) was less than the then applicable Guaranteed Net Qualifying Capacity of the Facility for such Showing Month; or
(c) the Effective Flexible Capacity of the Facility for such Showing Month was either (i) not published by or otherwise established with the CAISO by the Notification Deadline for such Showing Month, or (ii) was less than the then applicable Guaranteed Flexible Capacity of the Facility for such Showing Month.
“Real-Time Market” has the meaning set forth in the CAISO Tariff. “Receiving Party” has the meaning set forth in Section 18.2. “Reliability Network Upgrades” has the meaning set forth in the CAISO Tariff. “Remedial Action Plan” has the meaning in Section 2.4.
“Replacement RA” means Resource Adequacy Benefits, if any, (a) equivalent to those that would have been provided by the Facility with respect to the applicable month in which a RA 219
18 Deficiency Amount is due to Buyer, unless Buyer consents to accept Replacement RA from another facility, and (b) located within the CAISO Balancing Authority Area. “Requested Confidential Information” has the meaning set forth in Section 18.2. “Resource Adequacy Benefits” means the rights and privileges attached to the Facility that satisfy any entity’s Resource Adequacy Requirements, as those obligations are set forth in any ruling issue by the CPUC, including the Resource Adequacy Rulings, or the CAISO Tariff, and shall include Flexible Capacity, and any local, zonal or otherwise locational attributes associated with the Facility.
“Resource Adequacy Capacity” or “RA Capacity” has the meaning set forth in the CAISO Tariff.
“Resource Adequacy Requirements” or “RAR” means the resource adequacy requirements applicable to an entity as established by the CAISO pursuant to the CAISO Tariff, by the CPUC pursuant to the Resource Adequacy Rulings, or by any other Governmental Authority.
“Resource Adequacy Resource” shall have the meaning used in Resource Adequacy Rulings.
“Resource Adequacy Rulings” means CPUC Decisions 04-01-050, 04-10-035, 05-10-042, 06-04-040, 06-06-064, 06-07-031, 07-06-029, 08-06-031, 09-06-028, 10-06-036, 11-06-022, 12-06-025, 13-06-024, 14-06-050, 15-06-063, 16-06-045, 17-06-027, 18-06-030, 18- 06-031, 19-02-022, 19-06-026, 19-10-021, 20-01-004, 20-03-016, 20-06-002, 20-06-031, 20-06- 028, 20-12-006 and any other existing or subsequent ruling or decision, or any other resource adequacy laws, rules or regulations enacted, adopted or promulgated by the CPUC or the CAISO, however described, as such decisions, rulings, Laws, rules or regulations may be amended or modified from time-to-time throughout the Contract Term. “Revised Liability Share” means the sum of a Project Participant’s Initial Liability Share plus its Pro Rata portion of all Defaulted Liability Shares, not to exceed one hundred twenty-five percent (125%) of such Participant’s Initial Liability Share. “S&P” means the Standard & Poor’s Financial Services, LLC (a subsidiary of S&P Global Inc.) or its successor.
“SCADA Systems” means the standard supervisory control and data acquisition systems to be installed by Seller as part of the Facility, including those system components that enable Seller to receive ADS and AGC instructions from the CAISO or similar instructions from Buyer’s SC.
“Schedule” has the meaning set forth in the CAISO Tariff, and “Scheduled” and “Scheduling” have a corollary meaning.
“Scheduled Energy” means the Charging Energy or Discharging Energy, as applicable, that clears under the applicable CAISO market based on the final Day-Ahead Schedule, FMM 220
19 Schedule (as defined in the CAISO Tariff), and/or any other financially binding Schedule, market instruction or CAISO dispatch for the Facility for a given period of time implemented in accordance with the CAISO Tariff.
“Scheduling Coordinator” or “SC” means an entity certified by the CAISO as qualifying as a Scheduling Coordinator pursuant to the CAISO Tariff for the purposes of undertaking the functions specified in “Responsibilities of a Scheduling Coordinator,” of the CAISO Tariff, as amended from time to time.
“Security Interest” has the meaning set forth in Section 8.9. “Seller” has the meaning set forth on the Cover Sheet.
“Seller’s Indemnified Parties” has the meaning set forth in Section 16.1(b). “Seller Initiated Test” has the meaning set forth in Section 4.4(c). “Settlement Amount” means the Non-Defaulting Party’s Costs and Losses, on the one hand, netted against its Gains, on the other. If the Non-Defaulting Party’s Costs and Losses exceed its Gains, then the Settlement Amount shall be an amount owing to the Non-Defaulting Party. If the Non-Defaulting Party’s Gains exceed its Costs and Losses, then the Settlement Amount shall be zero dollars ($0). The Settlement Amount shall not include consequential, incidental, punitive, exemplary or indirect or business interruption damages for purposes of this Agreement, except to the extent that Seller’s lost revenue under this Agreement resulting from a Buyer Default may be included in the determination of Losses.
“Settlement Interval” has the meaning set forth in the CAISO Tariff. “Settlement Period” has the meaning set forth in the CAISO Tariff. “Shared Facilities” means the gen-tie lines, transformers, substations, or other equipment, permits, contract rights, and other assets and property (real or personal), in each case, as necessary to enable delivery of Discharging Energy to the Delivery Point, including the Interconnection Facilities and the Interconnection Agreement itself, if applicable, that are used in common with third parties or by Seller for electric generation or storage facilities owned by Seller other than the Facility.
“Showing Month” shall be a calendar month of the Delivery Term, commencing with the Showing Month that contains the RA Guarantee Date, that is the subject of a RA Compliance Showing, as set forth in the Resource Adequacy Rulings and outlined in the CAISO Tariff. For illustrative purposes only, pursuant to the CAISO Tariff and Resource Adequacy Rulings in effect as of the Effective Date, the monthly RA Compliance Showing made in June is for the Showing Month of August.
“Site” means the real property on which the Facility is or will be located, as further described in Exhibit A, and as shall be updated by Seller at the time Seller provides an executed Construction Start Date certificate in the form of Exhibit J to Buyer; provided, that any such update to the Site that includes real property that was not originally contained within the Site boundaries 221
20 described in Exhibit A shall be subject to Buyer’s approval of such updates in its sole discretion. “Site” does not include any land rights or interests in the real property constituting the Site that relate to or are used by other projects constructed or owned by Seller or its Affiliates. “Site Control” means that, for the Contract Term, Seller (or, prior to the Delivery Term, its Affiliate): (a) owns or has the option to purchase the Site; (b) is the lessee or has the option to lease the Site; or (c) is the holder of an easement or an option for an easement, right-of-way grant, or similar instrument with respect to the Site.
“State of Charge” or “SOC” means the ratio of (a) the Storage Level of the Facility to (b) the Effective Capacity multiplied by eight (8) hours, expressed as a percentage. “Station Use” means the Energy that is used within the Facility to power the lights, motors, temperature control systems, control systems and other electrical loads that are necessary for operation of the Facility (or as otherwise defined by the retail energy provider and CAISO Tariff) except during periods in which the Storage Facility is charging or discharging pursuant to a Charging Notice or Discharging Notice.
“Step-Up Event” means the forty-fifth (45th) day following the occurrence of a Project Participant Payment Default if such Project Participant Payment Default has not been cured by that date, regardless of whether or not notice was given to the Defaulted Project Participant under the Project Participation Share Agreement or otherwise or by Buyer hereunder. “Storage Level” means, at a particular time, the amount of electric Energy in the Facility available to be discharged as Discharging Energy, expressed in MWh. “Subsequent Purchaser” means the purchaser or recipient of Product from Buyer in any conveyance, re-sale or remarketing of Product by Buyer. “Supplementary Capacity Test Protocol” has the meaning set forth in Exhibit O. “Supply Plan” has the meaning set forth in the CAISO Tariff. “System Emergency” means any condition that requires, as determined and declared by CAISO or the Transmission Provider, automatic or immediate action to (i) prevent or limit harm to or loss of life or property, (ii) prevent loss of transmission facilities or generation supply in the immediate vicinity of the Facility, or (iii) to preserve Transmission System reliability. “System RAR” means the Resource Adequacy Requirements established for load-serving entities by the CAISO pursuant to the CAISO Tariff, the CPUC pursuant to the Resource Adequacy Rulings, or by any other Governmental Authority. “System RAR” may also be known as system area reliability, system resource adequacy, system resource adequacy procurement requirements, or system capacity requirement in other regulatory proceedings or legislative actions. “Tax” or “Taxes” means all U.S. federal, state and local and any foreign taxes, levies, assessments, surcharges, duties and other fees and charges of any nature imposed by a Governmental Authority, whether currently in effect or adopted during the Contract Term, including ad valorem, excise, franchise, gross receipts, import/export, license, property, sales and 222
21 use, stamp, transfer, payroll, unemployment, income, and any and all items of withholding, deficiency, penalty, additions, interest or assessment related thereto. “Tax Credits” means any (i) federal production tax credit, depreciation benefit, tax deduction and/or investment tax credit, including the ITC, specific to investments in renewable energy facilities and/or energy storage facilities and (ii) any refundable credit, grant, or other cash payment in lieu of an incentive described in clause (i). “Terminated Transaction” has the meaning set forth in Section 11.2(a). “Termination Payment” has the meaning set forth in Section 11.3(b). “Transmission Provider” means any entity that owns, operates and maintains transmission or distribution lines and associated facilities and/or has entitlements to use certain transmission or distribution lines and associated facilities for the purpose of transmitting or transporting the Discharging Energy from the Delivery Point. “Transmission System” means the transmission facilities operated by the CAISO, now or hereafter in existence, which provide energy transmission service downstream from the Delivery Point.
“Transmission System Outage” means an outage on the Transmission System, other than a System Emergency, that is not caused by Seller’s actions or inactions and that prevents Buyer or the CAISO (as applicable) from receiving Facility Energy onto the Transmission System. “Ultimate Parent” means Rev Renewables, LLC, a Delaware limited liability company. “Unplanned Outage” means a period during which the Facility is not capable of providing service due to the need to maintain or repair a component thereof, which period is not a Planned Outage.
1.2 Rules of Interpretation. In this Agreement, except as expressly stated otherwise or unless the context otherwise requires:
(a) headings and the rendering of text in bold and italics are for convenience and reference purposes only and do not affect the meaning or interpretation of this Agreement; (b) words importing the singular include the plural and vice versa and the masculine, feminine and neuter genders include all genders; (c) the words “hereof”, “herein”, and “hereunder” and words of similar import shall refer to this Agreement as a whole and not to any particular provision of this Agreement; (d) a reference to an Article, Section, paragraph, clause, Party, or Exhibit is a reference to that Article, Section, paragraph, clause of, or that Party or Exhibit to, this Agreement unless otherwise specified;
223
22 (e) a reference to a document or agreement, including this Agreement shall mean such document, agreement or this Agreement including any amendment or supplement to, or replacement, novation or modification of this Agreement, but disregarding any amendment, supplement, replacement, novation or modification made in breach of such document, agreement or this Agreement;
(f) a reference to a Person includes that Person’s successors and permitted assigns;
(g) the terms “include” and “including” mean “include or including (as applicable) without limitation” and any list of examples following such term shall in no way restrict or limit the generality of the word or provision in respect of which such examples are provided;
(h) references to any statute, code or statutory provision are to be construed as a reference to the same as it may have been, or may from time to time be, amended, modified or reenacted, and include references to all bylaws, instruments, orders and regulations for the time being made thereunder or deriving validity therefrom unless the context otherwise requires; (i) in the event of a conflict, a mathematical formula or other precise description of a concept or a term shall prevail over words providing a more general description of a concept or a term;
(j) references to any amount of money shall mean a reference to the amount in United States Dollars;
(k) the expression “and/or” when used as a conjunction shall connote “any or all of”;
(l) words, phrases or expressions not otherwise defined herein that (i) have a generally accepted meaning in Prudent Operating Practice shall have such meaning in this Agreement or (ii) do not have well known and generally accepted meaning in Prudent Operating Practice but that have well known and generally accepted technical or trade meanings, shall have such recognized meanings; and
(m) each Party acknowledges that it was represented by counsel in connection with this Agreement and that it or its counsel reviewed this Agreement and that any rule of construction to the effect that ambiguities are to be resolved against the drafting party shall not be employed in the interpretation of this Agreement.
ARTICLE 2
TERM; CONDITIONS PRECEDENT
2.1 Contract Term.
(a) The term of this Agreement shall commence on the Effective Date and shall remain in full force and effect until the conclusion of the Delivery Term, subject to any early termination provisions set forth herein, including Section 2.1(b) (“Contract Term”); provided, 224
23 Buyer’s obligations to pay for or accept any Product are subject to Seller’s completion of the conditions precedent pursuant to Section 2.2.
(b) Notwithstanding anything to the contrary in this Agreement, if Project Participant Approval of this Agreement is not obtained within ninety (90) days following the Effective Date, then either Party may terminate this Agreement upon written Notice to the other Party. Upon such termination, neither Party shall have any liability to the other Party, save and except for those obligations specified in Section 2.1(c), and Buyer shall promptly return to Seller any Development Security then held by Buyer, if any, less any amounts drawn in accordance with this Agreement.
(c) Applicable provisions of this Agreement shall continue in effect after termination, including early termination, to the extent necessary to enforce or complete the duties, obligations or responsibilities of the Parties arising prior to termination. The confidentiality obligations of the Parties under Article 18 shall remain in full force and effect for two (2) years following the termination of this Agreement, and all indemnity and audit rights shall remain in full force and effect for three (3) years following the termination of this Agreement.
2.2 Commercial Operation; Conditions Precedent. Seller shall provide Notice to Buyer of the expected Commercial Operation Date at least sixty (60) days in advance of such date.
Seller shall provide Notice to Buyer when Seller believes it has provided the required documentation to Buyer and met all the conditions precedent set forth below for achieving Commercial Operation. Following Buyer’s receipt of such Notice, Buyer shall have five (5) Business Days to approve or reject Seller’s request for confirmation of Commercial Operation, which, if confirmed, shall be deemed to have occurred as of the date of such Notice. Upon Buyer’s approval of Seller’s achievement of Commercial Operation, Buyer shall provide Seller with written acknowledgement of the Commercial Operation Date. (a) Seller shall have delivered to Buyer (i) a completion certificate from a Licensed Professional Engineer substantially in the form of Exhibit H and (ii) a certificate from a Licensed Professional Engineer substantially in the form of Exhibit I setting forth the Installed Capacity and Efficiency Rate on the Commercial Operation Date; (b) Seller has executed an Interconnection Agreement with the Transmission Provider, which shall be in full force and effect and a copy of the Interconnection Agreement delivered to Buyer;
(c) Seller has provided Buyer with a copy of written notice from CAISO that the Facility has achieved Partial Capacity Deliverability Status sufficient to fully deliver the Facility’s Guaranteed Capacity, if applicable;
(d) A Participating Generator Agreement and a Meter Service Agreement between Seller and CAISO shall have been executed and delivered and be in full force and effect, and a copy of each such agreement delivered to Buyer;
(e) Seller has obtained CAISO Certification for the Facility;The Facility has successfully completed all testing required by Prudent Operating Practice or any requirement of Law to operate the Facility;
225
24 (f) All applicable regulatory authorizations, approvals and permits for the operation of the Facility have been obtained and all conditions thereof that are capable of being satisfied on the Commercial Operation Date have been satisfied and shall be in full force and effect;
(g) Seller has Site Control;
(h) Seller has delivered the Performance Security to Buyer in accordance with Section 8.8;
(i) Insurance requirements for the Facility have been met, with evidence provided in writing to Buyer, in accordance with Section 17.1; and (j) Seller has paid Buyer for all amounts owing under this Agreement, if any, including Daily Delay Damages and Commercial Operation Delay Damages.
2.3 Development; Construction; Progress Reports. Within fifteen (15) days after the close of (i) each calendar quarter from the first calendar quarter following the Effective Date until the Construction Start Date, and (ii) each calendar month from the first calendar month following the Construction Start Date until the Commercial Operation Date, Seller shall provide to Buyer a Progress Report and agrees to regularly scheduled meetings between representatives of Buyer and Seller to review such reports and discuss Seller’s construction progress. The form of the Progress Report is set forth in Exhibit E. Seller shall also provide Buyer with any reasonably requested documentation (subject to confidentiality restrictions) directly related to the achievement of Milestones within ten (10) Business Days of receipt of such request by Seller. Seller is solely responsible for the design and construction of the Facility, including the location of the Site, the Facility layout, and the selection and procurement of the equipment comprising the Facility.
2.4 Remedial Action Plan. If Seller misses a Milestone by more than thirty (30) days, except as the result of Force Majeure Event or Buyer Default, Seller shall submit to Buyer, within ten (10) Business Days of the end of such thirty (30)-day period following the Milestone completion date, a remedial action plan (“Remedial Action Plan”), which will describe in detail any delays (actual or anticipated) beyond the scheduled Milestone dates, including the cause of the delay (e.g., governmental approvals, financing, property acquisition, design activities, equipment procurement, project construction, interconnection, or any other factor), Seller’s detailed description of its proposed course of action to achieve the missed Milestones and all subsequent Milestones by the Guaranteed Commercial Operation Date; provided, delivery of any Remedial Action Plan shall not relieve Seller of its obligation to provide Remedial Action Plans with respect to any subsequent Milestones and to achieve the Guaranteed Commercial Operation Date in accordance with the terms of this Agreement. Subject to the provisions of Exhibit B, so long as Seller complies with its obligations under this Section 2.4, Seller shall not be considered in default of its obligations under this Agreement solely as a result of missing any Milestone; provided, in the event Seller misses any Milestone and Seller provides Notice to Buyer that it is not likely to be able to achieve the Commercial Operation Date by the Guaranteed Commercial Operation Date as may be extended pursuant to Exhibit B, Buyer shall have the right to terminate this Agreement and retain the Development Security as liquidated damages and as its exclusive remedy, and neither Party shall have any further liability under this Agreement arising after the date of 226
25 termination. Such termination right must be exercised, if at all, within ten (10) Business Days after Buyer’s receipt of Seller’s Notice that it is not likely to be able to achieve the Commercial Operation Date by the Guaranteed Commercial Operation Date (as may be extended pursuant to Exhibit B).
2.5 Pre-Commercial Operation Actions. The Parties agree that, in order for Buyer to dispatch the Facility for its Commercial Operation Date, the Parties will have to perform certain of their Delivery Term obligations in advance of the Commercial Operation Date, including, without limitation, Seller’s delivery of an Availability Notice for the Commercial Operation Date, and delivery of a Dispatch Notice and nominating and scheduling the Facility for the Commercial Operation Date, in advance of the Commercial Operation Date. The Parties shall cooperate with each other in order for Buyer to be able to dispatch the Facility for the Commercial Operation Date. In addition, Seller shall have the right to operate the Facility prior to the Commercial Operation Date, so long as such operation does not interfere with Seller’s ability to perform its obligations under this Agreement from and after the Commercial Operation Date.
ARTICLE 3
PURCHASE AND SALE
3.1 Product. Subject to the terms and conditions of this Agreement, during the Delivery Term, Buyer shall have the exclusive right to the Installed Capacity and Effective Capacity, as applicable, and all Product associated therewith. Seller has all rights to the Installed Capacity and Effective Capacity, as applicable, and all Product associated therewith and after the Delivery Term. Seller shall operate the Facility and make available, charge and discharge, deliver, and sell the Product therefrom to Buyer when and as the Facility is available, subject to the terms and conditions of this Agreement, including the Operating Restrictions. Seller represents and warrants that it will deliver the Product to Buyer free and clear of all liens, security interests, claims and encumbrances. Seller shall not substitute or purchase any energy storage capacity, Energy, Ancillary Services or Capacity Attributes from any other energy storage resource or the market for delivery hereunder except as otherwise provided herein, nor shall Seller sell, assign or otherwise transfer any Product, or any portion thereof, to any third party other than to Buyer or the CAISO pursuant to this Agreement.
3.2 Discharging Energy. Subject to the terms and conditions of this Agreement, Seller commits to make available the Discharging Energy to Buyer during the Delivery Term, and Buyer shall have the exclusive rights to all such Discharging Energy, subject to the Operating Restrictions. Title to and risk of loss related to the Discharging Energy shall pass and transfer from Seller to Buyer at the Delivery Point.
3.3 Capacity Attributes. Seller shall request Partial Capacity Deliverability Status sufficient to fully deliver the Facility’s Guaranteed Capacity in the CAISO generator interconnection process. As between Buyer and Seller, Seller shall be responsible for the cost and installation of any Network Upgrades associated with obtaining such Partial Capacity Deliverability Status.
(a) Throughout the Delivery Term, Seller grants, pledges, assigns and otherwise commits to Buyer all the Capacity Attributes from the Facility. 227
26 (b) Throughout the Delivery Term, Seller shall maintain Partial Capacity Deliverability Status sufficient to fully deliver the Facility’s Guaranteed Capacity for the Facility from the CAISO and shall perform all actions necessary to ensure that the Facility qualifies to provide Resource Adequacy Benefits, including Flexible Capacity, to Buyer. Throughout the Delivery Term, Seller hereby covenants and agrees to transfer all Resource Adequacy Benefits from the Facility to Buyer.
(c) For the duration of the Delivery Term, Seller shall take all commercially reasonable actions, including complying with all applicable registration and reporting requirements, and execute all documents or instruments necessary to enable Buyer to use all of the Capacity Attributes committed by Seller to Buyer pursuant to this Agreement.
3.4 Ancillary Services; Environmental Attributes.
(a) Ancillary Services. Buyer shall have the exclusive rights to all Ancillary Services that the Facility is capable of providing during the Delivery Term consistent with the Operating Restrictions, with characteristics and quantities determined in accordance with the CAISO Tariff. Seller shall operate and maintain the Facility throughout the Contract Term so as to be able to provide such Ancillary Services in accordance with the specifications set forth in the Facility’s initial CAISO Certification associated with the Installed Capacity. Upon Buyer’s reasonable request, Seller shall submit the Facility for additional CAISO Certification so that the Facility may provide additional Ancillary Services that the Facility is, at the relevant time, actually physically capable of providing consistent with the definition of Ancillary Services herein and without modification of the Facility, provided that Buyer has agreed to reimburse Seller for any costs Seller incurs in connection with conducting such additional CAISO Certification. (b) Environmental Attributes. Buyer shall have the exclusive rights during the Delivery Term to any Environmental Attributes existing on the Effective Date or that may come into existence during the Contract Term. Buyer shall bear all costs and risks associated with the transfer, qualification, verification, registration and ongoing compliance for such Environmental Attributes. Upon Seller’s receipt of Notice from Buyer of Buyer’s intent to claim such Environmental Attributes, the Parties shall determine the necessary actions and additional costs associated with such Environmental Attributes. Seller shall have no obligation to bear any costs, losses or liability, or alter the Facility, unless the Parties in their discretion have agreed on all necessary terms and conditions relating to such alteration and Buyer has agreed to reimburse Seller for all costs, losses, and liabilities associated with such alteration.
3.5 Resource Adequacy Failure.
(a) RA Deficiency Determination. For each RA Shortfall Month, Seller shall pay to Buyer as liquidated damages the RA Deficiency Amount, as set forth in Section 3.5(b), and/or provide Replacement RA, as set forth in Section 3.5(c), as the exclusive remedy for the Capacity Attributes that Seller failed to convey to Buyer. (b) RA Deficiency Amount Calculation. For each RA Shortfall Month, Seller shall pay to Buyer an amount (the “RA Deficiency Amount”) equal to the product of:
(i) The greater of:
228
229
28 commencing on the Commercial Operation Date through the end of the Contract Term, Seller shall supply and deliver the Product to Buyer at the Delivery Point, and Buyer shall take delivery of the Product at the Delivery Point in accordance with the terms of this Agreement. Seller shall be responsible for paying or satisfying when due any costs or charges imposed in connection with the delivery of Discharging Energy to the Delivery Point, including any operation and maintenance charges imposed by the Transmission Provider directly relating to the Facility’s operations. Buyer shall be responsible for all costs, charges and penalties, if any, imposed in connection with the delivery of Discharging Energy at and after the Delivery Point, including without limitation transmission costs and transmission line losses and imbalance charges. Commencing as of the Commercial Operation Date, the Charging Energy and Discharging Energy will be scheduled to the CAISO by Buyer in accordance with Exhibit D.
(b) Seller shall be permitted to reduce deliveries of applicable Products during periods of Planned Outages, Unplanned Outages, Force Majeure Events and Curtailment Orders and as necessary to maintain health and safety pursuant to Section 6.2.
4.2 Interconnection. Seller shall be responsible for all costs of interconnecting the Facility to the Interconnection Point. During the Delivery Term, Seller shall maintain the Dedicated Interconnection Capacity for the Facility’s sole use.
4.3 Performance Guarantees.
(a) During the Delivery Term, the Facility shall maintain a Monthly Capacity Availability during each month of no less than (the “Guaranteed Availability”), which Monthly Capacity Availability shall be calculated in accordance with Exhibit P.
(b) During the Delivery Term, the Facility shall maintain an Efficiency Rate of no less than Guaranteed Efficiency Rate, which Efficiency Rate shall be calculated in accordance with Exhibit O. The Guaranteed Availability and Guaranteed Efficiency Rate are collectively the “Performance Guarantees”.
(c) Buyer’s sole remedies for Seller’s failure to achieve the Performance Guarantees are: (i) for the Guaranteed Availability, (1) the Availability Adjustment to the Monthly Capacity Payment, as set forth in Exhibit C, and (2) the Seller Event of Default as set forth in Section 11.1(b)(iii) and the applicable remedies set forth in Article 11; and (ii) for the Guaranteed Efficiency Rate, the Efficiency Rate Adjustment to the Monthly Capacity Payment, as set forth in Exhibit C.
4.4 Facility Testing.
(a) Capacity Tests. Prior to the Commercial Operation Date, Seller shall schedule and complete a Commercial Operation Capacity Test in accordance with Exhibit O.
Thereafter, Seller and Buyer shall have the right to run additional Capacity Tests in accordance with Exhibit O.
(i) Buyer shall have the right to send one or more representative(s) to witness all Capacity Tests.
230
29 (ii) Following each Capacity Test, Seller shall submit a testing report in accordance with Exhibit O. If the actual capacity or efficiency rate determined pursuant to a Capacity Test varies from the then-current Effective Capacity and/or Efficiency Rate, as applicable, then the actual capacity and/or efficiency rate determined pursuant to such Capacity Test shall become the new Effective Capacity and/or Efficiency Rate, at the beginning of the day following the completion of the test for all purposes under this Agreement. (b) Additional Testing. Seller shall conduct such additional testing as necessary to ensure the Facility is functioning properly and the Facility is able to respond to Dispatch Notices pursuant to Section 4.6(b).
(c) Any testing of the Facility requested by Buyer after the Commercial Operation Capacity Tests, and all required annual tests pursuant to Section B of the section headed “Capacity Test Notice and Frequency” in Exhibit O, shall be deemed Buyer-instructed dispatches of the Facility (“Buyer Dispatched Test”). Any test of the Facility that is not a Buyer Dispatched Test, including all tests conducted prior to Commercial Operation, any Commercial Operation Capacity Test, any Capacity Test conducted if the Effective Capacity immediately prior to such Capacity Test is below , any test required by
CAISO (including any test required to obtain or maintain CAISO Certification), and other Seller-requested discretionary tests or dispatches, at times and for durations reasonably agreed to by Buyer, that Seller deems necessary for purposes of reliably operating or maintaining the Facility or for re-performing a required test within a reasonable number of days of the initial required test (considering the circumstances that led to the need for a retest) shall be deemed a “Seller Initiated Test”.
(i) For any Seller Initiated Test other than a Capacity Test required by Exhibit O for which there is a stated notice requirement, Seller shall notify Buyer no later than twenty-four (24) hours prior thereto (or any shorter period reasonably acceptable to Buyer consistent with Prudent Operating Practices).
(ii) No Dispatch Notices shall be issued during any Seller Initiated Test.
Dispatch Notices may be issued during a Buyer Dispatched Test as reasonably necessary to implement the applicable test. The Facility shall be deemed unavailable during any Seller Initiated Test. Any Buyer Dispatched Test shall be deemed an Excused Event for the purposes of calculating the Monthly Capacity Availability.
4.5 Testing Costs and Revenues.
(a) Buyer shall be responsible for paying for all Charging Energy and shall be entitled to all CAISO revenues associated with a Buyer Dispatched Test. Seller shall be responsible for paying for all Energy to charge the Facility and shall be entitled to all CAISO revenues associated with a Seller Initiated Test. Buyer shall pay to Seller, in the month following Buyer’s receipt of such CAISO revenues and otherwise in accordance with Exhibit C, all applicable CAISO revenues received by Buyer and associated with the discharge Energy associated with such Seller Initiated Test.
231
30 (b) Buyer shall be responsible for all costs, expenses and fees payable or reimbursable to its representative(s) witnessing any Facility test. (c) Except as set forth in Sections 4.5(a) and (b), all other costs of any testing of the Facility shall be borne by Seller.
4.6 Facility Operations.
(a) Seller shall operate the Facility in accordance with Prudent Operating Practices.
(b) During the Delivery Term, Seller shall maintain SCADA Systems, communications links, and other equipment necessary to receive automated Dispatch Notices consistent with CAISO protocols and practice (“Automated Dispatches”). In the event of the failure or inability of the Facility to receive Automated Dispatches, Seller shall use all commercially reasonable efforts to repair or replace the applicable components as soon as reasonably possible, and if there is any material delay in such repair or replacement, Seller shall provide Buyer with a written plan of all actions Seller plans to take to repair or replace such components for Buyer’s review and comment. During any period during which the Facility is not capable of receiving or implementing Automated Dispatches, Seller shall implement back-up procedures consistent with the CAISO Tariff and CAISO protocols to enable Seller to receive and implement non-automated Dispatch Notices (“Alternative Dispatches”). (c) Seller shall maintain a daily operations log for the Facility which shall include but not be limited to information on Energy charging and discharging, electricity consumption and efficiency (if applicable), availability, outages, changes in operating status, inspections and any other significant events related to the operation of the Facility. Information maintained pursuant to this Section 4.6(c) shall be provided to Buyer within fifteen (15) days of Buyer’s request.
(d) Seller shall maintain accurate records with respect to all Capacity Tests. (e) Seller shall maintain and make available to Buyer records, including logbooks, demonstrating that the Facility is operated in accordance with Prudent Operating Practices. Seller shall comply with all reporting requirements and permit on-site audits, investigations, tests and inspections permitted or required under any Prudent Operating Practices.
4.7 Dispatch Notices. Buyer shall have the right to dispatch the Facility seven (7) days per week and twenty-four (24) hours per day (including holidays), by providing Dispatch Notices, subject to the requirements and limitations set forth in this Agreement, including the Operating Restrictions. Subject to the Operating Restrictions, each Dispatch Notice shall be effective unless and until such Dispatch Notice is modified by the CAISO, Buyer or Buyer’s SC. If Automated Dispatches are not possible for reasons beyond Buyer’s control, Alternative Dispatches may be provided pursuant to Section 4.6(b).
4.8 Facility Unavailability to Receive Dispatch Notices. To the extent the Facility is unable to receive or respond to Dispatch Notices either through Automated Dispatches or Alternative Dispatches during any Settlement Interval or Settlement Period, then as an exclusive 232
31 remedy, the time period corresponding to such Settlement Interval or Settlement Period shall be deemed unavailable for purposes of calculating the Monthly Capacity Availability.
4.9 Energy Management.
(a) Charging Generally. Upon receipt of a valid Charging Notice, Seller shall take all action necessary to deliver the Charging Energy to the Facility from the Delivery Point.
Seller shall maintain, repair or replace equipment in Seller’s possession or control used to deliver the Charging Energy from the Delivery Point to the Facility. Except as otherwise expressly set forth in this Agreement, Buyer shall be responsible for paying all costs and charges of delivering the Charging Energy to the Delivery Point, including all CAISO costs and charges associated with Charging Energy.
(b) Charging Notices. Buyer shall have the right to charge the Facility seven (7) days per week and twenty-four (24) hours per day (including holidays) during the Delivery Term, by causing Charging Notices to be issued, subject to the requirements and limitations set forth in this Agreement, including the Operating Restrictions. Each Charging Notice issued in accordance with this Agreement shall be effective unless and until Buyer’s SC or CAISO modifies such Charging Notice by providing Seller with an updated Charging Notice. Buyer shall be responsible for issuing all Charging Notices necessary or required in connection with the Must Offer Obligations.
(c) No Unauthorized Charging. Seller shall not charge the Facility during the Delivery Term other than pursuant to a valid Charging Notice (it being understood that Seller may adjust a Charging Notice to the extent necessary to maintain compliance with the Operating Restrictions), or in connection with a Seller Initiated Test (including Facility maintenance or a Capacity Test), or pursuant to a notice from the Transmission Provider or Governmental Authority.
If, during the Delivery Term, Seller charges the Facility (i) to a Storage Level greater than the Storage Level provided for in a Charging Notice, or (ii) in violation of the first sentence of this Section 4.9(c), then (i) Seller shall pay to Buyer all Energy costs associated with such charging of the Facility, and (ii) Buyer shall be entitled to discharge such Energy and shall be entitled to all of the benefits (including Product) associated with such discharge. (d) Discharging Notices. Buyer shall have the right to discharge the Facility seven (7) days per week and twenty-four (24) hours per day (including holidays) during the Delivery Term, by causing Discharging Notices to be issued. Each Discharging Notice issued in accordance with this Agreement shall be effective unless and until Buyer’s SC or the CAISO modifies such Discharging Notice by providing the Facility with an updated Discharging Notice.
Buyer shall be responsible for issuing all Discharging Notices necessary or required in connection with the Must Offer Obligations and all CAISO charges and penalties for failing to comply with the Must Offer Obligation.
(e) No Unauthorized Discharging. Seller shall not discharge the Facility during the Delivery Term other than pursuant to a valid Discharging Notice (it being understood that Seller may adjust a Discharging Notice to the extent necessary to maintain compliance with the Operating Restrictions), or in connection with a Seller Initiated Test (including Facility 233
32 maintenance or a Storage Capacity Test), or pursuant to a notice from the Transmission Provider or Governmental Authority.
(f) Unauthorized Charges and Discharges. If Seller or any third party charges, discharges or otherwise uses the Facility other than as permitted hereunder, or as is expressly addressed in this Section 4.9, it shall be a breach by Seller and Seller shall hold Buyer harmless from, and indemnify Buyer against, all actual costs or losses associated therewith, and be responsible to Buyer for any damages arising therefrom, and, if Seller fails to implement procedures reasonably acceptable to Buyer to prevent any further occurrences of the same, then the failure to implement such procedures shall be an Event of Default under Article 11. (g) CAISO Dispatches. During the Delivery Term, CAISO Dispatches shall have priority over any Charging Notice or Discharging Notice issued by Buyer’s SC, and Seller shall have no liability for violation of this Section 4.9 or any Charging Notice or Discharging Notice if and to the extent such violation is caused by Seller’s compliance with any CAISO Dispatch. During any time interval during the Delivery Term in which the Facility is capable of responding to a CAISO Dispatch, but the Facility deviates from a CAISO Dispatch or Seller negligently or intentionally fails to accurately communicate to Buyer the Facility’s availability, Seller shall be responsible for all CAISO charges and penalties resulting from such deviations (in addition to any Buyer remedy related to overcharging of the Facility as set forth in Section 4.9(c)). (h) Pre-Commercial Operation Date Period, etc. Prior to the Commercial Operation Date, Buyer shall have no rights to issue or cause to be issued Charging Notices or Discharging Notices, and Seller shall have exclusive rights to charge and discharge the Facility. (i) Curtailments. Notwithstanding anything in this Agreement to the contrary, during any Settlement Interval, Curtailment Orders applicable to such Settlement Interval shall have priority over any Dispatch Notices applicable to such Settlement Interval, and Seller shall have no liability for violation of this Agreement or any Dispatch Notice if and to the extent such violation is caused by Seller’s compliance with any Curtailment Order or other instruction or direction from a Governmental Authority or the Transmission Provider. Buyer shall have the right, but not the obligation, to provide Seller with updated Dispatch Notices during any Curtailment Order consistent with the Operating Restrictions.
(j) Station Use. Notwithstanding anything to the contrary in this Agreement, the Parties acknowledge (i) Seller is responsible for providing all Energy to serve Station Use(including paying the cost of any Energy used to serve Station Use during periods in which the Storage Facility is not charging or discharging pursuant to a Charging Notice or Discharging Notice), (ii) Energy supplied from Charging Energy or Discharging Energy during periods in which the Storage Facility is charging or discharging pursuant to a Charging Notice or Discharging Notice shall not be considered Station Use, (iii) Station Use may be supplied over the same circuit as Charging Energy and Discharging Energy, and (iv) Seller shall indemnify and hold harmless Buyer from any and all costs, penalties or charges for Energy supplied for Station Use by any means other than retail service from the applicable utility, and shall take any additional measures to ensure Station Use (other than that supplied from Charging Energy or Discharging Energy as provided in clause (ii) or over the same circuit as Charging Energy and Discharging Energy as 234
33 provided in clause (iii)) is supplied by the applicable utility’s retail service if necessary to avoid any such costs, penalties or charges.
4.10 Capacity Availability Notice.
(a) No less than thirty (30) days before the beginning of Commercial Operation, and thereafter ten (10) Business Days before the beginning of each month during the Delivery Term, Seller shall provide to Buyer and the SC (if applicable) a non-binding forecast of the hourly expected Available Capacity for each day of the following month in a form substantially similar to Exhibit F (“Monthly Forecast”).
(b) During the Delivery Term, no later than two (2) Business Days before each schedule day for the Day-Ahead Market in accordance with CAISO scheduling practices, Seller shall provide Buyer and the SC (if applicable) with an hourly schedule of the Available Capacity that the Facility is expected to have for each hour of such schedule day (the “Availability Notice”).
Seller shall provide Availability Notices (including updated Availability Notices) using the form attached in Exhibit G, or other form as reasonably requested by Buyer, by (in order of preference) electronic mail or telephonically to Buyer personnel or its Scheduling Coordinator designated to receive such communications.
(c) Seller shall notify Buyer and the SC (if applicable) immediately with an updated Monthly Forecast and Availability Notice, as applicable, if the Available Capacity of the Facility changes or is expected to change after Buyer’s receipt of a Monthly Forecast or Availability Notice. Seller shall accommodate Buyer’s reasonable requests for changes in the time of delivery of Availability Notices.
4.11 [Reserved].
4.12 Outages
(a) Planned Outages.
(i) No later than January 15, April 15, July 15 and October 15 of each Contract Year, and at least sixty (60) days prior to the Commercial Operation Date, Seller shall submit to Buyer Seller’s schedule of proposed Planned Outages (“Outage Schedule”) for the following twelve (12)-month period in a form reasonably agreed to by Buyer. Within twenty (20) Business Days after its receipt of an Outage Schedule, Buyer shall give Notice to Seller of any reasonable request for changes to the Outage Schedule, and Seller shall, consistent with Prudent Operating Practices, accommodate Buyer’s requests regarding the timing of any Planned Outage.
Seller shall deliver to Buyer the final Outage Schedule no later than ten (10) days after receiving Buyer’s comments. Seller shall be permitted to reduce deliveries of applicable Products during any period of such Planned Outages.
(ii) If reasonably required in accordance with Prudent Operating Practices, Seller shall have the right, on no less than ninety (90) days advance Notice to Buyer, to propose changes to the Outage Schedule developed pursuant to Section 4.12(a)(i). Buyer may provide comments no later than ten (10) days after receiving Seller’s Notice of proposed changes to the Outage Schedule and shall permit any changes if doing so would not have a material adverse 235
236
35 after its delivery to Buyer at the time and place contemplated under this Agreement (other than withholding or other Taxes imposed on Seller’s income, revenue, receipts or employees) or on Charging Energy prior to its delivery to Seller. If a Party is required to remit or pay Taxes that are the other Party’s responsibility hereunder, such Party shall promptly pay the Taxes due and then seek and receive reimbursement from the other for such Taxes. In the event any sale of Product hereunder is exempt from or not subject to any particular Tax, Buyer shall provide Seller with all necessary documentation to evidence such exemption or exclusion within thirty (30) days after the date Buyer makes such claim. Buyer shall indemnify, defend, and hold Seller harmless from any liability with respect to Taxes for which Buyer is responsible hereunder and from which Buyer claims it is exempt.
5.2 Cooperation. Each Party shall use reasonable efforts to implement the provisions of and administer this Agreement in accordance with the intent of the Parties to minimize all Taxes, so long as no Party is materially adversely affected by such efforts. The Parties shall cooperate to minimize Tax exposure; provided, neither Party shall be obligated to incur any financial or operational burden to reduce Taxes for which the other Party is responsible hereunder without receiving due compensation therefor from the other Party. All Product delivered by Seller to Buyer hereunder shall be a sale made at wholesale, with Buyer reselling such Product.
5.3 Environmental Costs. Seller shall be solely responsible for:
(a) All Environmental Costs;
(b) All taxes, charges or fees imposed on the Facility or Seller by a Governmental Authority for Greenhouse Gas emitted by or attributable to the Facility during the Delivery Term, but expressly excluding any taxes, charges or fees related to Greenhouse Gases imposed on Charging Energy or Discharging Energy;
(c) Seller’s obligations listed under “Compliance Obligation” in the GHG Regulations, and
(d) All other costs associated with the implementation and regulation of Greenhouse Gas emissions (whether in accordance with the California Global Warming Solutions Act of 2006, Assembly Bill 32 (2006) and the regulations promulgated thereunder, including the GHG Regulations, or any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions implemented and regulated by a Governmental Authority) with respect to the Facility and/or Seller.
ARTICLE 6
MAINTENANCE AND REPAIR OF THE FACILITY
6.1 Maintenance of the Facility.
(a) Seller shall construct, operate, and maintain the Facility so that Buyer may dispatch the Facility within the operating parameters of the Operating Restrictions. Nothing herein shall limit Seller’s right replace or augment existing batteries and other equipment to maintain the capacity of the Facility.
237
36 (b) Seller shall, as between Seller and Buyer, be solely responsible for the operation, inspection, maintenance and repair of the Facility, and any portion thereof, in accordance with applicable Law and Prudent Operating Practices. Seller shall maintain and deliver maintenance and repair records of the Facility to Buyer’s scheduling representative upon request. (c) Seller shall promptly make all necessary repairs to the Facility, and any portion thereof, and take all actions necessary in order to provide the Product to Buyer in accordance with the terms of this Agreement (and, at a minimum, the Performance Guarantees).
6.2 Maintenance of Health and Safety. Seller shall take reasonable safety precautions with respect to the operation, maintenance, repair and replacement of the Facility. If Seller becomes aware of any circumstances relating to the Facility that create an imminent risk of damage or injury to any Person or any Person’s property, Seller shall take prompt, reasonable action to prevent such damage or injury and shall give Buyer’s emergency contact identified in Exhibit N Notice of such condition. Such action may include disconnecting and removing all or a portion of the Facility or suspending the supply of Discharging Energy to the Delivery Point.
6.3 Shared Facilities. The Parties acknowledge and agree that certain of the Shared Facilities and Interconnection Facilities, and Seller’s rights and obligations under the Interconnection Agreement, may be subject to certain shared facilities and/or co-tenancy agreements to be entered into among Seller, the Transmission Provider, Seller’s Affiliates, and/or third parties. Seller agrees that any agreements regarding Shared Facilities (i) shall permit Seller to perform or satisfy, and shall not purport to limit, Seller’s obligations hereunder, (ii) shall provide for separate metering of the Facility; (iii) shall not limit Buyer’s ability to charge or discharge the Facility up to the Dedicated Interconnection Capacity; (iv) shall provide that any other generating or energy storage facilities not included in the Facility but using Shared Facilities shall not be included within the Facility’s CAISO Resource ID; and (iv) shall provide that any curtailment or restriction of Shared Facility capacity not attributable to a specific project or projects shall be allocated to all generating or storage facilities utilizing the Shared Facilities based on their pro rata allocation of the Shared Facility capacity prior to such curtailment or reduction. Seller shall not, and shall not permit any Affiliate to, allocate to other Persons a share of the total interconnection capacity under the Interconnection Agreements in excess of an amount equal to the total interconnection capacity under the Interconnection Agreements minus the Dedicated Interconnection Capacity.
ARTICLE 7
METERING
7.1 Metering. Seller shall measure the amount of Charging Energy and Discharging Energy using the Facility Meter, which shall be subject to adjustment in accordance with applicable CAISO meter requirements and Prudent Operating Practices, including to account for Electrical Losses. Seller shall separately meter all Station Use except to the extent drawn from Charging Energy or Discharging Energy. The Facility Meter shall be operated pursuant to applicable CAISO-approved calculation methodologies and maintained at Seller’s cost. Each meter shall be kept under seal, such seals to be broken only when the Facility Meters are to be tested, adjusted, modified or relocated. In the event Seller breaks a seal, Seller shall notify Buyer as soon as practicable. In addition, Seller hereby agrees to provide all Facility Meter data to Buyer in a form reasonably acceptable to Buyer, and consents to Buyer obtaining from CAISO the 238
37 CAISO meter data directly relating to the Facility and all inspection, testing and calibration data and reports. Seller and Buyer shall cooperate to allow both Parties to retrieve the meter reads from the CAISO Market Results Interface - Settlements (MRI-S) web and/or directly from the CAISO meter(s) at the Facility.
7.2 Meter Verification. If Seller or Buyer have reason to believe there may be a Facility Meter malfunction, Seller shall test the Facility Meter. The tests shall be conducted by independent third parties qualified to conduct such tests. Buyer shall be notified seven (7) days in advance of such tests and have a right to be present during such tests. If a Facility Meter is inaccurate, it shall be promptly repaired or replaced. If a meter is inaccurate by more than one percent (1%) and it is not known when the Facility Meter inaccuracy commenced (if such evidence exists, then such date will be used to adjust prior invoices), then the invoices covering the period of time since the last Facility Meter test shall be adjusted for the amount of the inaccuracy on the assumption that the inaccuracy persisted during one-half of such period if such adjustments are accepted by CAISO; provided, such period may not exceed twelve (12) months.