AGENDA
Regular Meeting
Board of Directors
Thursday, August 28, 2025
5:00 p.m.
Don L. Nay Port Administration Boardroom
3165 Pacific Hwy.
San Diego, CA 92101
The meeting will be held in person at the above date, time and location(s). Members of the Board of Directors and members of the public may attend in person. Under certain circumstances, Directors may also attend and participate in the meeting virtually pursuant to the Brown Act (Gov.
Code § 54953). As a convenience to the public, Community Power provides a call-in option and internet-based option for members of the public to virtually observe and provide public comments at its meetings. Additional details on in-person and virtual public participation are below. Please note that, in the event of a technical issue causing a disruption in the call-in option or internet-based option, the meeting will continue unless otherwise required by law, such as when a Board Member is attending the meeting virtually pursuant to certain provisions of the Brown Act.
Note: Any member of the public may provide comments to the Board of Directors on any agenda item. When providing comments to the Board, it is requested that you provide your name and city of residence for the record. Commenters are requested to address their comments to the Board of Directors as a whole through the Chair. Comments may be provided in one of the following manners:
1. Providing oral comments during a meeting. Anyone attending in person desiring to address the Board of Directors is asked to fill out a speaker’s slip and present it to the Clerk of the Board. To provide remote comments during the meeting, join the Zoom meeting by computer, mobile phone, or dial-in number. On Zoom video conference by computer or mobile phone, use the “Raise Hand” feature. This will notify the moderator that you wish to speak during a specific item on the agenda or during non-agenda Public Comment. Members of the public will not be shown on video but will be able to speak when called upon. If joining the meeting using the Zoom dial-in number, you can raise your hand by pressing *9. Comments will be limited to three (3) minutes.
2. Written Comments. Written public comments must be submitted prior to the start of the meeting to [email protected]. Please indicate a specific agenda item when submitting your comment. All written comments received prior to the meeting will be provided to Members of the Board. In the discretion of the Chair, the first ten (10) submitted comments shall be stated into the record of the meeting.
Comments read at the meeting will be limited to the first 400 words. Comments 1 received after the start of the meeting will be collected, sent to the Members of Board, and be part of the public record.
If you have anything that you wish to be distributed to the Board, please send it to [email protected].
The public may participate using the following remote options:
Teleconference Meeting Webinar https://sdcommunitypower-org.zoom.us/j/94274587066 Telephone (Audio Only) (669) 900-6833 or (346) 248-7799 | Webinar ID: 94274587066
WELCOME
CALL TO ORDER
ROLL CALL
PLEDGE OF ALLEGIANCE
SPECIAL PRESENTATIONS AND INTRODUCTIONS
• Recognition of Chair Aguirre for her service to Community Power • Introduction of Community Power Representative from Imperial Beach, Jack Fisher • Introduction of New Community Power Staff
ITEMS TO BE ADDED, WITHDRAWN, OR REORDERED ON THE AGENDA
PUBLIC COMMENTS
Opportunity for members of the public to address the Board on any items not on the agenda but within the jurisdiction of the Board. Members of the public may provide a comment in either manner described above.
CONSENT CALENDAR
All matters are approved by one motion without discussion unless a member of the Board of Directors requests a specific item to be removed from the Consent Calendar for discussion.
A member of the public may comment on any item on the Consent Calendar in either manner described above.
1. Approve June 26, 2025, Meeting Minutes
2. Receive and File Treasurer’s Report for Period Ending May 31, 2025
3. Receive and File Update on Programs
2 4. Receive and File Update on Power Services
5. Receive and File Update on Customer Operations
6. Receive and File Update on IT and Data Analytics
7. Receive and File Update on Human Resources
8. Receive and File Community Advisory Committee Monthly Update
9. Receive and File Update on Marketing, Public Relations, and Local Government Affairs
10. Approve Load Management Standards Compliance Plan Update
11. Authorize Amendment No. 1 to Professional Services Agreement with JSR Strategies LLC to Increase Contract Amount to $650,000 for Marketing, Communications, Website Design, and Maintenance Services
12. Adopt Resolution No. 2025-08, Approving a Second Revision to San Diego Community Power (Community Power) Investment Policy
13. Adopt Resolution No. 2025-12, Approving Updates to San Diego Community Power’s (Community Power) Public Records Request Policy Pursuant to the California Public Records Act (CPRA) Recodification Act, Assembly Bill 473 (AB 473)
REGULAR AGENDA
The following items call for discussion or action by the Board of Directors. The Board may discuss and/or take action on any item listed below if the Board is so inclined.
14. Election of Officer(s) for Community Power for the Remainder of Calendar Year 2025
Recommendation: Elect a Chair and, if necessary, a Vice Chair for the remainder of the 2025 calendar year.
15. Adoption of Resolution No. 2025-10, Requesting CalPERS to Authorize the Division Vote of Community Power Employees to Participate in Social Security, and Upon Receiving Authorization, Authorize Community Power to Conduct the Division Vote
Recommendation: Adoption of Resolution No. 2025-10, requesting CalPERS to authorize the division vote of Community Power employees to participate in Social Security and for Community Power to conduct the division vote upon receiving said authorization. 3 AGENDA – BOARD OF DIRECTORS – SAN DIEGO COMMUNITY POWER
16. Adopt Resolution No. 2025-11, Establishing and Approving a Claims Procedures Policy
Recommendation: Adopt Resolution No. 2025-11, establishing and approving a Claims Procedures Policy.
17. Adoption of Resolution No. 2025-09, Approving a Disposal of Surplus Property Policy
Recommendation: Adoption of Resolution No. 2025-09, Approving a Disposal of Surplus Property Policy.
18. Approve Renewable Power Purchase Agreement with IP Darden IV, LLC Recommendation: Approve the proposed Renewable Power Purchase Agreement (“PPA”) for a 91.48 MW solar and 91.48 MW, 4-hour battery energy storage facility, with IP Darden IV, LLC, for a term of up to 12 years, in substantially final form and authorize the Chief Executive Officer to execute the PPA.
19. 2024 Power Source Disclosure Program Annual Reports and Power Content Label; and Adoption of Resolution No. 2025-13, Approving the Submission and Attesting to the Accuracy of Community Power’s 2024 Power Source Disclosure Annual Reports for PowerBase, PowerOn, Power100, and Power100 Green+
Recommendation: Adopt Resolution 2025-13 approving the submission and attesting to the accuracy of Community Power’s 2024 Power Source Disclosure annual reports for PowerBase, PowerOn, Power100, and Power100 Green+.
20. Update on Regulatory and Legislative Affairs
Recommendation: Receive and File Update of Regulatory and Legislative Affairs.
21. Update on Results from Clean Prepayment Transaction No. 2 Recommendation: Receive and file the update for the Clean Energy Prepayment Bond finance initiative.
CHIEF EXECUTIVE OFFICER REPORT
Community Power Management may briefly provide information to the Board and the public. The Board may engage in discussion if the specific subject matter of the report is identified below, but the Board may not take any action other than to place the matter on a future agenda. Otherwise, there is to be no discussion or action taken unless authorized by law.
4 DIRECTOR COMMENTS
Board Members may briefly provide information to other members of the Board and the public, ask questions of staff, request an item to be placed on a future agenda, or report on conferences, events, or activities related to Community Power business. There is to be no discussion or action taken on comments made by Directors unless authorized by law.
ADJOURNMENT
The San Diego Community Power Board of Directors will adjourn to a regular meeting scheduled on Thursday, September 25, 2025, at 5 pm.
Compliance with the Americans with Disabilities Act
San Diego Community Power Board of Directors meetings comply with the protections and prohibitions of the Americans with Disabilities Act. Individuals with a disability who require a modification or accommodation, including auxiliary aids or services, in order to participate in the public meeting may contact (888) 382-0169 or
[email protected]. Requests for disability-related modifications or accommodations require different lead times and should be provided at least 72-hours in advance of the public meeting.
Availability of Board Documents
Copies of the agenda and agenda packet are available at https://sdcommunitypower.org/resources/meeting-notes/. Late-arriving documents related to a Board meeting item which are distributed to a majority of the Members prior to or during the Board meeting are available for public review as required by law. Public records, including agenda-related documents, can be requested electronically at [email protected] or by mail to San Diego Community Power, P.O.
BOX 12716, San Diego, CA 92112. The documents may also be posted on Community Power’s website. Such public records are also available for inspection, by contacting [email protected] to arrange an appointment. 5 BOARD OF DIRECTORS
Don L. Nay Port Administration Boardroom
3165 Pacific Hwy.
San Diego, CA 92101
REGULAR MEETING MINUTES
June 26, 2025
________________________________________________________________________________
WELCOME
CALL TO ORDER
Chair Aguirre called the Community Power Board of Directors regular meeting to order at 5 p.m.
ROLL CALL
PRESENT: Chair Aguirre, City of Imperial Beach; Vice Chair Lawson-Remer, County of San Diego; Director Elo-Rivera, City of San Diego (arrived at 5:02 p.m.); Director Inzunza, City of Chula Vista; Director San Antonio, City of Encinitas; Alternate Director Cazares, City of La Mesa; and Director Yamane, City of National City ABSENT: None
Staff Present: Chief Executive Officer Burns; Chief Financial Officer Washington; Chief Operating Officer Clark, General Counsel Tyagi; Associate Director of Legislative Affairs Welch; Director of Origination Torres (via Zoom Teleconference); Senior Director of People Operations and Administration Pugh; Director of Finance Manglicmot; Director of Portfolio Management Camara; Director of Power Contracts Key; Strategic Finance Manager Spengler; Senior Manager Community Engagement Crespo; Clerk of the Board Hernandez; and Assistant Clerk of the Board Vences Chair Aguirre announced that the previously scheduled Closed Session would not be required:
PLEDGE OF ALLEGIANCE
Chair Aguirre led the Pledge of Allegiance.
LAND ACKNOWLEDGEMENT
Chair Aguirre acknowledged the Kumeyaay Nation and all the original stewards of the land. 6 SPECIAL PRESENTATIONS AND INTRODUCTIONS
• Proclamation recognizing outgoing Community Advisory Committee member Gary Jahns Chair Aguirre recognized outgoing Community Advisory Committee Member, Gary Jahns, for his contributions and years of dedicated service and presented him with a Proclamation. • Introduction of New Community Power Staff
Chair Aguirre welcomed new employees Sara Saragosa, Executive Assistant and Nadeem Bahou, Data Analyst to introduce themselves.
ITEMS TO BE ADDED, WITHDRAWN, OR REORDERED ON THE AGENDA There were no items added, withdrawn, or reordered on the agenda.
PUBLIC COMMENTS
Cristina Marquez from IBEW Local 569 and Jim Whalen from J. Whalen Associates provided public comments.
CONSENT CALENDAR
1. Approve May 22, 2025, Meeting Minutes
2. Receive and File Treasurer’s Report for Period Ending April 30, 2025
3. Receive and File Update on Programs
4. Receive and File Update on Power Services
5. Receive and File Update on Customer Operations
6. Receive and File Update on Marketing, Public Relations, and Local Government Affairs
7. Receive and File Community Advisory Committee Monthly Report
8. Receive and File Update on Regulatory and Legislative Affairs There were no public comments on Consent Item Nos. 1-8.
Motioned by Director Inzunza and seconded by Director Yamane to approve Consent Calendar Item Nos. 1 through 8. The motion carried 7/0 as follows:
AYES: Chair Aguirre, Vice Chair Lawson-Remer, Directors Elo-Rivera, Inzunza, San Antonio, Yamane, and Alternate Director Cazares
NOES: None
7 ABSTAINED: None
ABSENT: None
REGULAR AGENDA
9. Approve Community Advisory Committee Member for City of Chula Vista Ms. Crespo presented the member criteria and selection process, followed by a brief overview of candidate Alonso Gonzalez for appointment to the Community Advisory Committee for the City of Chula Vista.
There were no public comments on Item No. 9.
After Board member comments, motioned by Director Inzunza and seconded by Director Yamane to approve the appointment of Alonso Gonzalez to the Community Advisory Committee for the City of Chula Vista. The motion carried 7/0 as follows:
AYES: Chair Aguirre, Vice Chair Lawson-Remer, Directors Elo-Rivera, Inzunza, San Antonio, Yamane, and Alternate Director Cazares
NOES: None
ABSTAINED: None
ABSENT: None
10. Consider Amendments to Executive Employment Agreements a. Approve Amended and Restated Employment Agreement for Chief Executive Officer b. Approve First Amendment to Employment Agreement for General Counsel Nicholas Norvell, Special Legal Counsel from Best Best & Krieger noted that under the Brown Act before taking final action on an executive’s salary or benefits a verbal summary is required.
Mr. Norvell reported that at the regular meeting of May 22, 2025, the Board conducted its annual performance evaluations and compensation review for both the Chief Executive Officer (CEO) and the General Counsel. Based upon those discussions and successful completion of negotiations there are two items before the Board this evening, the first is an Amended and Restated Employment Agreement for the CEO. The amended agreement incorporates language from the previous three amendments to the CEO's employment agreement; it corrects and clarifies items from the original agreement and provides for the following changes to salary and benefits:
- Under the amended employment agreement, the CEO would receive a merit increase of 3.5% bringing the salary to $486,772.82.
- In addition, the CEO would receive an additional 40 hours of vacation time per year which would supplement the amount she receives under Community Power’s standard benefits. 8 The second item for approval this evening is the First Amendment to the General Counsel’s Employment Agreement. The first amendment corrects and clarifies items from the original agreement, removes the specific term from the employment period and provides the following change to salary:
- A market adjustment as well as a 4% merit increase bringing her total salary to $408,241.60.
There were no public comments on Items 10 (a) or 10 (b).
Motioned by Director Yamane and seconded by Director Elo-Rivera to approve the Amended and Restated Employment Agreement for the CEO and the First Amendment to Employment Agreement for the General Counsel. The motion carried 7/0 as follows:
AYES: Chair Aguirre, Vice Chair Lawson-Remer, Directors Elo-Rivera, Inzunza, San Antonio, Yamane, and Alternate Director Cazares
NOES: None
ABSTAINED: None
ABSENT: None
11. Tariffs, Tax Credits and Executive Orders: New-Build Market Outlook Update Mr. Welch and Ms. Torres provided an update on Tariffs, Tax Credits and Executive Orders: New-Build Market Outlook.
There were no public comments on Item No. 11.
After Board member questions, discussion and comments, the status report on federal policy and budget as it relates to clean energy procurement was received and filed.
12. Public Hearing - AB 2561 - Status of vacancies, recruitment and retention efforts Chair Aguirre declared the public hearing open.
Ms. Pugh summarized the requirements of Assembly Bill (AB) 2561 and presented Community Power’s report on status of vacancies, recruitment, and retention efforts.
There were no public comments on Item No. 12.
Chair Aguirre declared the public hearing closed.
Motioned by Director Yamane and seconded by Director Inzunza to hold a public hearing, receive comments, and accept report on the status of Community Power employee vacancy rates and recruitment and retention efforts. The motion carried 7/0 as follows:
AYES: Chair Aguirre, Vice Chair Lawson-Remer, Directors Elo-Rivera, Inzunza, San Antonio, Yamane, and Alternate Director Cazares
NOES: None
ABSTAINED: None
9 ABSENT: None
13. Approve the FY 2025-2026 Operating Budget, the FY 2025-2026 Capital Budget, and the FY 2026-2030 Capital Investment Plan
Ms. Burns introduced the proposed FY 2025-2026 Operating Budget, the FY 2025-2026 Capital Budget, and the FY 2026-2030 Capital Investment Plan. Followed by Dr. Washington, Mr. Manglicmot, Ms. Camara, and Mr. Clark presented their corresponding budget sections.
There were no public comments on Item No. 13.
After Board member comments, motioned by Director Yamane and seconded by Director Inzunza to adopt Resolution No. 2025-06, approving the FY 2025-2026 Operating Budget, the FY 2025-2026 Capital Budget, and the FY 2026-2030 Capital Investment Plan. The motion carried 7/0 as follows:
AYES: Chair Aguirre, Vice Chair Lawson-Remer, Directors Elo-Rivera, Inzunza, San Antonio, Yamane, and Alternate Director Cazares
NOES: None
ABSTAINED: None
ABSENT: None
14. Approve Update to San Diego Community Power’s Energy Risk Management Policy:
California Carbon Allowance and Carbon Offset Transactions and Obligations Ms. Camara provided an update on San Diego Community Power’s Energy Risk Management Policy:
California Carbon Allowance and Carbon Offset Transactions and Obligations.
Director Elo-Rivera left the meeting at 6:29 p.m.
There were no public comments on Item No. 14.
Motioned by Director Yamane and seconded by Alternate Director Cazares to adopt Resolution No. 2025-05 approving Addendum 2 to San Diego Community Power’s Energy Risk Management Policy:
California Carbon Allowance and Carbon Offset Transactions and Obligations, to allow the CEO to approve procurement of California Carbon Allowance (CCA) and Carbon Offset (CO) to meet San Diego Community Power compliance obligations under California’s Cap-and-Trade Program. The motion carried 6/0 as follows:
AYES: Chair Aguirre, Vice Chair Lawson-Remer, Directors Inzunza, San Antonio, Yamane, and Alternate Director Cazares
NOES: None
ABSTAINED: None
ABSENT: Director Elo-Rivera
10 15. Adoption of Resolution No. 2025-07, Authorizing Execution of an Energy Prepayment Transaction, Related Documents, and ‘Form of’ Documents Subject to Maximum Issuance Amount, Limitation on Fees, and Minimum Required Savings Mr. Washington introduced the goals and benefits of Energy Prepayment Transactions and turned it over to Mr. Spengler to provide an overview of the process for the Execution of an Energy Prepayment Transaction, Related Documents, and ‘Form of’ Documents Subject to Maximum Issuance Amount, Limitation on Fees, and Minimum Required Savings.
Vice Chair Lawson-Remer left the meeting at 6:37 p.m.
There were no public comments on Item No. 15.
Motioned by Director Yamane and seconded by Director Inzunza to adopt Resolution No. 2025-07, approving parameters under which an energy prepayment transaction can be completed; authorizing and approving documents or “form of” documents supporting the prepay transaction; and directing California Community Choice Financing Authority (CCCFA) to make payments to service providers for issuance costs from prepay bond proceeds. The motion carried 5/0 as follows:
AYES: Chair Aguirre, Directors Inzunza, San Antonio, Yamane, and Alternate Director Cazares
NOES: None
ABSTAINED: None
ABSENT: Vice Chair Lawson-Remer and Director Elo-Rivera
16. Approve Amended and Restated Energy Storage Service Agreement with Yellow Pine Solar III, LLC
Mr. Key provided an overview of the Amended and Restated Energy Storage Service Agreement with Yellow Pine Solar III, LLC.
There were no public comments on Item No. 16.
After Board member comments, motioned by Alternate Director Cazares and seconded by Director San Antonio to approve the proposed Amended and Restated Renewable Energy Storage Service Agreement with Yellow Pine Solar III, LLC to move the capacity between project sites, reduce the fixed capacity price, and make additional minor amendments, and authorize the Chief Executive Officer to execute the agreement. The motion carried 5/0 as follows:
AYES: Chair Aguirre, Directors Inzunza, San Antonio, Yamane, and Alternate Director Cazares
NOES: None
ABSTAINED: None
ABSENT: Vice Chair Lawson-Remer and Director Elo-Rivera 11 17. Approve Energy Storage Service Agreement for the North Johnson Energy Center Mr. Key presented the proposed Energy Storage Service Agreement for the North Johnson Energy Center.
Director Elo-Rivera rejoined the meeting at 6:53 p.m.
There were no public comments on Item No. 17.
Motioned by Director Yamane and seconded by Alternate Director Cazares to approve the proposed 15-year Energy Storage Service Agreement with North Johnson Energy Center, LLC for a 50 MW/200 MWh, 4-hour battery energy storage facility and authorize the Chief Executive Officer to execute the agreement. The motioned carried 6/0 as follows:
AYES: Chair Aguirre, Directors Elo-Rivera, Inzunza, San Antonio, Yamane and Alternate Director Cazares
NOES: None
ABSTAINED: None
ABSENT: Vice Chair Lawson-Remer
CHIEF EXECUTIVE OFFICER REPORT
Ms. Burns reported on Community Power’s recent activities and events.
DIRECTOR COMMENTS
There were no Director comments.
ADJOURNMENT
Chair Aguirre announced that the Board will be dark in July. The meeting was adjourned at 7:03 p.m. to the next regular meeting scheduled for Thursday, August 28, 2025, at 5 p.m. _____________________________
Maricela Hernandez, MMC, CPMC
Clerk of the Board
12 SAN DIEGO COMMUNITY POWER
Staff Report – Item 2
____________________________________________________________________________________ TO: Board of Directors
FROM: Dr. Eric W. Washington, Chief Financial Officer/Treasurer VIA: Karin Burns, Chief Executive Officer
SUBJECT: Treasurer’s Report for Period Ending May 31, 2025 DATE: August 28, 2025
____________________________________________________________________________________ RECOMMENDATION:
Receive and File Treasurer’s Report for Period Ending May 31, 2025.
BACKGROUND:
San Diego Community Power (Community Power) maintains its accounting records on a full accrual basis in accordance with Generally Accepted Accounting Principles (GAAP) as applicable to governmental enterprise funds. Community Power has prepared its year-to-date financial statements for the eleven-month period ended May 31, 2025, along with budgetary comparisons.
Additionally, on May 25, 2023, the Community Power Board of Directors (Board) adopted the Community Power Investment Policy, which was subsequently revised on June 27, 2024. The objectives of the Investment Policy are to (1) safeguard the principal of investment funds, (2) meet the liquidity needs of Community Power, (3) achieve a return on funds invested, and (4) exercise a high standard of care on investment funds. The Investment Policy additionally includes provisions for regular reporting to the Financial and Risk Management (FRMC) which will be included in the Treasurer’s Report.
In an effort to increase public transparency and in alignment with section 1.a of the Community Power Delegated Contract Authority Policy, Community Power will also report newly executed contracts between $50,000 and $125,000 for goods and services in the Treasurer’s Report.
Community Power additionally reports monthly metrics during its Board meetings as part of its Update on Back-Office Operations. As part of the Treasurer’s Report, certain key metrics related to risk are presented during Financial and Risk Management Committee (FRMC) meetings.
13 On June 27, 2024, the Community Power Board of Directors (Board) approved the Fiscal Year 2024-25 Operating Budget that included net operating revenues of $1,177,925,889 total expenses of $1,143,919,262 and a resulting net position of $34,006,627. The approved Fiscal Year 2024-25 budget also includes a capital budget to fund 16 projects, totaling 23 active projects during the fiscal year for $16,434,280.
Subsequently, on February 27, 2025, the Board approved an amendment to the FY 2024- 25 Operating Budget to increase total net operating revenues to $1,221,258,172 and total expenses to $1,187,090,169, resulting in a net position of $34,168,003. Additionally, the Board approved an amendment to the FY 2024-25 Capital Budget to increase total expenses to $144,212,340 and an amendment to the FY 2025-29 Capital Investment Plan (CIP) to $155,910,762.
ANALYSIS AND DISCUSSION:
Financial Results
Actual financial results for the period ended May 31, 2025: $1,116.3 million in net operating revenues were reported compared to $1,101.6 million budgeted for the period. $1,088.9 million in total expenses were reported (including $1,045.4 million in energy costs) compared to $1,105.9 million budgeted for the period (including $1,040.0 million budgeted for energy costs). After expenses, Community Power’s change in net position of $27.4 million was reported year-to-date for Fiscal Year 2024-25. The following is a summary of the actual results compared to the Fiscal Year 2024-25 Amended Budget.
Table 1: Budget Comparison Versus Actual Result
• Net operating revenues finished $14.7 million (or 1.3 percentage points) over the budget and were largely in line with expectations.
• Operating expenses ended $17.0 million (2.0 percentage points) under budget, primarily due to the following factors:
• Investment Income: Favorable variance of $12.1 million year-to-date, which was not included in the budget.
• Professional Services and Consultants: $5.4 million below year-to-date budget, mainly due to lower-than-expected costs related to Calpine, Legal, SDG&E fees, and other services.
• Personnel Costs: $2.4 million under budget, driven by vacancies and accrued vacation.
14 Figure 1: Budget Comparison versus Actual Results
For the eleven-month period ending May 31, 2025, Community Power contributed $27,430,577 to its net position compared to the expected contribution of $(4,275,633) per the Fiscal Year 2024-25 budget. Total Community Power reserves at the end of the period were $319,565,492 based on cash and cash equivalents – unrestricted, and total available liquidity (including lines of credit) was $532,065,492. Community Power has a total Fiscal Year 2024-25 year-end reserve target of $575,822,041 which is equivalent to 180-days of total operating expenses as set in Community Power’s Reserve Policy and Strategic Goals
Investment Portfolio Report
Chandler Asset Management manages Community Power’s investment portfolio. As of May 31, 2025, the market value of the portfolio was $61.84 million compared to the $61.99 million market value as April 30, 2025. The following is a snapshot of the overall characteristics of the portfolio.
$(200,000,000)
$-
$200,000,000
$400,000,000
$600,000,000
$800,000,000
$1,000,000,000
$1,200,000,000
Net Operating Revenues Total Expenses Change in Net Position YTD FY25 Results v. Budget
YTD FY25 as of 5/31/25 (11 months) FY25 YTD Budget Amended 15 Contract Execution between $50,000 and $125,000
Community Power executed 1 Contract in May with GB Endeavors for $100,000. 16 Metrics
Figure 2: Participation Rates as of 7/1/2025
The Phase 4 mass enrollment process in National City and Unincorporated County of San Diego for Non-Net Energy Metering (NEM) customers was officially completed as of May 2023. The participation rate for Community Power reflects full enrollment of current member agencies. We are reporting on the opt outs and eligible accounts associated with the phase based on those accounts that we have noticed for enrollment on a rolling basis as of the reporting month.
17 Staff are also presenting the state of Community Power Arrearages related to financial risk for FRMC consideration and for regular review. Additional metrics can be added by request. The below arrearage data includes Community Power’s Receivables aged 120+ Days as of July 1, 2025.
Figure 3: State of Community Power Arrearages as of 7/1/2025 Figure 4: State of Community Power Arrearages Residential vs Commercial as of 7/1/2025 FISCAL IMPACT:
N/A
ATTACHMENTS:
A: 2025 Year-to-Date Period Ended May 31, 2025, Financial Statements. 18 ITEM 2
ATTACHMENT A
19 1
ACCOUNTANTS’ COMPILATION REPORT
Management
San Diego Community Power
Management is responsible for the accompanying financial statements of San Diego Community Power (a California Joint Powers Authority) which comprise the statement of net position as of May 31, 2025, and the related statement of revenues, expenses, and changes in net position, and the statement of cash flows for the eleven months then ended in accordance with accounting principles generally accepted in the United States of America. We have performed a compilation engagement in accordance with Statements on Standards for Accounting and Review Services promulgated by the Accounting and Review Services Committee of the AICPA. We did not audit or review the accompanying statements nor were we required to perform any procedures to verify the accuracy or completeness of the information provided by management. Accordingly, we do not express an opinion, conclusion, nor provide any assurance on these financial statements.
Management has elected to omit substantially all of the note disclosures required by accounting principles generally accepted in the United States of America in these interim financial statements. San Diego Community Power’s annual audited financial statements include the note disclosures omitted from these interim statements. If the omitted disclosures were included in these financial statements, they might influence the user’s conclusions about the Authority’s financial position, results of operations, and cash flows. Accordingly, these financial statements are not designed for those who are not informed about such matters.
We are not independent with respect to the Authority because we performed certain accounting services that impaired our independence.
Maher Accountancy
San Rafael, CA
July 1, 2025
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com 20 Current assets
Cash and cash equivalents - unrestricted $ 319,565,492
Cash and cash equivalents - restricted 14,040,173
Accounts receivable, net of allowance 89,229,608
Accrued revenue 48,114,102
Prepaid expenses 11,458,922
Other receivables 2,980,663
Deposits 10,870,538
Investments 1,901,228
Total current assets 498,160,726
Noncurrent assets
Cash and cash equivalents - restricted 647,000
Investments 59,339,039
Capital assets, net of depreciation and amortization 1,413,740 Total noncurrent assets 61,399,779
Total assets 559,560,505
Current liabilities
Accrued cost of electricity 122,639,628
Accounts payable 1,000,013
Other accrued liabilities 2,337,986
State surcharges payable 347,319
Deposits - energy suppliers 3,271,731
Lease liability 829,373
Advances from grantors 13,540,173
Total current liabilities 143,966,223
Noncurrent liabilities
Lease liability 672,678
Deposits - energy suppliers 4,410,450
Total noncurrent liabilities 5,083,128
Total liabilities 149,049,351
Restricted for security collateral 14,687,173
Unrestricted 395,823,981
Total net position $ 410,511,154
NET POSITION
SAN DIEGO COMMUNITY POWER
STATEMENT OF NET POSITION
As of May 31, 2025
ASSETS
LIABILITIES
See accountants' compilation report. 2
21 OPERATING REVENUES
Electricity sales, net $ 1,115,105,700
Grant revenue 1,343,644
Other income 1,268,258
Total operating revenues 1,117,717,602
OPERATING EXPENSES
Cost of electricity 1,045,476,896
Contract services 17,809,084
Staff compensation 15,484,969
Other operating expenses 14,882,621
Depreciation and amortization 630,156
Total operating expenses 1,094,283,726
Operating income 23,433,876
NON-OPERATING REVENUES (EXPENSES)
Investment income 12,129,570
Interest expense (434,674)
Nonoperating revenues (expenses), net 11,694,896
CHANGE IN NET POSITION 35,128,772
Net position at beginning of year 375,382,382
Net position at end of year $ 410,511,154
SAN DIEGO COMMUNITY POWER
STATEMENT OF REVENUES, EXPENSES
AND CHANGES IN NET POSITION
Eleven Months Ended May 31, 2025
See accountants' compilation report. 3
22 CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from customers $ 1,160,367,342
Receipts from grantors 14,883,817
Receipts of supplier security deposits 15,196,186
Other operating receipts 1,246,064
Payments to suppliers for electricity (1,053,136,388)
Payments for other goods and services (35,422,836)
Payments for deposits and collateral (1,974,371)
Payments for staff compensation (15,488,365)
Payments of state surcharges (2,411,387)
Net cash provided by operating activities 83,260,062
CASH FLOWS FROM NONCAPITAL FINANCING ACTIVITIES
Proceeds from bank note 55,500,000
Principal payments - bank note (55,500,000)
Interest payments (393,961)
Net cash provided (used) by noncapital
financing activities (393,961)
CASH FLOWS FROM CAPITAL AND RELATED
FINANCING ACTIVITIES
Payments of lease liability (591,882)
Net cash used by capital and related financing activities (591,882)
CASH FLOWS FROM INVESTING ACTIVITIES
Investment income received 10,824,046
Proceeds from investment sales and maturities of investments 1,994,014 Purchase of investments (62,281,724)
Net cash provided (used) by investing activities (49,463,664) Net change in cash and cash equivalents 32,810,555
Cash and cash equivalents at beginning of year 301,442,110 Cash and cash equivalents at end of year $ 334,252,665
Reconciliation to the Statement of Net Position
Cash and cash equivalents (unrestricted) $ 319,565,492
Restricted cash - current 14,040,173
Restricted cash - noncurrent 647,000
Cash and cash equivalents $ 334,252,665
NONCASH INVESTING ACTIVITIES
Unrealized appreciation and timing differences in investment income $ 1,305,524
NONCASH CAPITAL AND RELATED
FINANCING ACTIVITIES
Acquisition of lease asset $ 1,284,053
SAN DIEGO COMMUNITY POWER
STATEMENT OF CASH FLOWS
Eleven Months Ended May 31, 2025
See accountants' compilation report. 4
23 Operating income $ 23,433,876
Adjustments to reconcile operating income to net
cash provided by operating activities
Depreciation and amortization expense 630,156
(Increase) decrease in:
Accounts receivable, net 14,282,557
Accrued revenue 28,749,321
Prepaid expenses 23,559,478
Other receivables 3,261,162
Deposits 1,291,661
Increase (decrease) in:
Accrued cost of electricity (25,476,688)
Accounts payable (4,007,863)
Advances from grantors 13,540,173
Other accrued liabilities 1,174,671
State surcharges payable (181,623)
Deposits - energy suppliers 3,003,181
Net cash provided by operating activities $ 83,260,062
SAN DIEGO COMMUNITY POWER
STATEMENT OF CASH FLOWS (continued)
Eleven Months Ended May 31, 2025
RECONCILIATION OF OPERATING INCOME TO NET
CASH PROVIDED BY OPERATING ACTIVITIES
See accountants' compilation report.
24 5
1 ACCOUNTANTS’ COMPILATION REPORT
Board of Directors
San Diego Community Power
Management is responsible for the accompanying operating fund and capital investment program fund budgetary comparison schedules of San Diego Community Power (SDCP), a California Joint Powers Authority, for the eleven months ended May 31, 2025 and for determining that the budgetary basis of accounting is an acceptable financial reporting framework. We have performed a compilation engagement in accordance with Statements on Standards for Accounting and Review Services promulgated by the Accounting and Review Services Committee of the AICPA. We did not audit or review the accompanying statement nor were we required to perform any procedures to verify the accuracy or completeness of the information provided by management. Accordingly, we do not express an opinion, a conclusion, nor provide any assurance on this special purpose budgetary comparison statement.
These special purpose statements are prepared in accordance with the budgetary basis of accounting, which is a basis of accounting other than accounting principles generally accepted in the United States of America. This report is intended for the information of the Board of Directors of SDCP.
Management has elected to omit substantially all of the note disclosures required by accounting principles generally accepted in the United States of America in these interim financial statements.
SDCP’s annual audited financial statements will include the note disclosures omitted from these interim statements. If the omitted disclosures were included in these financial statements, they might influence the user’s conclusions about the Authority’s financial position, results of operations, and cash flows.
Accordingly, these financial statements are not designed for those who are not informed about such matters.
We are not independent with respect to SDCP because we performed certain accounting services that impaired our independence.
Maher Accountancy
San Rafael, CA
July 1, 2025
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com 25 Amended
Budget Actual
Amended
Budget Variance
(Under) Over
Actual/
Amended
Budget %
Amended
Budget
Amended
Budget
Remaining
REVENUES AND OTHER SOURCES
Gross Ratepayer Revenues 1,121,291,483 $ 1,129,126,348 7,834,865 101% 1,243,010,863 $ 113,884,515 Less: Uncollectible Customer Accounts (19,622,601) (14,020,648) 5,601,953 71% (21,752,690) (7,732,042) Other Income 1,268,258 - 1,268,258 na (1,268,258) -
Total Revenues and Other Sources 1,101,668,882 1,116,373,958 14,705,076 1,221,258,173 104,884,215
OPERATING EXPENSES
Cost of Energy 1,040,030,756 1,045,476,896 5,446,140 101% 1,116,836,549 71,359,653 Professional Services and Consultants 22,317,493 16,839,683 (5,477,810) 75% 24,346,342 7,506,659 Personnel Costs 17,020,564 14,616,297 (2,404,267) 86% 18,567,895 3,951,598 Marketing and Outreach 2,730,391 1,751,151 (979,240) 64% 2,978,593 1,227,442 General & Administrative 4,500,614 2,673,050 (1,827,564) 59% 4,909,761 2,236,711 Total Operating Expenses 1,086,599,818 1,081,357,077 (5,242,741) 1,167,639,140 86,282,063 Operating Income (Loss) 15,069,064 35,016,881 19,947,817 53,619,033 18,602,152
NON-OPERATING REVENUES (EXPENSES)
Investment Income 12,129,570 - 12,129,570 na (12,129,570) - Interest and Related Expenses (1,169,667) (1,540,844) (371,177) 132% (1,276,000) 264,844 Transfer to Capital Investment Program (18,175,030) (18,175,030) 100% (18,175,030) - - Total Non-Operating Revenues (Expenses) (19,344,697) (7,586,304) 11,758,393 (19,451,030) (11,864,726) NET CHANGE $ (4,275,633) $ 27,430,577 $ 31,706,210 $ 34,168,003 $ 6,737,426
SAN DIEGO COMMUNITY POWER
BUDGETARY COMPARISON SCHEDULE
Eleven Months Ended May 31, 2025
OPERATING FUND
Year-to-Date Annual
See accountants' compilation report.
26 SAN DIEGO COMMUNITY POWER
Staff Report – Item 3
____________________________________________________________________________________ TO: Board of Directors
FROM: Jack Clark, Chief Operating Officer
Colin Santulli, Senior Director of Programs
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Update on Programs
DATE: August 28, 2025
____________________________________________________________________________________ RECOMMENDATION:
Receive and file update on customer energy programs.
BACKGROUND:
Staff will provide regular updates to the Board of Directors (“Board”) regarding the following Community Power customer energy programs: Commercial Programs, Residential Programs, Flexible Load Programs, Solar + Energy Storage Programs, and San Diego Regional Energy Network.
ANALYSIS AND DISCUSSION:
Updates on customer energy programs are detailed below.
Commercial Programs
Commercial Application Assistance Pilot Project
Status and Next Steps: Please refer to Item 4 of the June 2025 Board of Directors staff report for the most recent update on this pilot project. Staff anticipate bringing an update as an agenda item to the September 2025 meeting.
Efficient Refrigeration Pilot Project
Status: Staff began outreach for the Efficient Refrigeration Pilot in March 2025. Eligible corner stores, small businesses, and nonprofits in low-income and low-food-access areas within Community Power’s service territory can receive up to two energy-efficient refrigerators and/or freezers and an American Society of Heating, Refrigerating, and Air-Conditioning Engineers (“ASHRAE”) Level 1 energy audit at no cost to the participant.
The pilot aims to serve a total of 24 participants. To date, Staff have been conducting targeted outreach for the pilot primarily by engaging member agency staff, elected 27 officials, and community organizations. As of August 12, 2025, 16 participants have been enrolled in the pilot.
Next Steps: Staff will continue to conduct outreach and enroll participants in the pilot until grant funds are expended.
Residential Programs
California Energy Commission (“CEC”) Equitable Building Decarbonization Direct Install (“EBD DI”) Program
Status: Staff continues to work with Los Angeles County (“LA County”) to prepare for the launch of the EBD DI Program. LA County has communicated that they now expect the EBD DI program to launch at the end of Q3 2025 (originally anticipated summer 2025).
Staff is collaborating with the Public Affairs team to activate the Power Network and contract with community-based organizations (“CBOs”) to implement and support marketing, outreach, and education (“ME&O”) to recruit residents.
Next Steps: Staff are working with LA County to prepare for the launch of the EBD DI program. Staff will continue to work with the Public Affairs team to release a solicitation to CBOs that can do ME&O activities for the EBD DI program.
Flexible Load Programs
Smart Home Flex Pilot Project
Status and Next Steps: Please refer to Item 3 of the June 2025 Board of Directors staff report for the most recent update on this pilot project.
EV Flex Connect Pilot Project
Status and Next Steps: Please refer to Item 3 of the June 2025 Board of Directors staff report for the most recent update on this pilot project.
Solar and Energy Storage Programs
Disadvantaged Communities–Single-Family Affordable Solar Homes (“DAC-SASH”) Readiness Pilot Project Status and Next Steps: Please refer to Item 5 of the March 2025 Board of Directors staff report for the most recent update on this pilot project. Staff anticipate bringing an update as an agenda item to the September 2025 meeting.
Net Energy Metering (“NEM”) and Net Billing Tariff (“NBT”) Status and Next Steps: Please refer to Item 2 of the December 2023 Board staff report for the most recent update on this program.
Solar Battery Savings (“SBS”) Program
Status: Staff continue to work on a variety of activities in anticipation of relaunching the SBS Program in late September 2025. Staff held an in-person contractor information session in May 2025 to provide program updates to interested installers. On August 7, 28 2025, over 20 attendees representing 11 different Original Equipment Manufacturers (OEM) attended the virtual information session to provide program updates including requirements for participation in the program. Staff are currently redesigning the contractor portal used in the SBS Pilot to enable increased efficiency and quality control for the relaunched program.
Next Steps: Staff will continue to work on program relaunch activities including testing the revised contractor portal, developing program marketing materials and engaging contractors. Staff anticipate hosting several contractor training sessions in September for installers interested in enrolling in the program. Staff anticipate opening the program for applications on September 30, 2025.
Solar Advantage Program
Status: On June 16, 2025, Staff requested a second extension from the California Public Utilities Commission (“CPUC”) to continue negotiating a Power Purchase Agreement (“PPA”) for the Solar Advantage program. The CPUC approved Community Power’s extension request and Community Power now has until November 6, 2025 to finalize negotiations, bring the agreement before the Board of Directors for consideration, and submit to the CPUC for approval.
On July 4, 2025, the CPUC issued Resolution E-5368 regarding the Methodology for Setting the Confidential Benchmark Value Reference Price (“CBVRP”). Please refer to Item 20 of the Regulatory and Legislative staff report on the August Board of Directors Agenda.
Next Steps: Staff will continue to negotiate with the remaining eligible offer from the first RFO. Staff plans to bring this PPA to a Board of Directors meeting for review and approval later this year.
Community Power will begin the process of updating the cost containment cap as directed by E-5368 prior to launching the next solicitation.
San Diego Regional Energy Network (“SDREN”)
SDREN
Status: Staff continue activities required for the successful launch of SDREN programs with a focus on procurement. In December 2024, Staff developed a phased schedule to release solicitations for program implementers. The Phase 1 solicitations (administrative, regulatory, and reporting support a cross-cutting sector programs) were released on February 4, 2025 and closed on March 25, 2025. The Phase 2 solicitations (residential and public sector programs) were released on March 6, 2025 and closed on April 24, 2025. The Phase 3 solicitation (commercial sector programs) was released on May 8, 2025 and closed on June 26, 2025.
Next Steps: Staff will initiate contract negotiations with the selected vendors from the Phase 3 solicitation and finalize contract negotiations with the selected vendors from the Phase 1 and 2 solicitations. Staff anticipate the Phase 1 contracts to be executed in 29 August 2025, the Phase 2 contracts to be executed in September 2025, and the Phase 3 contracts to be executed in November 2025 in accordance with Resolution No. 2025-01 adopted by the Board on January 23, 2025, authorizing the Chief Executive Officer to ‘negotiate and execute contracts with third parties to implement the agreement or use of [SDREN] funds’.
Contracts are expected to be executed with selected vendors with amounts not exceeding the budgets stated in the solicitations:
Phase 1
• Administrative, Technical, and Compliance Support: $800,000 • Codes and Standards Program: $5,556,916
• Energy Pathways Program: $5,556,916
• Workforce Training and Capacity Building Program: $9,030,024 Phase 2
• Climate Resilience Leadership Program: $9,740,641 (direct implementation), $7,442,846 (incentives)
• Tribal Engagement Program: $1,389,551
• Single-Family Program: $6,367,475 (direct implementation), $12,416,267 (incentives)
• Multifamily Program: $3,492,276 (direct implementation), $6,539,071 (incentives) Phase 3
• Efficient Refrigeration Program: $2,028,045 (direct implementation), $4,074,678 (incentives)
• Market Access Program: $4,597,330 (direct implementation), $9,006,228 (incentives)
• Small-to-Medium Business Energy Coach Program: $6,567,110 (direct implementation), $2,016,518 (incentives)
SDREN funds are authorized by the California Public Utilities Commission and are disbursed to San Diego Community Power in accordance with the San Diego Regional Energy Network Energy Efficiency Programs and Budget Agreement for Years 2024-2027 executed between Community Power and SDG&E (under Resolution No. 2025-01).
FISCAL IMPACT:
N/A
ATTACHMENTS:
N/A
30 SAN DIEGO COMMUNITY POWER
Staff Report – Item 4
TO: Board of Directors
FROM: Gordon Samuel, Chief Commercial Officer
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Update on Power Services
DATE: August 28, 2025
RECOMMENDATION:
Recommendation to receive and file update on Power Services.
BACKGROUND:
Staff provide the updates below to the Board of Directors regarding Community Power’s energy procurement activities.
ANALYSIS AND DISCUSSION:
Power Services Staffing
Building out a team of experienced, knowledgeable energy professionals has long been a top priority and allows Community Power not only to solicit, negotiate, and administer contracts for energy supply effectively, but also to monitor market activity, manage risk, bring in-house several activities that have historically been completed by consultants, and to dedicate additional resources to local and distributed energy procurement and development efforts. The Power Services team is now thirteen people strong. The Power Services team welcomed a new Chief Commercial Officer this month, has two open positions currently in the interview stage, and is excited to continue stable, prudent growth through 2025.
Administrative Amendment Updates
In May 2025, the CEO signed an administrative amendment to the Sunzia Power Purchase Agreement to allow the developer, Pattern Energy, to operate the turbines at a higher nameplate capacity to facilitate maximum import capacity expansion.
In July 2025, the CEO signed an amendment to the MRP Enterprise Agreement. That project had its battery portion delayed from June 2026 to June 2027. In the amendment the battery commercial operation date was adjusted and Community Power received replacement products from June 2026 to May 2027.
31 Long-term Renewable Energy Solicitations
As Community Power strives to meet its environmental, financial, and regulatory compliance goals and requirements, long-term power purchase agreements (PPAs) provide developers with the certain revenue stream against which they can finance up-front capital requirements, so each long-term PPA that Community Power signs with a developing facility will underpin a new, incremental renewable energy project. In addition, long-term PPAs lock in renewable energy supply around which Community Power can build its power supply portfolio while also providing power supply cost certainty. Moreover, the California Renewable Portfolio Standard (RPS), as modified in 2015 by Senate Bill 350, requires that Community Power provide 65% of its RPS-required renewable energy from contracts of at least ten years in length. Finally, in California Public Utilities Commission (CPUC) Decision (D.) 21-06-025, the CPUC required each Load Serving Entity (LSE) in California to make significant long-term purchase commitments for resource adequacy from new, incremental generation facilities that will achieve commercial operation during 2023 through 2026 for purposes of “Mid Term Reliability” (MTR). These requirements have been augmented and extended into 2026 and 2027 via CPUC D.23-02-040.
In pursuit of long-term contracts for renewable energy and storage, over the past 24 months, staff have released several Requests for Offers (RFOs) and Requests for Proposals (RFPs). Most recently, staff issued an RFO targeted for clean-firm resources (e.g. geothermal, bioenergy potential) in April to help achieve MTR requirements and increase technology diversity in Community Power’s portfolio. Staff have over two dozen long-term contracts executed for energy, renewable energy credits and/or capacity from renewable and storage projects.
Staff remain in negotiations for additional resources that are expected to be online between 2026 and 2029. Staff and the Energy Contracts Working Group (ECWG) evaluate all submissions from solicitations prior to entering negotiations with selected participants. Assuming that staff and shortlisted developer(s) can agree to mutually agreeable contracts consistent with terms authorized by the ECWG, staff then review draft terms with the Community Power Board for approval and authorization to execute the relevant documents.
Local Development
Community Power’s rolling Local RFI remains open and has yielded eight Board-approved contracts for local generation and storage facilities. After consultation with the ECWG, Community Power Board of Directors has approved a portfolio of PV PPAs and energy storage and service agreements and is actively negotiating with several local projects submitted to the Local RFI in Q4 2024. Community Power also released an RFO for distributed renewable energy resources (DERs), focusing on a broad range of distribution-level renewable projects within San Diego County. Additional agreements resulting from the RFO are expected and will be presented to the Board when ready.
Other ongoing local initiatives include a Feed-in-Tariff Program revamp and expansion, expected in the second half of this year, and continued collaboration with member agency staff and other local agencies to identify strategic opportunities to further infill development.
32 As Program Administrators of the CPUC’s Disadvantaged Communities Green Tariff (DAC-GT) program, Community Power completed its first solicitation last year. The first DAC-GT PPA, with Luminia LLC, a local developer, was presented to and approved by the Board in January. The second DAC-GT solicitation round was released on April 7th and will be accepting offers through September 8th.
Community Power’s Local RFI and Feed-in Tariff remain open. More information is available about each at the links below:
• https://sdcommunitypower.org/resources/solicitations/ • https://sdcommunitypower.org/programs/feed-in-tariff/ Short-Term RPS Procurement
Community Power staff continue to actively manage its environmental portfolio and closely monitor the market for opportunities to optimize its renewable and carbon-free portfolios. Community Power has recently been evaluating solicitation offers, bilateral offers, and products that meet needs for multiple portfolios – creating greater value for its customers. Community Power will continue to prioritize environmental targets while also ensuring value for our customers.
Market Update
Due to limited resource availability in the broader Western Interconnection, lingering supply chain impacts and long interconnection queues that have delayed development of new-build energy resources, and implementation of tariffs and duties on foreign imports, the market for renewable energy and resource adequacy (RA) continues to be tight and expensive. Staff are working with developers, industry groups, the CPUC, and CA Governor’s Office and legislators to i) develop near-term solutions while also actively procuring short-term energy and capacity products and long-term energy resources to meet Community Power 's portfolio needs practically and cost-effectively, and ii) to establish a portfolio of resources that will provide value to Community Power and California's clean, reliable energy needs into the future.
Near-term California power markets remain steady due to normal summer weather and reliable power supply. Summer forecasts have indicated higher chances of above normal temperatures throughout the West, with slightly lower chances in coastal locations. No supply shortfalls are expected, but markets remain sensitive to extreme weather events and unexpected supply shortages.
FISCAL IMPACT:
N/A
ATTACHMENTS:
N/A
33 SAN DIEGO COMMUNITY POWER
Staff Report – Item 5
____________________________________________________________________________________ TO: Board of Directors
FROM: Jack Clark, Chief Operating Officer
Lucas Utouh, Senior Director of Data Analytics and Customer Operations
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Update on Customer Operations
DATE: August 28, 2025
____________________________________________________________________________________ RECOMMENDATION:
Receive and file an update on various customer operations’ initiatives.
BACKGROUND:
Staff will provide regular updates to the Board of Directors centered around tracking customer opt actions (i.e., opt outs, opt ups, opt downs, and re-enrollments) as well as customer engagement metrics. The following is a brief overview of items pertaining to customer operations.
ANALYSIS AND DISCUSSION:
A) Enrollment Update
As of July 28, 2025, Community Power is serving a cumulative total count of 961,299 active accounts.
Customers with newly established accounts or who have moved into a new service address within any and all of our member jurisdictions receive 2 post-enrollment notices through the mail at their mailing address on file within 60 days of their account start date to notify them that they have defaulted to Community Power electric generation service. 34 B) Customer Participation Tracking
The below charts summarize customer elections into San Diego Community Power’s four (4) available service levels:
35 36
37 38
39 40
41 D) Contact Center Metrics
As anticipated, call volumes have remained steady as a result of the temperate weather and lower winter electricity rates. We anticipate that calls will increase as customers begin to receive bills for usage spanning the summer months (i.e., June 1 – October 31).
The chart below summarizes contact made by customers into the Contact Center broken down by month:
42 San Diego Community Power anticipates the trend of customers calling into the Contact Center’s Interactive Voice Response (IVR) system tree and being able to self-serve their opt actions using the recorded prompts as well as utilizing Community Power’s website for processing opt actions will continue to account for over 65% of all instances. The remaining portion of customer calls are connected to Customer Service Representatives to answer additional questions, assist with account support, or process opt actions.
As of this latest reporting month, Community Power has 9 Dedicated Customer Service Representatives staffed at the Contact Center and 1 Supervisor. Robust Quality Assurance (QA) procedures are firmly in place to ensure that customers are getting a world-class customer experience when they contact Community Power.
D) Joint Rate Comparison
San Diego Community Power and San Diego Gas & Electric (SDG&E) have jointly created a comparison of our typical electric rates, average monthly bills and electric generation power sources. SDG&E implemented adjustments to its electric rates effective June 1, 2025. Community Power updated its electric rates on February 1, 2025. The California Public Utilities Commission (CPUC) requires that this comparison be posted online within 60 days of each rate change, and the most recent Joint Rate Comparison can be accessed here: SDCP_SDGE JRC 06.01.2025_Final.pdf.
FISCAL IMPACT:
N/A
ATTACHMENTS:
N/A
43 SAN DIEGO COMMUNITY POWER
Staff Report – Item 6
____________________________________________________________________________________ TO: Board of Directors
FROM: Jack Clark, Chief Operating Officer
Stephen Yi, Associate Director of IT and Data Analytics VIA: Karin Burns, Chief Executive Officer
SUBJECT: Update on IT and Data Analytics
DATE: August 28, 2025
____________________________________________________________________________________ RECOMMENDATION:
Receive and file an update on IT and Data Analytics.
BACKGROUND:
Community Power onboarded the Associate Director of IT and Data Analytics in February 2025 to continue its commitment to building a world-class in-house IT and analytics service team. In recent months, the IT and Data Analytics teams have led key technology projects aimed at simplifying processes, transforming operations, and improving effectiveness with low-cost, efficient solutions. Improvements in cybersecurity measures were also implemented.
ANALYSIS AND DISCUSSION:
The IT and Data Analytics staff have implemented several critical initiatives in the past 6 months that are already delivering efficiency and value for the agency, including:
• Completed Milestone 1 Release of Enterprise Data Platform to Production, including:
o Back-end system infrastructure, platform design, codebase and deployment using CI/CD process.
o Establishment of end-to-end data engineering pipelines using medallion architecture.
o Automated API data ingestion, storage and pipelines of core customer data. o Establishment of Business Intelligence (BI) workspace for internal reports. o Establishment of database for core customer data.
o End-to-end MLOps framework for Data Science model development, training and deployment.
44 • Onboarded new Data Analyst to support reporting needs and internal data requests.
• Collaborated with Customer Programs on analytics deliverables to support upcoming Solar Battery Savings Program.
• Established a cross-departmental team to assess, identify and document organization-wide systems and platforms.
• Creation of AI committee to assess responsible use of potential AI tools organization wide.
• Completed annual device inventory audit.
• Streamlined device replacement process.
• Enhanced device management and IAM (Identity Access Management) protocols across the organization.
• Deployed new internal IT/Data Analytics support ticketing system. • Delivered cybersecurity training to all staff.
• Leveraged Microsoft M365 E5 licensing for improved cybersecurity posture.
FISCAL IMPACT:
N/A
ATTACHMENTS:
N/A
45 SAN DIEGO COMMUNITY POWER
Staff Report – Item 7
______________________________________________________________________ TO: Board of Directors
FROM: Chandra Pugh, Senior Director of People Operations and Administration VIA: Karin Burns, Chief Executive Officer
SUBJECT: Human Resources Update
DATE: August 28, 2025
______________________________________________________________________ RECOMMENDATION:
Receive and file update on human resources.
BACKGROUND:
Staff will provide regular updates to the Board of Directors (“Board”) regarding human resources updates.
ANALYSIS AND DISCUSSION:
The Human Resources team successfully recruited and welcomed three new employees since July.
We are excited to welcome Gordon Samuel to Community Power as our new Chief Commercial Officer. Gordon will oversee our power services team and portfolio as the newest member of our executive team. Gordon comes to us with 25 years of electric utility experience, most recently with Valley Clean Energy as its Chief Operating Officer also overseeing power procurement.
Prior to VCE, he was a Sr. Power Resources Manager at Marin Clean Energy and before that held various senior leadership roles at Arizona Public Service (APS), the largest electric utility (IOU) in Arizona. For two decades at APS, he was involved in leading asset management, resource planning, trading, contract management, safety, and operational efficiency, managing teams of up to 20 direct reports.
He has an engineering degree from Penn State, an MBA, and a long history of volunteering in his community.
46 Aoife (pronounced ee-fuh) Maxwell has joined the Public Affairs team as our first Community Outreach Representative.
Aoife holds a BA in International Business with a Marketing concentration from Northeastern University and is finishing up a Sustainability Community Outreach and Reporting Fellowship at the City of Encinitas. She will continue to professionalize our outreach efforts and direct customer engagement by being an ambassador of Community Power at outreach events.
Pete Polansky joined the Customer Operations and Data Analytics team as a Senior Rates Analyst.
Pete is passionate about renewable energy and addressing climate change quickly and equitably. He recently graduated from the University of California San Diego Scripps Institute of Oceanography with a Master of Advanced Studies in Climate Science and Policy.
His previous professional experience includes distributed energy resource program development, grid planning, resource procurement, innovative rate design, and incorporating energy equity into analysis and decision-making at the Hawaii Public Utilities Commission.
Current open positions include:
Account Services Analyst
Key Account Services Analyst
Portfolio Analyst
Senior Origination Associate
FISCAL IMPACT:
N/A
ATTACHMENTS:
N/A
47 SAN DIEGO COMMUNITY POWER
Staff Report – Item 8
____________________________________________________________________________________ TO: Board of Directors
FROM: Jack Clark, Chief Operating Officer
Jen Lebron, Senior Director of Public Affairs
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Community Advisory Committee Monthly Report
DATE: August 28, 2025
____________________________________________________________________________________ RECOMMENDATION:
Receive and file the Community Advisory Committee (CAC) monthly report.
BACKGROUND:
Per Section 5.10.3 of the San Diego Community Power (Community Power) Joint Powers Authority Agreement:
The Board shall establish a Community Advisory Committee comprised of non-Board members. The primary purpose of the Community Advisory Committee shall be to advise the Board of Directors and provide a venue for ongoing citizen support and engagement in the strategic direction, goals, and programs of SDCP.
At the direction of the Board Chair, the CAC provides quarterly presentations to the Board of Directors on the regular agenda and monthly reports on the consent agenda. The next quarterly update is expected to take place at the September 25, 2025 Board meeting. The CAC observed a July meeting recess.
ANALYSIS AND DISCUSSION:
During the August 14, 2025, regular CAC meeting:
• Chair Harris (City of La Mesa) welcomed new Community Power staff, and led the unanimous approval of the consent agenda, which included updates on Customer Operations, Marketing, Public Relations and Local Government Affairs, Power Services, and Programs, as well as a Load Management Standards Compliance Plan Update.
48 • The CAC received the quarterly Regulatory and Legislative Affairs Update.
Members relayed concerns around a variety of state bills and encouraged staff to return with additional information about how Federal actions are making an impact on state and local matters.
• The CAC received an update on the San Diego Regional Energy Academy, which members lauded as a critical, valuable Community Power initiative that has already made a significant impact on raising the energy knowledge of stakeholders in the region.
• The CAC also learned about the Results from Clean Prepayment Transaction No.
2. Members had questions about the mechanics of the transaction and how Community Power’s long-term power purchase agreements give the agency an opportunity to receive discounts on payment.
• Members shared announcements on community activities, including how the Sierra Club is seeking volunteer “champions” in each agency in San Diego County to audit climate action plans. Members also noted that the Electric Vehicle Association of San Diego hosts monthly events at the San Diego Automotive Museum.
• No Board of Directors items were recommended.
As of August 28, 2025, the CAC has one vacancy representing the City of Encinitas.
Members of the public must be residents, community leaders, and/or business owners of the respective jurisdictions and may submit their applications electronically. The vacancy continues to be advertised at meetings, community events, and through Community Power’s social media.
FISCAL IMPACT:
N/A
ATTACHMENTS:
N/A
49 SAN DIEGO COMMUNITY POWER
Staff Report – Item 9
____________________________________________________________________________________ TO: Board of Directors
FROM: Jack Clark, Chief Operating Officer
Jen Lebron, Senior Director of Public Affairs
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Update on Marketing, Public Relations, and Local Government Affairs DATE: August 28, 2025
____________________________________________________________________________________ RECOMMENDATION:
Receive and file an update on marketing, public relations, and local government affairs activities for San Diego Community Power (Community Power).
BACKGROUND:
Community Power has engaged in a variety of public relations, marketing, community outreach, and local government affairs activities to drive awareness, spark community engagement, and maintain high customer enrollment.
ANALYSIS AND DISCUSSION:
Community Power’s Public Affairs Department has been participating in events across our member agencies as it aims to increase general awareness and answer questions in a friendly, helpful manner.
Recent and Upcoming Public Engagement Events
EcoFest Encinitas
Connect San Diego Summer Social
Building Industry Association
Ruby Awards
Working Waterfront
Chula Vista Community Collaborative
Economic Development Tribal Convening
San Diego Padres
Community Clean Energy Celebration
San Diego Regional Climate Collaborative Circle of Influence Reception 50 Fallbrook Nonprofit Expo
Port of San Diego’s Day at the Park – Bayfront Park
San Diego Regional Chamber of Commerce Congressional Luncheon Imperial Beach Collaborative
Suncoast Imperial Beach Farmer’s Market
Sustainable Solutions Fair
Community Climate Conversations – Pacific Beach
Utilities Fair for seniors
San Diego County Movie in the Park – Lakeside
Equality California Pride Celebration
San Diego Pride Parade
Loma Verde Elementary Back-to-School Resource Fair
Olivewood Gardens Day of Play
Business for Good Summer Mixer
National Night Out
San Diego Military Summit
Summer Bash Business Expo
Beautify the Block
Chula Vista Community Collaborative
Mt. Hope Community Garden Farmers Market
National City Collaborative
Imperial Beach Collaborative
Chula Vista Lemon Festival
San Diego County Movie in the Park – MacArthur Park
Bike the Bay
San Diego Wave Fútbol Club
Marketing, Communications and Outreach
The Public Affairs team has been working diligently behind the scenes to support programmatic efforts, including the launch of the San Diego Regional Energy Network and relaunch of the Solar Battery Savings program. It is also ramping up efforts to promote pilot programs, including one that helps customers repair their roofs to be ready for solar installations, and another that will distribute grants to small businesses that would benefit from more efficient refrigerators. The Public Affairs team is working closely with internal and external stakeholders to encourage participation in these programs and leveraging relationships with community partners to amplify our marketing and outreach efforts.
The Marketing and Communications division has also been working on a website refresh and brand update. After a survey of more than 4,700 stakeholders including customers, board members, CAC members and staff, the team is making improvements to the website to enhance navigability and increase accessibility. The website will be officially launched in fall. As a companion to the website update, Community Power brand standards are being refreshed to create more easily recognizable, consistent imagery. 51 Community Power has continued its efforts to connect with local leaders through meetings and at community events.
The Public Affairs team will continue to develop new strategies, processes and capacity over the next several months to conduct more community outreach, expand marketing and brand awareness efforts, and provide timely, accurate information across multiple channels.
Local Government Affairs
Community Power continues to meet with and work with local governments and tribal nations throughout the greater San Diego region. It has made a concerted effort to reach out to newly elected officials in all seven member agencies to provide education about the organization.
FISCAL IMPACT:
N/A
ATTACHMENTS:
N/A
52 SAN DIEGO COMMUNITY POWER
Staff Report – Item 10
______________________________________________________________________ TO: Board of Directors
FROM: Jack Clark, Chief Operating Officer
Lucas Utouh, Senior Director of Data Analytics and Customer Operations
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Approval of Load Management Standards Compliance Plan Update DATE: August 28, 2025
______________________________________________________________________ RECOMMENDATION:
Approval of San Diego Community Power (Community Power) Load Management Standards (LMS) Compliance Plan update.
BACKGROUND:
On April 1, 2023, the California Energy Commission (CEC) adopted amendments to the LMS, which requires all large utilities and community choice aggregators (CCAs) to (1) develop retail electricity rates that change at least hourly and list of cost-effective load flexibility programs to better reflect grid costs and greenhouse gas (GHG) emissions and apply for approval by their governing board, (2) maintain up-to-date rates in CEC’s new central repository for rate information, Market Informed Demand Automation Server (MIDAS), and (3) establish public outreach and education to customers about time-dependent rates and automation technologies. Each large utility and CCA was directed to develop and submit a compliance plan to the CEC describing actions they will take to meet the goals of the LMS amendments. The Board of Directors approved Community Power’s LMS Compliance Plan during the February 22, 2024 meeting and the Compliance Plan was timely filed with the CEC Docket Number 23-LMS-01 on March 7, 2024.
ANALYSIS AND DISCUSSION:
Community Power’s LMS Compliance Plan includes considerations of the specified marginal cost-based rate structures and programs and evaluates the rate structures and programs with respect to cost-effectiveness, equity, technological feasibility, and benefits to the grid and to customers. Based on Community Power staff evaluation, the conclusion is that implementing complex new rate structures that change at least hourly by July 1, 53 2027, would not be cost effective nor result in material benefits to our customers or promote grid reliability at this time. The implementation of new and complex rate structures without review of pilot study results, sufficient testing, and refinement of the new rate designs would likely result in low customer adoption and/or confusion. Instead, Community Power intends to utilize its load flexibility programs to meet LMS compliance instead of implementing real-time pricing rates.
After the Compliance Plan was filed within the CEC Docket, CEC staff reviewed the document and provided feedback and requested revisions in April 2025. CEC staff’s requests include the following items.
1. Clarify information about the circumstances to substantiate that real-time pricing rates are not yet feasible or cost effective and confirm that load flexibility programs will be used instead for compliance.
2. Update and expand information for the list of load flexibility programs that will be used for compliance, including customer class and end use requirements, program design, incentive structure, and interactions with MIDAS.
3. Include a discussion on what customer classes can participate in the load flexibility programs and if any, why certain customer classes are not yet covered at this time.
4. Insert CEC developed language on coordination with other load serving entities on creating a statewide tool.
Community Power staff reviewed CEC staff feedback and requests and updated the LMS Compliance Plan (Attachment A) accordingly. The updates include information that clarify and include additional details on the Board of Directors’ approved Community Power load flexibility programs. The updated LMS Compliance Plan continues to address LMS update requirements and evaluates the potential implementation impacts on Community Power operations and customers based on the latest existing information.
Next Steps
In the LMS Compliance Plan, Community Power describes the pathway and details of achieving LMS goals that are most cost-effective, customer oriented, and technologically feasible. Community Power staff will bring the LMS Compliance Plan to the Board of Directors for review and approval on August 28, 2025, and upon adoption, submit the updated Compliance Plan to the Executive Director of the CEC for approval. Due to the collaborative approach working with CEC staff, their recommendation will be for the CEC Executive Director to approve Community Power’s revised LMS Compliance Plan.
Community Power will continue to offer time-variant rates that customers are familiar with and develop and implement load flexibility programs. In parallel, Community Power is currently implementing one or more demand flexibility program pilots to evaluate marginal cost-based programs. Community Power will also re-evaluate the specified rate and 54 program designs in the next update of the LMS Compliance Plan, informed by future pilot study results.
FISCAL IMPACT:
N/A
COMMITTEE REVIEW:
This item was presented to the Community Advisory Committee at their meeting on August 14, 2025. Committee members received and filed the report.
STRATEGIC PLAN:
1. Deliver 150 Megawatts of local capacity from distributed energy resources (DERs) and our Virtual Power Plant (VPP) by 2035, including expansion of the Solar Battery Savings program.
2. Evolve rate strategy to ensure competitiveness, affordability, and fiscal sustainability.
ATTACHMENTS:
A: San Diego Community Power Load Management Standards Compliance Plan Update 55 ITEM 10
ATTACHMENT A
56 1
San Diego Community Power
Load Management Standards
Compliance Plan
August 1, 2025
57 2
Table of Contents
1. Executive Summary...............................................................................................................................4
2. Introduction ..........................................................................................................................................5
2.1 About SDCP..................................................................................................................................5
2.1.1 Community Clean Energy Innovation Grants Program...........................................................6
2.1.2 SDCP’s 100 Percent Renewable Energy Policy ........................................................................6
2.2 Load Management Standards .....................................................................................................7
2.2.1 SDCP’s Compliance Plan Roadmap..........................................................................................8
2.2.2 SDCP’s Compliance Plan Administration.................................................................................9
3. Access to Price Signals ........................................................................................................................10
3.1 Publication of Machine-Readable Rates in MIDAS....................................................................10
3.1.1 Upload of Time-Dependent Rates.........................................................................................11
3.1.2 Provide RINS to Customers...................................................................................................12
3.1.3 Statewide RIN Access Tool ....................................................................................................12
4. Dynamic Rates.....................................................................................................................................13
4.1 Overview of Current Time-Dependent Rates............................................................................14
4.1.1 Residential Rates...................................................................................................................15
4.1.2 Non-Residential Rates...........................................................................................................16
4.2 SDCP’s Rate Development Process............................................................................................16
4.2.1 Strategic Direction on Competitive Rates.............................................................................16
4.2.2 Rate Design and Implementation .........................................................................................17
4.3 Evaluation of New Dynamic Rates.............................................................................................17
4.3.1 Cost-Effectiveness.................................................................................................................18
4.3.2 Equity.....................................................................................................................................25
4.3.3 Technological Feasibility .......................................................................................................26
4.3.4 Benefits to the Grid and Customers......................................................................................28
4.3.5 Compliance Approach ...........................................................................................................30
5. Load Flexibility Programs....................................................................................................................31
5.1 Overview of SDCP Load Flexibility Programs.............................................................................31
5.1.1 LMS Compliant Load Flexibility Programs.............................................................................32
5.2 Evaluation of Programs .............................................................................................................36
5.2.1 Cost-Effectiveness.................................................................................................................37
5.2.2 Equity.....................................................................................................................................39 58 3
5.2.3 Technological Feasibility .......................................................................................................39
5.2.4 Benefits to the Grid and Customers......................................................................................40
5.2.5 Compliance Approach ...........................................................................................................41
6. Public Information Program................................................................................................................41
6.1 SDCP’s Communication Approach.............................................................................................42
6.2 Current Outreach and Marketing..............................................................................................42
6.3 Compliance Approach ...............................................................................................................43
7. Delay and Modification of Compliance Requirements.......................................................................43
7.1 Providing RINs to Customers.....................................................................................................44
7.2 Statewide RIN Access Tool.........................................................................................................44
7.2.1 Development of Statewide Tool ...........................................................................................44
7.2.2 Implementation of Statewide Tool .......................................................................................44
7.3 Dynamic Rates...........................................................................................................................44
7.4 Dynamic Response Load Flexibility Programs...........................................................................45
7.4.1 Identification of Cost-Effective Load Flexibility Programs....................................................45
7.4.2 Voluntary Participation in Cost-Effective Load Flexibility Programs.....................................46 Appendix A..................................................................................................................................................47 59 4
1. Executive Summary
Since 1974, the California Energy Commission (“CEC”) held the authority to establish and revise the Load Management Standards (“LMS”). On April 1, 2023, the CEC adopted amendments to the LMS, which require all large utilities and community choice aggregators (“CCAs”) to provide dynamic electricity rates in a format that can be shared and communicated with smart devices or service providers. The updated standards aim to assist customers to take better advantage of time-dependent rates, with the goal of decreasing overall costs by shifting energy use from peak to non-peak time periods. In addition, any technological and behavior changes, resulting from the LMS revisions, slow the rise of future energy costs, increase grid reliability, reduce the need for building more conventional power plants, and avoid transmission and distribution congestion.
The updated standards require all large publicly- and investor-owned utilities and Large1 CCAs to (1) develop retail electricity rates that change at least hourly and list of cost-effective load flexibility programs to better reflect grid costs and greenhouse gas (“GHG”) emissions and apply for approval by their governing board, (2) maintain up-to-date rates in CEC’s new central repository for rate information, Market Informed Demand Automation Server (“MIDAS”), and (3) establish public outreach and education to customers about time-dependent rates and automation technologies.
Each utility and CCA must develop and submit a compliance plan describing actions taken to meet the requirements of the LMS amendments. Specifically, publicly owned utilities and large CCAs may delay or modify compliance of each requirement if they can show that despite good faith efforts, that requirement must be modified to provide a more cost-effective, equitable, technologically feasible, or safe pathway to achieve the LMS goals.
San Diego Community Power (“SDCP”) firmly supports and aligns with the intent and goals of the LMS through its active load flexibility programs (described more in detail in Section 5) and its Community Clean Energy Innovation Grants Program2 as well as its 100 Percent Renewable Energy by 2035 Policy.3 The Community Clean Energy Innovation Grants Program aims to support scalable, replicable clean energy pilot projects that promote load flexibility and management, energy resilience, and increased access to clean energy technologies. Through the 100 Percent Renewable Energy Policy, SDCP’s Board of Directors establishes a firm commitment to achieve 100 percent renewable energy by 2035, thus eliminating GHG emissions from SDCP’s power supply. SDCP is actively pursuing pathways to reduce system peak, stress on the grids, GHG emissions, and customer costs through programs and pilots.
SDCP’s compliance plan (“Plan”) includes considerations of the specified marginal cost-based rate structures and programs, as described in the LMS requirements, 4 and evaluates the rate structures and
1 Large CCAs are defined as any CCA that provides in excess 700 GWh of electricity to customers in any calendar year.
2 San Diego Community Power Community Clean Energy Innovation Grants Policy, December 15, 2022, 2022-13- Community-Grant-Program-Policy.pdf (sdcommunitypower.org). 3 San Diego Community Power 100 Percent Renewable Energy by 2035 Policy, March 23, 2023, Item-12b-SDCP-100-Renewable-Energy-by-2035-Policy-c1.pdf (sdcommunitypower.org). 4 Barclays Official California Code of Regulations, § 1623.1. Large POU and Large CCA Requirements for Load Management Standards, April 1, 2023, View Document - California Code of Regulations (westlaw.com). 60 5
programs with respect to cost-effectiveness, equity, technological feasibility, and benefits to the grid and to customers.
Based on SDCP’s evaluation, the conclusion is such that implementing complex new rate structures that change at least hourly by July 1, 2027 would not be cost effective nor result in material benefits to our customers or promote grid reliability at this time. The implementation of new and complex rate structures without review of pilot study results, sufficient testing, and refinement of the new rate designs would likely result in low customer adoption and/or confusion. In addition, SDCP’s evaluation cannot conclude that implementing new programs that allow for automated response to MIDAS signals would result in material benefits, to be cost-effective at this time. However, SDCP has and will continue to implement and offer load flexibility programs, in lieu of offering a new marginal cost-based rate design, to support the intent and goals of the LMS and to meet LMS compliance.
SDCP describes the pathway and details of achieving LMS goals that are more cost-effective, customer oriented, and technologically feasible in Section 5. SDCP will continue to offer time-variant rates that customers are familiar with as well as develop and implement load flexibility programs. SDCP will reevaluate the specified rate and program designs in the next update of the Plan, informed by future pilot study results.
SDCP’s Plan was presented and submitted to SDCP’s Board of Directors (“Board”) within one year of the adoption of LMS amendments on April 1, 2023. The Plan was adopted by the Board at a duly noticed meeting on February 22, 2024, and this decision was made by SDCP’s Board acting as its rate-approving body. SDCP will review the Plan every three years following adoption, and material Plan updates will be submitted to the Board for approval. This Plan was timely filed with the CEC Docket No. 23-LMS-01 on March 7, 2024. The Plan was subsequently reviewed by CEC staff and CEC staff provided feedback and requested revisions on April 3, 2025. Revisions to the Plan were submitted to SDCP’s Board and adopted on August 28, 2025 are captured herein. The revised final Plan will be filed with the CEC for approval in 2025.
2. Introduction
2.1 About SDCP
SDCP is a Joint Powers Authority (“JPA”) formed by the communities of Chula Vista, Encinitas, Imperial Beach, La Mesa, and San Diego in October 2019. In November 2021, SDCP’s founding member agencies were joined by National City and the unincorporated areas of San Diego County. As a JPA, SDCP is a local government agency and is governed by a seven-member Board of Directors composed of elected representatives of its member local agencies. Through these representatives, SDCP is controlled by and accountable to the communities SDCP serves. SDCP provides retail electric generation services and complementary energy programs to customers within the municipal boundaries of its member local governments.
SDCP was formed to empower its member communities to choose the generation resources that reflect their individual values and needs. SDCP was established to procure and develop electrical energy for customers in participating jurisdictions, address climate change by reducing energy-related greenhouse gas emissions, promote electrical rate price stability and affordability, and foster local economic benefits such as job creation, local energy programs, and local power development while prioritizing equity. 61 6
SDCP commenced retail electric service to its first phase of customer enrollment in March 2021. As of April 2024, SDCP will successfully have completed its planned phase-in activities of all its member agencies. SDCP is currently serving approximately 956,000 service accounts, equal to approximately 670 gigawatt hours (“GWh”) of energy consumption per month.
At the service launch to customers, SDCP’s Board approved a minimum 50 percent renewable energy supply portfolio for all participating customers, with a 100 percent renewable retail service option available on a voluntary basis. These retail service offerings have been named “PowerOn” and “Power100,” respectively. The minimum quantity of renewable energy delivered to SDCP customers is expected to increase over time, moving to 85 percent by 2030. SDCP’s Board adopted two additional service options that came into effect on July 1, 2024. Power100 Green-e Certified is a product offering for businesses looking to meet Leadership in Energy and Environmental Design (“LEED”) standards.
PowerBase is the second product offering with a 47 percent renewable energy supply portfolio and less expensive compared to SDG&E’s default product offering.
2.1.1 Community Clean Energy Innovation Grants Program
On December 15, 2022, adopted through Board of Directors’ approval of Policy Number 2022-135, SDCP established a grant program aimed to support scalable, replicable clean energy pilot projects that provide economic, environmental, and health benefits to local communities and increase overall energy literacy of SDCP customers. Enabling load flexibility is addressed by three of the program’s five focus areas, including:
• Energy behaviors that reduce energy consumption and/or costs. • Energy resilience to ensure communities can avoid, prepare for, minimize, adapt to, and recover from energy disruptions.
• Increased access to the benefits of clean energy technologies with a focus on underserved communities and vulnerable populations.
In June 2023, grants totaling $390,000 were awarded to ten organizations. SDCP expects to receive progress updates from the organizations periodically.6 The program will run annually, and the next submission cycle will open in early 2024.
2.1.2 SDCP’s 100 Percent Renewable Energy Policy
On March 23, 2023, adopted through the Board of Directors’ Resolution 2023-03, SDCP’s 100 Percent Renewable Energy by 2035 Policy commits SDCP to achieving 100 percent renewable energy for its generation energy supply by 2035. The policy commits SDCP’s Chief Executive Officer to take all operational actions necessary to achieve this target. Annually, SDCP shall review progress towards this target at a Board meeting. As SDCP ramps up its energy supply towards 100 percent renewable energy, 5 San Diego Community Power, Community Grant Program Policy, https://sdcommunitypower.org/wp-content/uploads/2023/02/2022-13-Community-Grant-Program-Policy.pdf. 6 San Diego Community Power Community Clean Energy Innovation Grants Award Press Release, July 26, 2023,
23.07.26.SDCP_.SDF_.PressReleaseFinal.pdf (sdcommunitypower.org). 62 7
the organization is also committed to continue promoting electrical rate price stability and affordability and fostering local economic benefits.
Currently, SDCP is actively negotiating the offtake of renewable power from long-term projects of multiple technologies. Promoting the construction of renewable energy projects, in culmination with battery energy storage systems, will help with grid reliability as well as decreasing green-house-gas emissions that would be otherwise produced via conventional power generation. Current portfolio content is such that after providing 100 percent RPS for Power100 customers, PowerOn is tracking towards serving customers with 75 percent RPS by 2027. SDCP’s new product offerings that started on July 1, 2024 have portfolio content that includes a 100 percent RPS for Power100 Green-e Certified and a 47 percent RPS for Powerbase. SDCP’s contracting of long-term renewable projects will allow SDCP to achieve the Board target of 100 percent renewable by 2035, and price negotiating efforts will allow SDCP to forecast portfolio price impacts.
2.2 Load Management Standards
The central focus of CEC’s LMS Rulemaking is to encourage customers to shift electricity use from peak times of day when it is expensive and polluting to cheaper and cleaner off-peak times of the day.
According to the Public Resources Code, section 25132, load management is defined as “any utility program or activity that is intended to reshape deliberately a utility’s load duration curve”. Load management reduces the need for new electrical generation and backup generation, thus lowering customer energy costs, and is a key strategy to ensure grid reliability and resilience, distributed energy resources integration, and GHG emissions reduction.
The CEC adopted the LMS amendments through a rulemaking on April 1, 2023, and the amendments require publicly- and investor-owned utilities and Large CCAs to offer customers access to rate-structures and programs that provide the information needed to manage and optimize their energy use.
Specifically, the revisions require development of marginal cost-based rates or load flexibility programs.
LMS defines marginal cost as the change in current and future electric system cost that is caused by a change in electricity supply and demand during a specified time interval at a specified location. 7 Total
marginal cost is calculated as the sum of the marginal energy cost, the marginal capacity cost (generation, transmission, and distribution), and any other appropriate time and location dependent marginal costs, including the locational marginal cost of associated greenhouse gas emissions, on a time interval of no more than one hour.
In this Plan, SDCP uses the term dynamic rates to reflect responding to these marginal cost signals on an hourly or sub-hourly basis. Being a CCA, SDCP is authorized and responsible for setting and recovering only the generation cost components for each applicable electric rate. San Diego Gas and Electric (“SDG&E”), the investor-owned utility for the San Diego service area, is responsible for setting distribution, transmission, and any other non-generation cost components for each rate. 7 Energy cost computations shall reflect locational marginal cost pricing as determined by the associated balancing authority, such as the Los Angeles Department of Water and Power, the Balancing Authority of Northern California, or other balancing authority. Marginal capacity cost computations shall reflect the variations in the probability and value of system reliability of each component (generation, transmission, and distribution). 63 8
2.2.1 SDCP’s Compliance Plan Roadmap
Adopted LMS amendments section 1623.1(c) requires SDCP, along with the other utilities and Large CCAs, to develop and submit a compliance plan in response to meeting the revised LMS requirements.
The following table is a roadmap identifying where each regulatory requirement, along with the due date, is addressed within SDCP’s compliance plan.
LMS Section Regulatory Requirement Due Date Plan
Section
Status
§1623.1(c) Within three months of regulation
effective date, 4/1/2023, upload
existing time-dependent rates to the
MIDAS database.8
8/1/2023 3.1 Completed
§1623.1(a)(1) Within one year of regulation effective
date, develop and submit a compliance
plan addressing how SDCP plans to
comply with LMS requirements, and
including evaluation of marginal cost-based rates and programs, to SDCP’s Board. The plan must be considered
for adoption within 60 days after
submission.
4/1/2024 2.2.2.1 In progress
§1623.1(a)(3)(A) Submit compliance plan to the
Executive Director on the CEC within
30 days of adoption of the plan.
Respond to requests for additional
information and/or recommendations
within 90 days.
6/1/2024 2.2.2.2 Completed;
Plan
revision
submission
in progress
§1623(c)(4) Within one year of regulation effective
date, provide customers access to their
Rate Identification Numbers (“RIN”) on
billing statements and in online
accounts using both text and QR.
4/1/2024 3.1.2 Completed
§1623(c)(2) Within 18 months of regulation
effective date, develop and submit to
the CEC, in conjunction with the other
obligated utilities, a single statewide
standard tool for authorized rate data
access by third parties, and the terms
and conditions for using the tool. Upon
CEC approval, maintain and implement
the tool.
10/1/2024 3.1.3 In progress
§1623.1(b)(3) Within 18 months of regulation
effective date, submit to the CEC
10/1/2024 5.2.5.1 Completed
8 On June 1, 2023, the CEC issued Order No. 23-0531-10 in response to a request for extension from the IOUs and Large CCAs. The Order approved an extension for CCAs to upload time-dependent generation rates by August 1, 2023, and remaining time-depending rates with rate modifiers by October 1, 2023. 64 9
Executive Director a list of load
flexibility programs deemed cost
effective by SDCP. The portfolio of
programs must provide at least one
option to automate response to MIDAS
signals for each customer class where
SDCP’s Board has determined such a
program would materially reduce peak
demand.
§1623.1(a)(3)(C) Submit annual reports to the CEC
Executive Director demonstrating
implementation of plan, as approved
by SDCP’s Board.
Every year,
starting on
4/1/2025
2.2.2.4 Planned for
future
§1623.1(b)(2) Within 27 months of the regulation
effective date, submit at least one
marginal cost-based rate to SDCP’s
Board for approval for any customer
class(es) where such a rate will
materially reduce peak load.
7/1/2025 4.3.5 Deferred
§1623.1(b)(4) Within 51 months of the regulation
effective date, offer customers
voluntary participation in either a
marginal cost-based rate, if approved
by SDCP’s Board, or a cost-effective
load flexibility program.
7/1/2027 4.3.5 and
5.2.5.2 In progress
§1623.1(b)(5) Conduct a public information program
to inform and educate affected
customers why marginal cost-based
rates or load flexibility programs and
automation are needed, how they will
be used, and how these rates and
programs can save customers money.
Ongoing,
dependent
on offerings
6.3 In progress
§1623.1(a)(1)(C) Review the plan at least once every 3
years after the plan is adopted and
submit a plan update to the Board if
there is a material change.
Every 3
years
2.2.2.3 Planned for
2028
2.2.2 SDCP’s Compliance Plan Administration
2.2.2.1 Plan Development and Board Approval Process
Adopted LMS amendments section 1623.1(a) requires each Large CCA to submit a compliance plan consistent with the applicable requirements of the LMS, as well as actions taken to meet those requirements to its rate-approving body. The compliance plan must be submitted within one year of the regulation effective date, or by April 1, 2024, and must be considered for adoption by the rate-approving body in a duly noticed public meeting within 60 days of submission.
65 10
This Plan meets the requirements of section 1623.1(a). The Plan was submitted to the Board prior to April 1, 2024, and presented to SDCP’s Board at a duly noticed meeting on February 22, 2024. SDCP’s Board approved this Plan. The description of how SDCP complies with each element of the regulatory requirements of the LMS amendments is provided in the subsequent sections of this Plan.
2.2.2.2 CEC Review Process
Adopted LMS amendments section 1623.1(a)(3) specifies that, upon adoption by the Large CCA rate approving-body, the plan must be submitted to the CEC Executive Director within 30 days for review. SDCP’s Board is the sole authority to approve rates, and in this regulatory proceeding, the CEC’s role is limited to determining whether this adopted Plan complies with the regulation.
Following the Plan’s presentation and adoption by SDCP’s Board on February 22, 2024, the Plan was submitted to the CEC by April 1, 2024 for review. Any requests for additional information or recommended changes will be addressed, and a written response submitted to the CEC within 90 days as required in the regulation. The Plan was reviewed by CEC staff and CEC staff provided feedback and requested revisions on April 3, 2025. Through this revised compliance plan, SDCP is responding to the CEC staff accordingly.
2.2.2.3 Triennial Plan Review
Adopted LMS amendments section 1623.1(a)(1)(C) requires each Large CCA to review its compliance plan at least once every three years. The CCA must submit a plan update to its rate-approving body where there is a material change to the factors considered in evaluating marginal cost-based rates and programs. Material revisions to the plan shall follow the same process as the initial plan approval.
This Plan will be reviewed by SDCP every three years following the date of adoption, and material updates will be submitted to SDCP’s Board for approval. Subsequently, this Plan and any approved material updates will be duly submitted to the CEC.
2.2.2.4 Annual Reporting
Adopted LMS amendments section 1623.1(a)(3)(C) requires each Large CCA to submit to demonstrate implementation of its LMS compliance plan through a submission to the CEC Executive Director. Each Large CCA must submit the initial report one year after adoption of the plan by the CCA’s rate-approving body, and annually thereafter.
SDCP will timely submit annual reports to the CEC Executive Director describing the implementation of this Plan.
3. Access to Price Signals
3.1 Publication of Machine-Readable Rates in MIDAS
The CEC developed the MIDAS database, as part of the LMS revisions, so customers and automation service providers can link flexible loads to a machine-readable database of rates and other grid signals to automate demand flexibility. The LMS amendments 66 11
require the utilities and Large CCAs to populate utility rate information into MIDAS and to facilitate access to MIDAS signals for customers and their authorized third parties.
This section of the Plan details SDCP’s planned actions to meet this requirement.
3.1.1 Upload of Time-Dependent Rates
Adopted LMS amendments section 1623.1(c) requires each Large CCA to upload existing time-dependent rates to the MIDAS database within three months of the regulation effective date, or by July 1, 2023. On June 1, 2023, the CEC issued Order No. 23-0531- 109in response to a request for extension from the IOUs and Large CCAs. The Order approved an extension for CCAs to upload time-dependent generation rates by August 1, 2023, and remaining time-depending rates with rate modifiers by October 1, 2023.
Each uploaded rate must be assigned a RIN, which is used to uniquely identify each rate.
The MIDAS database will provide information about the rate and any associated marginal signals to which the customer may automate response for each associated RIN.
Large CCAs are also required to upload any new time-dependent rates or changes to existing rates, prior to the effective date of that rate. All uploaded time-dependent rates must include all applicable time-dependent cost components.
3.1.1.1 Existing Rates Upload
On August 1, 2023, SDCP successfully uploaded 180 rate permutations of time-dependent rates, including residential and non-residential customer classes. A list of current time-dependent rates and corresponding RINs can be found in Appendix A.
A message confirming successful upload was returned for each rate file loaded to MIDAS. SDCP also performed random retrieval of rates as a second point of confirmation to the successful rate upload and to validate accuracy of rates recorded in MIDAS. In addition, SDCP sent a confirmation of successful MIDAS upload email to CEC staff on August 1, 2023, and received acknowledgement from the CEC’s MIDAS Lead contact on August 2, 2023.
On October 1, 2023, SDCP successfully uploaded the corresponding 180 rate permutations of time-dependent rates for SDCP’s 100 percent renewable retail service option, “Power100”. SDCP received acknowledgement from CEC’s Lead contact on October 5, 2023, confirming successful additional MIDAS upload. SDCP coordinated with its vendor to upload any new time-dependent rates or changes to existing rates, that became effective on February 1, 2024 going forward.
3.1.1.2 Future Rates Upload
Going forward, SDCP will upload existing rates as needed, to reflect any rate changes, and any new time-dependent rates or rate components. SDCP will follow a similar process to the successful existing rate uploads in 2023. SDCP will create rate files in csv format, convert them to XML format, and load them to MIDAS through the application programming interface.
9 California Energy Commission, Order No. 23-0531, June 1, 2023, https://efiling.energy.ca.gov/GetDocument.aspx?tn=250450&DocumentContentId=85205. 67 12
3.1.2 Provide RINS to Customers
Adopted LMS amendments section 1623(c)(4) requires each Large CCA to provide customers access to their RIN(s) on customer billing statements and online accounts using both text and quick response (“QR”) or similar machine-readable digital code. This access must be provided within one year of the regulation effective date, or by April 1, 2024.
3.1.2.1 Implementation Plan
SDCP partners with SDG&E, the local investor-owned utility in the service area, to serve electricity charges to customers through either paper and/or electronic bill statements.
The bill is the standard presentation of electricity billing statements to customers.
Customers also have access to billing statements through their protected online SDG&E accounts.
SDCP through SDG&E made the RINs available in text and QR formats on billing statements on or before April 1, 2024 as required. This allows customers to access their RIN on the billing statement received by mail or accessed online. SDG&E has significant control of both paper and electronic billing statement designs, therefore SDCP’s compliance with section 1623(c)(4) was dependent on successful coordination with SDG&E. SDCP, through its contracted back-office vendor, coordinated with SDG&E to implement the RINs, both in text and QR formats, by April 1, 2024. RINs are standardized to include country, state, distribution, energy, rate, and location information. RINs are also based on customer energy providers, pricing plans, locations, and other account considerations, such as participation in assistance and/or solar programs and pricing plan(s) changes.
SDCP customers see two RINs, one for the CCA-associated component(s) of their bill pertinent to their generation rates and another for the SDG&E-associated component(s) of their bill related to transmission and distribution rates. There may be multiple RINs for customers with group bills and corrected billing.
3.1.3 Statewide RIN Access Tool
Adopted LMS amendments section 1623(c) requires utilities and Large CCAs to collaboratively develop a single statewide standard tool for authorized rate data access by third parties, along with a single set of
terms and conditions for third parties using the tool. The tool must meet all the following requirements:
• Provide the RIN(s) for the rate(s) applicable to a customer’s premise. • Provide any RIN(s) for the rate(s) to which the customer is eligible to be switched.
• Provide estimated average or annual bill amounts based on the customer’s current rate and any other rate(s) for the customer is eligible to be switched if such calculation tools already exist.
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• Enable authorized third parties, upon the direction and consent of the customer, modify the customer’s applicable rate, to be reflected in the next billing cycle.
The tool must also incorporate reasonable and applicable cybersecurity measures, minimize enrollment barriers, and be accessible in a digital, machine-readable format according to industry best practices and standards. The tool must be submitted to the CEC for approval within 18 months of the regulation effective date, or by October 1, 2024. After CEC approval, the utilities and Large CCAs must collaboratively implement and maintain the tool.
3.1.3.1 Statewide Tool Development
SDCP has been working with the other regulated load serving entities on creating the statewide RIN tool pursuant to 20 CCR Section 1623(c). A proposed plan for the tool was submitted to the CEC for review on October 1, 2024. We will continue to work with the other Load Serving Entities (LSEs) and the CEC to implement and maintain the statewide RIN tool in a timely manner, subject to the tool’s approval by the Commission.
3.1.3.2 Statewide Tool Implementation
SDCP’s internal infrastructure must be updated to integrate and support the final approved statewide tool.
SDCP is unable to specifically identify the full scope of integration efforts needed until the final tool is designed and approved by the CEC. Concurrent with the development process, however, SDCP is reviewing its internal infrastructure and scheduling budget requests. Implementation projects will be added to SDCP’s annual work prioritization queue. While SDCP anticipates complying with this requirement, any delays in development of the tool could result in implementation delays. Similarly, if the costs of integrating the tool result in undue hardship to SDCP or its customers, SDCP may seek to delay or modify compliance with this requirement.
4. Dynamic Rates
The adopted LMS amendments identify dynamic hourly or sub-hourly rates as a central tool and are critical to encourage shifting peak energy-use, controlling daily and seasonal peak loads, lessening, or delaying the need for new electrical capacity, and reducing fossil fuel consumption and associated GHG emissions.
Adopted LMS amendments section 1623.1(b)(2) directs the Large CCAs to seek approval from their Boards for at least one dynamic rate for each customer class for which its rate-approving body determines such rate will materially reduce peak load. The application must be submitted within 27 months of the regulation effective date, or by July 1, 2025. In accordance with section 1623.1(b)(4), approved rates must be implemented 24 months following any Board rate approvals, or by July 1, 2027. 69 14
Adopted LMS amendments section 1623.1(a)(1) requires each Large CCA to evaluate the cost effectiveness, equity, technological feasibility, and benefits to the grid and customers, of dynamic rates for each customer class in its compliance plan. After evaluating such rates, the Large CCA may instead propose and evaluate specified programs and/or delay or modify compliance with the LMS requirements.
The following section of SDCP’s Plan provides an overview of SDCP’s current time-dependent rates, describes SDCP’s rate development process, and addresses the requirement to evaluate the implementation of dynamic rates on the timeframes specified in the LMS.
4.1 Overview of Current Time-Dependent Rates
SDCP’s portfolio of time-dependent rates includes at least one marginal cost-based time-dependent rate for nearly every customer class. SDCP has five customer classes:
residential, small commercial, medium/large commercial, agriculture, and lighting. Apart from lighting and unmetered customers, all customers have access to Time-of-Use (“TOU”) rates and 84% of SDCP customers are on TOU rates. Please see the following table for details on SDCP’s rates by customer class and percent of customers in that customer class on TOU rates.
Customer Class Available Rates10 % on TOU Rates
Residential TOU:
- DR-SES
- EV-TOU, EV-TOU-2, EV-TOU-5
- TOU-DR, TOU-DR-1, TOU-DR-2
- TOU-ELEC
Non-TOU:
- DR
- DR-LI-MB (CARE/FERA/Medical Baseline)
83%
Small
Commercial
TOU:
- TOU-A (Primary or Secondary)
- TOU-A-2 (Primary or Secondary)
- TOU-A-3 (Primary or Secondary)
- TOU-M
Non-TOU:
- A-TC (Traffic Control Service)
- E-LI-NR (CARE/FERA for TOU-A, TOU-A-2,
TOU-A-3, TOU-M)
96% (100% if excluding A-TC, Traffic Control Service
accounts)
Medium/Large
Commercial
TOU:
- A6-TOU (Primary, Secondary or
Transmission)
- AL-TOU (Primary, Secondary or
Transmission)
96%
10 SDCP has additional rate variants including legacy grandfathered rates and less than 20kW or 20kW or greater versions of rates.
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- AL-TOU-2 (Primary, Secondary or
Transmission)
- EV-HP (Primary or Secondary)
- DG-R (Primary, Secondary or Transmission)
Non-TOU:
- E-LI-NR (CARE/FERA for AL-TOU, AL-TOU-2,
DG-R)
- OL-TOU
Agriculture TOU:
- PA-T-1 (Primary, Secondary or
Transmission)
- TOU-PA (Primary or Secondary)
- TOU-PA-2 (Primary or Secondary)
- TOU-PA-3 (Primary or Secondary)
100%
Lighting TOU:
- LS-2-AD
Non-TOU:
- LS
- OL-2
0% (96% of lighting accounts
are unmetered)
SDCP is also developing load flexibility programs that incorporate time-varying marginal cost-based signals, some of which test response to different price signals, in addition to time-dependent rates to encourage customer peak load shift. The following section of the Plan provides a summary of SDCP’s currently available time-dependent rates.
4.1.1 Residential Rates
SDCP’s TOU-DR is the standard rate for residential customers. Residential customers pay different rates depending on the season, day, and hours of energy use, summarized in the table below. These time periods were selected because they are best aligned with highest peak loads and marginal electricity prices, while also being simple and easy for customers to understand.
Time-Of-Use Periods Summer Months (June 1 through
October 31)
Winter Months (November 1 through
May 31)
On-Peak 4 pm – 9 pm 4 pm – 9 pm
Off-Peak weekdays 6 am – 4 pm and 9 pm –
12 am, weekends and holidays 2
pm – 4 pm and 9 pm to 12 am
weekdays 4 am – 4 pm (excluding 10
am – 2 pm in March and April) and 9
pm – 12 am, weekends and holidays 2
pm – 4pm and 9 pm to 12 am
Super Off-Peak weekdays 12 am – 6 am, weekends
and holidays 12 am – 2pm
weekdays 12 am – 6 am (excluding 10
am – 2 pm in March and April),
weekends and holidays 12 am – 2pm
SDCP’s other TOU rates provide options for customers in terms of difference in peak, off-peak, and super off-peak periods to shift energy use. SDCP enrolled residential customers onto its TOU rates in the first half of 2022 during phase 3 of enrollment. The high adoption and retention of residential TOU rates has benefited both SDCP and customers. 71 16
SDCP’s EVTOU is the standard rate for residential customers that charge their EVs at home.
This rate encourages customers to charge their EVs during super off-peak times when energy is abundant, and energy prices are low.
4.1.2 Non-Residential Rates
SDCP’s TOU-A is the standard rate for small commercial customers. SDCP’s AL-TOU is the standard rate for medium/large commercial customers. SDCP’s TOU PA is the standard rate for agriculture customers. All these rates are similar in concept to residential TOU rates, except the rate periods differ. Non-residential customers have been offered TOU rates for a much longer time compared to residential customers.
4.2 SDCP’s Rate Development Process
4.2.1 Strategic Direction on Competitive Rates
Adopted by the Board on November 17, 2022, the Rate Development Policy11 guides SDCP’s rate development process. The policy provides a framework to ensure SDCP’s rate design, development, and implementation of processes remain transparent, fiscally responsible, and centered on the customer. The policy includes the following objectives:
• Cost Recovery: rates must be sufficient to recover all expenses, debt service and other expenditure requirements.
• Reserves: rates must be sufficient to build prudent reserves. • Rate Competitiveness and Customer Value: rates must allow SDCP to successfully compete to retain and attract customers while offering superior electricity service offerings with higher renewable content compared to the incumbent investor-owned utility. • Rate Stability: rate changes should be minimized to reduce customer bill impacts with a preference for annual rate adjustments.
• Equity among customers: rate difference among customers should be justified by differences in usage characteristics and/or cost of service. Additionally, to the extent possible, rates shall be equalized from a value proposition perspective among customers enrolled during different Power Charge Adjustment Indifference (“PCIA”) Vintage Years.
• Rate Structures: as new rates are developed; emphasis shall be put on rate-design simplicity and comparability as well as overall customer experience. • Transparency: SDCP’s Board will review and approve rates at an open and public meeting held in accordance with the Ralph M. Brown Act. SDCP shall post a copy of the adopted rates in both English and Spanish on its website within 14 calendar days 11 San Diego Community Power Rate Development Policy, https://sdcommunitypower.org/wp-content/uploads/2023/01/Item-12a_Rate-Development-Policy.pdf. 72 17
of approval or by the rates’ effective date, whichever is sooner. SDCP shall also make any rate design documents promptly available upon request under the California Public Records Act.
• Cost Shifting: SDCP shall avoid, to the best of its ability, cost shifting between customer classes.
• Cost of Service: SDCP may explore a cost-of-service model for rate design.
When designing rates, SDCP must balance all the above competing objectives, many of which are reflected in the LMS revisions’ goals. As a public not-for-profit agency, SDCP designs and implements rates that meet revenue requirements as well as targeted reserves, while maintaining rate competitiveness, stability, and long-term financial viability. While SDCP understands the need to develop and implement dynamic rates, SDCP emphasizes the customer experience, such as ensuring the rate development process is transparent and rates are easy to understand, as well as minimize rate changes.
4.2.2 Rate Design and Implementation
Aligned with objectives of the Rate Development Policy, SDCP takes deliberate measures to ensure that any new rate development and implementation will be successful, effective, and accepted by its customers. These proactive measures may include:
• Conducting pilots to determine the effectiveness of different rate options and reception by customers.
• Developing and implementing iterative outreach and education campaigns. • Developing and implementing new education tools, such as rate comparison tools and reports.
After rate implementation, SDCP is committed to monitoring the effectiveness of the rate with respect to shifting peak load and customer feedback.
4.3 Evaluation of New Dynamic Rates
Consistent with the adopted LMS amendments, the following section of the Plan evaluates the cost-effectiveness, equity, technological feasibility, and benefits of dynamic rates for each customer class. SDCP assumes that these new dynamic rates would be implemented on the schedule specified in the LMS amendments, which includes applying for Board approval of dynamic rates by July 1, 2025, and offering voluntary participation in those rates to all customers by July 1, 2027, where such a rate is determined to materially reduce peak load cost effectively.
SDCP does not have sufficient information at this time to conclude that proposing and implementing dynamic rates following the adopted LMS amendments’ schedule would be cost effective or provide incremental benefits. Significant uncertainties exist related to a gap in dynamic rate pilot evaluation results and data in SDCP’s and SDG&E’s service area, the level of incremental load shift potential, customer response to market price risks, and 73 18
customer acceptance of a complex new rate design. Based on the results of this evaluation, SDCP plans to defer the proposal and adoption of new dynamic rates at this time. However, SDCP has and will continue to implement and offer load flexibility programs, in lieu of implementing a new marginal cost-based rate design, to support the intent and goals of the LMS and meet LMS compliance standards. SDCP will re-evaluate dynamic rates with the benefit of additional information from dynamic rate pilots in SDCP’s and SDG&E’s service area and other service areas in the next update of this Plan.
4.3.1 Cost-Effectiveness
Adopted LMS amendments section 1623.1(a)(1)(A) specifies cost effectiveness as the first evaluation factor. SDCP strives to qualitatively estimate the costs and benefits to customers, that are associated with new dynamic rates for each rate class. This approach is necessary because, as of the time of the preparation of this Plan, SDCP does not have data to support a full quantitative analysis.
To assess cost effectiveness, it is necessary to consider the costs associated with designing, implementing, and maintaining new rates for each customer class, as well as the ongoing benefits associated with implementation. To demonstrate cost effectiveness, the expected benefits for each rate must exceed the cost of implementation.
As best practice for assessing the cost effectiveness of a new rate, SDCP would conduct a comprehensive pilot study to test and gather data on different rate options, which would likely require several years and a multi-million-dollar investment. Forming in 2019, SDCP is still a relatively young organization and has been limited in terms of developing rate options and has been prioritizing building a strong foundation as a customer-centric organization.
Thus, SDCP has not had sufficient time nor resources to pilot multi-year and multi-million-dollar rate pilots. SDCP plans to evaluate the effectiveness of dynamic rate options based on information gathered across the state from ongoing and proposed dynamic rate pilots.
As a result of the factors above, SDCP’s cost-effectiveness evaluation is based on qualitative assessments, and SDCP anticipates exploring opportunities to expand data access and/or refine estimates to inform future updates of the Plan.
4.3.1.1 Estimated Costs
Significant investment in planning, customer education and marketing, and technology development is required to implement new rates for all customer classes, particularly rates that are far more complex than any other currently available. SDCP has identified the following cost categories associated with implementing dynamic rates:
• Rate design costs would include the costs of initial market research, implementing pilots to test rate options, and analyzing the results of those pilots to refine the final design. Once the pilot is complete and evaluation data is analyzed, the final rate recommendation needs to be designed.
• Setup costs include coordinating with external vendors and SDG&E on Information Technology system updates to enable settlement over new intervals, data integration, updating the bill presentment to reflect these intervals, and developing 74 19
new or updating existing customer tools. Having tools available for customers to self-service and monitor their costs and usage will be important for success with hourly rates.
• Recruitment and retention costs include marketing and enrollment costs. SDCP anticipates spending significant time educating customers through an extensive, phased marketing campaign and targeted outreach in a variety of languages. This effort will only be successful if significant time and funds are invested. Shifting to complex hourly rates while maintaining a positive customer experience – which is key for adoption and longer-term retention of the rate – will require informing and educating customers to, at a minimum, understand and monitor hourly rates, energy market dynamics, pricing, and temperature trends that may significantly impact their bills.
SDCP anticipates the above costs to make a dynamic rate available are fixed and do not vary by load, electricity usage, or enrollment level. While SDCP does not currently have pilot results to inform implementation costs, SDCP estimates significant resources to develop, implement, and maintain hourly rates for customers will be required. Depending on the scope of the costs, implementing complex new rates may necessitate a rate increase for all customers to bring in additional revenue.
4.3.1.2 Estimated Benefits
This section of the Plan describes the potential benefits associated with implementing new dynamic rates and the estimated realization of incremental benefits based on design effectiveness, adoption levels, and additional load shift capacity available to be captured.
4.3.1.2.1 Potential Benefits
SDCP has identified the primary avoided cost benefits of new dynamic rates as the following:
• Avoided capacity costs, resulting from a reduction for new capacity additions or resource adequacy procurement.
• Avoided energy costs, resulting from shifting demand from higher-cost periods to lower-cost periods.
Secondary benefits can also flow from the realization of avoided capacity and energy procurement needs. For example, to the extent that load shifting reduces the need for new capacity and wholesale energy purchases during peak periods, these reductions can also contribute to the following:
• Avoided transmission and distribution in the form of reduced need for capital investments to deliver energy during peak periods.
• Avoided GHG compliance costs associated with a reduction in generating or purchasing energy from fossil -fueled resources that may otherwise be needed to serve load during peak periods.
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• Improved air quality, public health, and environmental outcomes associated with a reduction in operations of fossil-fueled resources. While these benefits do not accrue directly to SDCP, they provide value on a societal basis.
4.3.1.2.2 Realization of Benefits
As a retail electric service provider and a CCA, SDCP anticipates that the greatest potential direct benefits would be derived from avoided capacity and energy procurement costs.
However, the realization of any of the above-identified benefits from new dynamic rates is highly dependent on the following several factors:
• The effectiveness of the rate design in shifting customer usage patterns. • The operational value of the load shift.
• The adoption levels of the new rates.
• The customer experience on the new rate.
In addition, with respect to avoided GHG compliance costs and improved air quality, public health, and environmental outcomes, the realization of benefits also depends on the relative utilization of fossil-fueled resources to serve peak load versus periods of lower demand. A discussion of each factor’s expected effect on the benefits attributable to developing new dynamic rates is detailed in the next section of the Plan.
4.3.1.2.2.1 Estimated Design Effectiveness
Effective rate design is necessary to achieve predictable load shift during the most valuable peak hours of the day. The risk of not having sufficient generation, which spurs the need for new capacity additions or resource adequacy procurement, is typically concentrated in a small number of peak hours each year when serving peak load is most challenging.
Accordingly, to realize any avoided capacity benefits, it is vitally important that a new rate design can achieve consistent and meaningful load reductions during those peak hours.
Reducing capacity and energy procurement during peak periods relies on a consistent shift in demand patterns.
Time to develop and test the effectiveness of rate design options will be especially important when shifting to a complex new rate structure that could include several price signal changes within a peak period or even within an hour. If customers do not understand the signals or the time periods
During which they are provided, their response may not be predictable, leading to reduced efficacy and potentially adverse bill impacts. SDCP’s ideal dynamic rate development process would include market research, testing the effectiveness of different rate options through pilots, analyzing the results, and considering refinements before proposing a rate.
Completing these steps helps to ensure that the rate sends the right signals and takes into consideration customers’ willingness to respond either directly or via automated technologies/devices while fully recognizing that the process can take significant time and resources.
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The LMS requirements direct Large CCAs to propose new dynamic rates for every customer class to the Board by July 1, 2025. That timeline does not provide sufficient time for SDCP to design a pilot, test responses to different rate options, and analyze the results for even one rate class. In addition, SDG&E’s dynamic rate pilots have been delayed and results of those studies will not be available before July 1, 2025 because the California Public Utilities Commission (“CPUC”) has not issued a decision for the Demand Flexibility proceeding (Rulemaking 22-07-005), which will require SDG&E to submit its dynamic rate pilot design.
Without the results from pilots, SDCP cannot conclude that a complex new rate design would result in any incremental, dependable load shift or ensure a positive customer experience for any of our customers.
In addition, if SDCP undertook the rate design process, it would only be able to design and potentially implement commodity or generation component-only dynamic rates. Without knowledge of SDG&E’s delivery dynamic rates and without coordination on customer billing and outreach, a SDCP generation component-only dynamic rate will not be able to achieve demand flexibility goals, and could cause significant customer confusion, and will be almost impossible to implement unilaterally. A successful dynamic rate pilot will require close coordinated collaboration between SDCP and SDG&E to align its rate design (i.e., dynamic interval, pricing differences, etc.), customer outreach messaging, and customer billing implementation. Currently, SDG&E has yet to share any information regarding its dynamic rate pilot.
4.3.1.2.2.2 Estimated Adoption Level
The estimated adoption level of new hourly dynamic rates directly impacts the value of load shift benefits. Based on available information, SDCP anticipates that dynamic rates rolled out to customers by July 1, 2027, would likely have low adoption and retention levels.
SDCP’s assumption is based on several key factors, including the uncertainty in bill impacts from complex new rate structures, the time needed to educate customers to promote a positive experience, and the cost and limited accessibility of enabling behind-the-meter automation technology.
• Bill savings are a significant driver for customer rate adoption. The predictability of bill impacts gives customers the assurance of how they can leverage a rate to see bill savings. With dynamic rates, customers take on the full risk of price fluctuations, which may not be sustainable in the long term.
• One method of mitigating the uncertainty of bill impacts from new dynamic rates is to fully educate and inform customers. SDCP is dedicated to a culture of delivering the best possible customer experience when transitioning customers from one rate structure to another or when offering optional rates. Limited time to engage and educate customers on new complex hourly rates, and the potential benefits and risks associated with participation, may lead to confusion about bill impacts and low uptake. Customer experience is a priority for SDCP, so negative experiences may have an unintended negative impact on the brand and act as a deterrence on current and future initiatives.
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• Realizing the benefits of dynamic rates is dependent on customers’ ability to access and adopt enabling technology. There are challenges and uncertainties associated with utilizing these devices for grid services, as further discussed in Section 4.3.3.2.
SDCP expects that limited adoption of the needed technology would translate to limited benefits from dynamic rates, but accessibility of customer-owned automated devices that allow for response to hourly or sub-hourly signals is a near-term constraint. • Adoption is also impacted by a customer’s ability to understand and their capacity to meaningfully respond to dynamic rate signals. As part of its due diligence, SDCP issued an on-going survey to the largest commercial customers in 2022 to gauge interest in a Real-Time Pricing pilot rate and to date, no responses have been received.12 Through day-to-day business interaction and planned engagement with commercial and industrial customers, the feedback can be summarized as either no interest in enrolling in a dynamic rate at this time or dynamic rates are too complex and will require too much up-front technology and staffing resources investment.
4.3.1.2.2.3 Estimated Incremental Load Shift Capability The primary potential benefits of dynamic rates are based on reducing new capacity additions and associated avoided wholesale energy costs, which may carry additional benefits associated with reduced transmission and distribution costs, reduced GHG compliance costs, and improved air quality, public health, and environmental outcomes.
SDCP’s existing time-dependent rates and planned new load flexibility programs are likewise designed to capture these same benefits and to create a customer-centric experience, that is simple and easy-to-understand and have been supported with extensive customer outreach and education. Any incremental benefits associated with implementing dynamic rates rely on achieving incremental load shift relative to SDCP’s existing rates and planned new programs. The following summarizes the current load shift capability of SDCP’s existing rates and planned new programs, and potential incremental load shift opportunities. • SDCP’s TOU rate structures mirror SDG&E’s rates and were designed to shift peak time periods energy use to off peak periods, thus reducing grid stress and resulting in financial benefits from combined energy and capacity savings. • SDCP is in the process of designing and planning to offer new load flexibility and demand response programs that allow customers to respond to signals that incorporate day-ahead marginal prices, weather, and grid conditions. These programs complement our existing TOU rate structure and provide additional load shift benefit on a day-ahead basis and, in some cases, on a same-day basis for emergency scenarios. SDCP’s new programs and pilots are discussed further in Section 5.
• SDCP has not yet conducted pilots to evaluate more complex dynamic rate options in which hourly market price risk is passed directly to the customers. In addition, planned dynamic rate pilots in SDCP’s and SDG&E’s service area have been delayed.
The CPUC has not issued a decision for the Demand Flexibility proceeding, which will 12 Real-Time Pricing Pilot Rate Survey, https://sdcommunitypower.org/real-time-pricing-rtp-pilot-rate-2/. 78 23
require SDG&E to submit its dynamic rate pilot design. Without the benefit of pilot results and given the inherent complexity of new dynamic rates coupled with the risk of adverse bill impacts, and the existence of more customer-friendly TOU rates and planned new programs, SDCP cannot conclude that such dynamic rates would likely result in incremental load shift benefits. As part of its due diligence, SDCP issued an on-going survey to the largest commercial customers in 2022 to gauge interest in a Real-Time Pricing pilot rate and to date, no responses have been received.13 Through day-to-day business interaction and planned engagement with commercial and industrial customers, the feedback can be summarized as either no interest in enrolling in a dynamic rate at this time or dynamic rates are too complex and will require too much up-front technology and staffing resources investment.
4.3.1.3 Discussion
Based on the evaluation of available information, SDCP cannot conclude that implementing dynamic rates for any customer class on the LMS required timeline would be cost-effective.
There are significant uncertainties both in the magnitude of value that can be captured and SDCP’s ability to realize the value based on design efficacy, how customers would react to hourly market risks, and expected adoption levels. According to the whitepaper, Time-Varying and Dynamic Rate Design, authored by the Regulatory Assistance Project (“RAP”) and the Brattle Group, real-time/dynamic pricing presents high rewards but also high risks.14 SDCP anticipates that developing dynamic rates would result in significant costs and may even require a rate increase to all customers to bring additional revenue to support the development and implementation of the said rates. Without pilot results in SDCP’s and SDG&E’s service area to perform a comprehensive analysis, SDCP cannot readily ascertain rate development costs, the estimated benefits, or whether those benefits would be likely to offset the costs.
A 2004 Lawrence Berkley National Laboratory whitepaper concludes that most dynamic rate programs in the early 2000s, implemented across the country, did not achieve significant level of participation. Another takeaway from the survey is that although many customers on dynamic rates are price responsive, a substantial fraction are not.15 Significant changes are happening and will occur in the rate landscape in our region and at the state level, including a shift to battery energy storage systems, implementation of net billing tariff, adoption of an income-graduated fixed charge, and exploration of other potential fixed charges. The combination of multiple concurrent rate variables can make evaluating dynamic rate and demand flexibility difficult. Isolating and quantifying the benefits of just dynamic rates becomes a challenge, and these overlapping efforts complicate signaling a customer to change energy use behavior and may increase development costs. For example, introducing fixed charges, such as the income-graduated fix charge, dilutes the hourly variability that dynamic rates are trying to reflect. 13 Real-Time Pricing Pilot Rate Survey, https://sdcommunitypower.org/real-time-pricing-rtp-pilot-rate-2/. 14 Time-Varying and Dynamic Rate Design, RAP and the Brattle Group, July 2012, page 17. 15 A Survey of Utility Experience with Real Time Pricing, Lawrence Berkeley National Laboratory and Neenan Associates, December 2004, ES-4 and ES-6.
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The following summarizes the key items that highlight circumstances that substantiate why marginal cost-based rates are not yet feasible or cost effective for SDCP:
1. SDG&E’s proposed dynamic rate pilots would have provided the more accurate estimated costs and benefits compared to pilots in other service territories because weather conditions, local economy, and local energy policies, and other factors that are captured by SDG&E’s pilot overlap with SDCP’s conditions. However, SDG&E proposed two dynamic rate pilots through Applications 21-12-006 and 12-12-008 to the CPUC, but the import rate pilot was dismissed without prejudice and the other pilot delayed. SDG&E will file a new application for a dynamic import rate once the CPUC issues a final decision in the Demand Flexibility Rulemaking that will provide guidance for dynamic rate applications.16 SDCP continues to monitor and check in with SDG&E on the status of the Demand Flexibility Rulemaking and SDG&E’s dynamic rate pilot but the CPUC has not issued a decision and is unlikely to do so by July 1, 2025.
2. Without information from SDG&E’s dynamic rate pilot, it is infeasible for SDCP to design and implement a commodity or generation component-only dynamic rate. A closely coordinated collaboration and partnership with SDG&E is required for the rate design, rate and billing implementation, and customer outreach and education to achieve demand flexibility goals.
3. As part of its due diligence, SDCP issued an on-going survey to the largest commercial customers, starting in 2022, to gauge interest in a Real-Time Pricing pilot rate and to date, no responses have been received.17 Through day-to-day business interaction and planned engagement with commercial and industrial customers, the feedback can be summarized as either no interest in enrolling in a dynamic rate at this time or dynamic rates are too complex and will require too much up-front technology and staffing resources investment.
4. Southern California Edison (“SCE”) implemented its two dynamic rate pilots from 2022 through 2024. The Public Utilities Commission ordered SCE to conduct evaluations of the pilots to assess cost-effectiveness as well as other impacts. SDCP has reviewed the key findings and is hereby including the relevant and applicable lessons learned from SCE into any future dynamic rate design. On February 28, 2025, the Final Evaluation of SCE’s Dynamic Rate Pilot was released, and the analysis did not find evidence of consistent and/or large changes on hourly energy usage due to customer price response.18
SDCP will continue to gather information to inform evaluation of future rate and program designs. As data becomes available from pilots, SDCP anticipates exploring cost-effectiveness analyses and/or quantifying the estimates provided in this section of the Plan. 16 Ordering Paragraphs 1 and 2, Decision 23-11-006 Adopting Dynamic Export Rate Pilot and Dismissing Application for a Real Time Pricing Rate Pilot, November 15, 2023, 520868373.PDF (ca.gov). 17 Real-Time Pricing Pilot Rate Survey, https://sdcommunitypower.org/real-time-pricing-rtp-pilot-rate-2/. 18 Final Evaluation of Southern California Edison’s Dynamic Rate Pilot, Christensen Associates, February 28, 2025, page 7.
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4.3.2 Equity
The second criterion by which to evaluate dynamic rates is equity, a core principle for SDCP’s establishing bylaws and purpose. Without pilot study data to support quantifying load shift and bill impacts for different customer groups, SDCP will qualitatively evaluate the equity impacts of these rates by considering customers’ ability to benefit directly and indirectly from the rates.
4.3.2.1 Equitable Access to Direct Benefits
The ability to directly benefit from a dynamic rate depends on several factors, such as access to enabling technology, ability to shift load away from high-cost periods, and ability to benefit from the rate and absorb potential bill shocks. • The ability to participate in a dynamic rate depends upon customers’ access to technology with specific characteristics that enable response to hourly or sub-hourly price signals. Currently, the high upfront cost of this technology may pose a limitation. To help address these barriers, SDCP’s Community Clean Energy Innovation Grant Program provides opportunities to increase access to the benefits of clean energy technologies with a focus on underserved communities and vulnerable populations. In addition, SDCP is exploring different incentive programs and developing strategies to help further broaden access. • The ability to quickly shift load away from high-priced peak periods will affect whether participating customers can directly benefit from a dynamic rate. As market signals would be dynamic with potentially very large changes in prices between hours, customers that cannot or do not adopt and/or utilize and embrace enabling technology could see very large bill impacts.
• Participating customers i a dynamic rate runs the risk of bill shocks if they are unable to shift load away from high-priced peak hours. Customers who face greater barriers in implementing enabling technology are likely to be most exposed and least able to absorb potential bill shocks.
4.3.2.2 Equitable Access to Indirect Benefits
As previously described in Section 4.3.1.2.1, dynamic rates may offer benefits to SDCP’s customers, to the extent such rates reduce overall capacity costs, contribute to reliability, and reduce reliance on fossil-fueled resources. These benefits could serve as a downward pressure on rates and result in improved air quality, public health, and environmental outcomes. However, as discussed in Section 4.3.1.2.2, SDCP is unable to conclude at this time the magnitude of these benefits that would result from the implementation of dynamic rates.
4.3.2.3 Discussion
Based on the evaluation of available information, SDCP cannot conclude that implementing dynamic rates would result in any equity benefits. The availability of such rates is likely to disproportionately benefit higher-income customers, early adopters of technology, and can absorb the risk of bill shocks. It is critical to analyze pilot study results to accurately quantify 81 26
the magnitude and uncertainty of these benefits, including the level of acceptance and adoption of dynamic, hourly, or sub-hourly rates from customers of different income levels.
Severin Borenstein, in a 2009 article, states that some customers would be winners, and others would be losers with a switch to dynamic rates. He elaborates that those customers who consume disproportionate quantities at the most expensive times are being subsidized under time-invariant rates and may be worse off if they cannot adjust their consumption substantially under dynamic rates.19
4.3.3 Technological Feasibility
Technological feasibility is the third evaluation factor for dynamic rates. SDCP’s evaluation assesses the technological feasibility of implementing dynamic rates for all customers on the schedule specified in the LMS requirements and considers the feasibility of both the technology systems needed to support implementation of dynamic rates and to the external customer technology that is needed to enable response to hourly or sub-hourly signals.
Since SDCP is a CCA that isn’t the Meter Data Management Agent (“MDMA”), SDG&E is in control and responsible for a significant portion of the technology systems’ updates and rollout required to implement dynamic rates that overlap both organization’s service areas.
4.3.3.1 Technology Systems
The primary technology systems needed to support dynamic rates include advanced metering infrastructure (“AMI”), SDCP and SDG&E’s Customer Relationship Management software, and SDCP’s and SDG&E’s billing system software. SDCP also relies on additional applications from external vendors to develop customer educational tools and is working with these providers to provide functionality to communicate with and control enabling technologies, in the future. The following provides a feasibility assessment of each technology component:
• SDG&E’s meters can provide hourly interval data for residential customers and sub-hourly interval data for non-residential customers. An assessment of the AMI network communication infrastructure is likely to be required to identify if additional equipment needs to be installed to support the increased volume. SDCP will coordinate with SDG&E to avoid any disruptions to customers. • SDCP will coordinate with SDG&E regarding any necessary billing system configuration changes. SDCP anticipates it will be necessary to develop enhancements to SDG&E’s online tools and services to help customers understand any new rates and rate changes holistically.
• Updating existing customer tools and developing new tools would be key to supporting a positive customer experience when implementing dynamic rates. SDCP will engage not only with external vendors on relevant existing tools but also SDG&E to assess the technological feasibility of timeframes necessary to develop and/or modify existing tools to support dynamic rates.
19 Electricity Pricing that Reflects Its Real-Time Cost, Severine Borenstein, March 2009, https://www.nber.org/reporter/2009number1/electricity-pricing-reflects-its-real-time-cost. 82 27
In sum, SDCP anticipates that collaboration and coordination with SDG&E and external vendors will be critical to successfully implementing dynamic rates. SDCP will work with parties to assess enhancements, upgrades, and additional functionality that will be needed to ensure the optimal benefits of realization of dynamic controls and a positive customer experience.
4.3.3.2 Enabling Customer Technology
Realizing that the potential incremental benefits of dynamic rates depend on customer participation and the widespread availability of devices and technology that can support real time response to hourly or sub-hourly price signals; SDCP is in the process of assessing technologies with this kind of capability to include in future customer programs. The following is a list of common load flexibility technologies in SDCP’s and SDG&E’s service area. SDCP anticipates these same technologies will be needed to respond to new dynamic rates.
• Wi-fi enabled smart thermostats are the most widely adopted load flexibility technology. These devices can receive and respond to dispatch signals within 15-30 minutes. Utilities and CCAs rely on day-ahead and/or more real-time marginal costs and system conditions to inform the dispatch of resources in load flexibility programs.
• Battery energy storage systems are being adopted with increasing frequency by residential customers, particularly as an add-on to solar photo-voltaic (“PV”) installations. Batteries have much greater ability to be dispatched on short notice, and SDCP has already designed and implemented a pilot program in 2024 to accelerate this adoption and reduce the payback period for solar plus storage deployments through upfront financial and on-going performance incentives. This pilot program was extremely successful and will be implemented as a standalone program by the third quarter of 2025.
• Air conditioning (“AC”) switches are one of the oldest distributed resource technologies and have been deployed since the 1970s. These switches are included in various demand flexibility programs across the utilities and CCAs. • Electric vehicles (“EVs”) are an emerging source of load flexibility. There is significant potential for further growth given statewide goals for zero emissions vehicles by 2030. SDCP is assessing potential future charging programs that include sending hourly price signals to participating EVs.
SDCP’s future programs, utilities and CCAs’ existing programs will inform SDCP’s understanding of how to most effectively engage with customers with behind-the-meter devices, considering different technologies, customer needs and preferences, and other factors. SDCP anticipates future programs will help increase the acceptance and adoption levels of enabling technologies as well as testing their response to utility signals and dispatch whereby the results of these programs will also inform future consideration of dynamic rates.
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4.3.3.3 Discussion
Based on the evaluation of available information, SDCP believes the technology exists to implement some level of dynamic rates on the LMS timeframe. However, the capabilities of enabling behind-the-meter device technology, along with the impacts on customer experience, are still being tested and developed. SDCP believes that reassessing the technological feasibility of dynamic rates after evaluating pilot study results and future programs would better inform the likelihood of positive customer acceptance and material load shift benefits.
SDCP anticipates coordination with SDG&E and external vendors on implementing any necessary changes to internal systems, with the necessary infrastructure deployments and system configuration implementations. Additional time to enhance the billing experience, develop customer tools, and enhance DER functionality and control would create a better experience, improve the likelihood of acceptance of the new rates, and support improved realization of both customer and grid benefits in alignment with LMS desired outcomes.
4.3.4 Benefits to the Grid and Customers
The final two criteria for evaluating dynamic rates are benefits to the grid and benefits to customers. SDCP evaluates the two factors simultaneously because many benefits to the grid also have pass-through benefits to customers. SDCP evaluates each benefit by considering the expected effectiveness of the rate design and the expected adoption rate.
The following is a summary of anticipated grid and customer benefits associated with implementation of new dynamic rates on the timeframe specified in the LMS requirements. • An effective rate design that delivers meaningful, dependable load shift in response to hourly or sub-hourly signals is critical to capture benefits of avoided capacity costs, in terms of reduced new generation capacity or procurement. Shifting demand away from peak periods also has the potential to increase grid reliability. As further discussed in this Plan’s section 4.3.1.2.2.3, SDCP is unable to conclude that implementing dynamic rates would result in incremental capacity cost savings, given the uncertainty around design effectiveness, adoption levels, and the magnitude of load shift potential.
• An effective rate design that encourages customers to shift from high-cost, high-GHG periods to lower-cost, lower-GHG periods is instrumental in capturing the benefits of avoided energy costs. This allows for more efficient use of cheaper renewable energy when it is generated and reduces the higher costs of fossil-fueled energy associated with serving peak load. However, as further discussed in the Plan’s section 4.3.1.2.2.3, SDCP cannot conclude that implementing dynamic rates would result in incremental avoided energy costs.
• As distributed energy resources (“DERs”) programs are still in pilot stages across the state, how they and rate designs impact the need for various transmission and distribution services is still uncertain. With limited available information, SDCP cannot conclude that dynamic rates will result in any transmission and/or distribution savings.
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• To the extent that dynamic rates can shift energy use from peak time periods in which fossil fueled resources serve load to time periods with greater renewable energy generation, there is the potential for reduced compliance costs for GHG emissions. Reducing grid thermal operations and/or limiting market purchases when the grid has a greater carbon intensity can save costs for SDCP’s customers.
However, any incremental GHG cost savings depend on the realization of incremental reductions in capacity needs and/or in energy purchases during high-cost/high-GHG periods. GHG cost savings benefits are uncertain because SDCP is unable to conclude that implementing dynamic rates would result in material incremental load shifts. In addition, as SDCP gets closer to achieving a 100 percent renewable energy supply, SDCP anticipates increasingly less difference between the GHG emissions profiles of resources serving customers during the peak and in periods of lower demand.
• Potential air quality, public health, and environmental benefits associated with dynamic rates depend on whether such rates can successfully reduce capacity needs or energy purchases during time periods when the grid has a higher carbon intensity. SDCP cannot conclude that a material incremental increase in these benefits will accrue on the timeline specified in the LMS requirements. • Through dynamic rates, customers have the potential to lower their energy costs by shifting their peak hour usage. However, customers take on the full risk of market price fluctuations, which could have severe impacts on customer bills, especially during times of extreme market volatility. If high prices are sustained over a long period of time, customers may not be able to shift energy use to prevent excessively large bills. As an example, during the May 25, 2021 Advanced DER and Demand Flexibility Management Workshop, SDG&E expressed the concern that while wholesale prices are effective at balancing supply and demand, they may cause unintended consequences during extreme scarcity events. SDG&E cited the example of the negative experience of Texas residential customers on wholesale prices.20 • SDCP strives to maintain a delicate balance between multiple objectives as described in its Rate Development Policy. When designing rates, one priority is to emphasize rate-design simplicity, comparability, and transparency. Dynamic rates could be very complex and difficult for customers to understand. Thus, leading to confusion and potential negative bill impacts, particularly if SDCP does not have sufficient time to fully educate customers on the potential benefits and risks of marginal cost-based rates.
4.3.4.1 Discussion
Based on the evaluation of available information, SDCP is unable to conclude that implementing dynamic rates on the timeframe specified in the adopted LMS amendments would yield material incremental benefits to the grid or to customers. Important takeaways from the Lawrence Berkeley National Laboratory white paper emphasized that sufficient 20 Advanced Strategies for Demand Flexibility Management and Customer DER Compensation, California Public Utilities Commission, June 22, 2022, page 103.
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resources must be devoted to developing and implementing a customer education program and customers need help understanding and managing price risk.21 Another team of Lawrence Berkeley National Laboratory researchers interviewed 29 customers in the Niagara Mohawk Power Corporation service territory with day-ahead dynamic prices in 2004. The study specified that reasons customers gave for why they were not price-responsive included implicit value placed on reliability, pricing structures, lack of flexibility in adjusting production inputs, just-in-time practices, perceived barriers to onsite generation, and insufficient time.22
Therefore, a premature introduction of dynamic rates may cause confusion and shift additional market price risk onto customers, creating a negative customer experience that may hinder adoption of both the new rate and longer-term load flexibility initiatives. A hurried implementation of a complex and untested dynamic rate structure is likely to result in costs, rather than benefits, to the grid and to customers.
4.3.5 Compliance Approach
Based on the results of this evaluation, SDCP plans to continue offering the existing portfolio of time-dependent rates. SDCP regularly reviews its rates, including cost-effectiveness. SDCP also plans to implement new load flexibility programs and pilots that will help the organization better understand how best to engage with behind-the-meter customer devices. With additional information and results, SDCP can consider developing a dynamic rate pilot rate for one or more customer classes in the future.
Therefore, SDCP will defer developing and proposing adoption of new dynamic rates beyond July 1, 2025, and offering voluntary participation in any such rates beyond July 1, 2027.
Based on available information, SDCP cannot conclude that proposing and implementing dynamic rates, as proposed in the LMS requirements’ timeline, would be cost-effective, provide equity benefits, be technologically feasible, and/or or yield any cost savings or emissions-related benefits to the grid and to customers. The risks of premature implementation can adversely impact participating customers’ bills, the overall customer experience, and even SDCP’s image and reputation.
In lieu of developing and proposing adoption of new dynamic rates, SDCP has and will continue to implement and offer load flexibility programs to support the intent and goals of the LMS and to meet LMS compliance.
SDCP plans to reassess the timeline for proposing and implementing dynamic rates no later than the triennial review of the Plan. The Plan review will also include potential updates to qualitative and quantitative evaluations for cost-effectiveness, equity, technological feasibility, and benefits to the grid and to customers. 21 A Survey of Utility Experience with Real Time Pricing, Lawrence Berkeley National Laboratory and Neenan Associates, December 2004, ES-9.
22 Real Time Pricing and the Real Live Firm, Lawrence Berkeley National Laboratory, August 2004, page 1. 86 31
5. Load Flexibility Programs
The adopted LMS amendments recognize that load flexibility programs may provide an alternative pathway to achieve the objectives of encouraging off-peak energy usage, controlling peak load to improve reliability and system efficiency, lessening, or delaying the need for new capacity, and reducing fossil-fuel consumption.
Adopted LMS amendments section 1623.1(a)(1)(B) requires each Large CCA to propose and evaluate programs that enable automated responses to marginal cost-based signals for each customer class, if the Large CCA does not propose the development of marginal cost-based rates. The programs must be evaluated based on cost effectiveness, equity, technological feasibility, and benefits to the grid and customers.
Adopted LMS amendments section 1623.1(b)(3) requires each Large CCA to submit a list of cost-effective MIDAS-integrated load flexibility programs to the CEC Executive Director by October 1, 2024. The portfolio of load flexibility programs must provide at least one option to automate response to MIDAS signals (that indicate, for example, hourly marginal cost-based rates, marginal prices, or hourly or sub-hourly GHG emissions) for every customer class where such a program is determined by its rate-approving body to materially reduce peak load.
Finally, each Large CCA is required to offer customers, by July 1, 2027, voluntary participation in a dynamic hourly rate, if approved by its rate-approving body, or a cost-effective MIDAS-integrated load flexibility program identified according to section 1623.1(b)(3).
The following section of SDCP’s Plan provides an overview of SDCP’s current and in-development future load flexibility programs and addresses the LMS requirement to evaluate and propose specified programs on timeframes. It also addresses the requirement to submit a list of cost-effective MIDAS-integrated load flexibility programs to the CEC.
5.1 Overview of SDCP Load Flexibility Programs
Load flexibility is a key strategy in helping SDCP achieve its 100 percent renewable energy goal. SDCP is currently piloting several programs that enable customers to be part of the strategy, dynamically managing load to reduce costs and increase grid resilience.
SDCP is focused on developing and offering load management programs that are simple, effective, flexible, and that allow SDCP to make rapid progress in unlocking peak load reduction potential. SDCP is working to innovate with technology and software providers to advance functionalities that will enable broad participation and maximize potential resources, optimized for customer and grid needs. When designing programs, SDCP strives to tailor its offers to specific customer segments and/or needs to maximize responsiveness beyond just price alone, delivering the greatest potential for mutual benefits to customers and to SDCP.
Piloting multiple approaches is a key strategy for SDCP. Pilot study results inform future program designs, and the technology needed to scale adoption. SDCP’s in development program portfolio includes a portfolio-level Distributed Energy Resource Management 87 32
(“DERMS”) deployment that will, in time, serve as the central point of control and dispatch for a range of load flexibility program offerings, which may include residential, C&I, and agricultural customer classes. In the near term, SDCP is developing specific offerings related to residential load flexibility and electric vehicle-managed charging. SDCP is also still in the stage of exploring program offerings for agricultural and large C&I customer classes.
Agricultural customers contribute to approximately 4% of SDCP’s total load in 2024, thus SDCP is initially focusing on residential and commercial customers with load flexibility programs since those customer classes make up the bulk of SDCP’s load. For large C&I customers, SDCP is in the process of exploring and designing appropriate program offerings that are cost-effective and provide benefits to the customers. Dedicating constrained resources to focus on residential and small commercial customers has the benefit of easily replicating and growing current programs and pilots. Lessons learned and evaluations from current program offerings will be valuable before designing and potentially launching more complex programs for large C&I customers who have more complex operations and more specific requirements and/or needs.
The following section provides a list of existing and planned program offerings that test reliability, load reduction, and customer adoption. These programs support the intent and spirit of LMS goals and are also LMS compliant, with justifications of modifications to LMS requirements provided within each program summary below.
5.1.1 LMS Compliant Load Flexibility Programs
5.1.1.1 Bring Your Own Device Load Shifting Pilot
a. Pilot Name: Smart Home Flex
b. Date of first availability: The program first became available on a pilot basis in Q1 2025, with enrollment limited to 2,000 thermostats and 150 water heaters. Following evaluation of device performance, SDCP anticipates relaunching the pilot as a full program which will remain active and available past July 1, 2027, for both active and new participants.
c. Customer class and device eligibility: The pilot is open to residential customers with a qualified device. Qualified devices are currently limited to smart thermostats and water heaters and will expand to include pool pumps and battery storage in the next 1-2 years after the pilot is launched.
d. Device dispatch: The pilot dispatch strategy is designed to deliver daily load shifting value. The specific device-level dispatch varies by asset class, based on the technical and operational limitations of the equipment and/or Original Equipment Manufacturer (“OEM”). For example, smart thermostats are dispatched during the summer 88 33
cooling season generally for 4 hours at a time, with 1 hour of precooling followed by 3 hours of shed and called approximately 20 times per season. Thermostats are operated to maximize load shifting value, and while daily dispatch is not allowed by device OEMs, the strategy seeks to maximize alignment with price and load. Smart water heaters are called on twice daily throughout the year, with 1 hour of preheating followed by 2 hours of shed. As pool pumps and battery storage systems are brought into the pilot, they will operate as a daily load shifting asset. In all cases, enrolled devices are/will be used to shift load to lower cost, lower demand periods, while minimizing impacts to participant comfort or utility. e. Dispatch signal: Resources are dispatched based on a multi-tier optimization framework. First, the pilot limits load-up commands to off peak periods and schedules load reductions to occur on peak, to maximize bill savings for participants. Within this constraint, the pilot dispatches devices in a manner that maximizes peak load reduction, using SDCP’s DERMS. The DERMS allows for coordinated control and management of participating DERs and will, once available, use the Market Informed Demand Automation Server (“MIDAS”) to incorporate day ahead pricing data into the dispatch and operationalization of the daily load shifting strategy. Finally, the pilot will override its daily load management strategy in the event of a grid emergency, to support statewide peak load reduction efforts. f. Pilot Incentives: Customers may receive one or more of three categories of incentives for participating in the pilot, an upfront (or enrollment incentive), a participation (or seasonal) incentive and/or a performance incentive. The upfront incentive is a flat, one-time, per device payment (currently set at $50) for enrolling in the pilot program. The participation incentive is paid out seasonally for devices that remain in the pilot through a load shifting seasonal window (summer or winter). The performance incentive is a payment to customers that varies based on a device’s
responsiveness to daily load shifting commands. The specific incentives a pilot participant receives vary based on the device(s) enrolled. All enrolled DERs receive an enrollment incentive; however, some OEMs and/or DER asset classes are less conducive to, and in some cases prohibited from participating in, performance-based incentives. 23 In the case of smart thermostats, OEMs often
keep participant data confidential, even towards load serving entities. In such a scenario, it is not possible for the load serving 23 One of the major smart thermostat OEMs explicitly prohibits participation of its devices in programs or pilots that include performance-based incentives. Given this prohibition, the thermostat portion of SDCP’s Smart Home Flex Pilot does not offer performance-based incentives. 89 34
entity to design performance-based incentives. For heat pump water heaters, the devices are already so energy efficient that there may not be enough capacity reduction to be achieved through their operational changes. SDCP prefers the use of performance-based incentives over fixed participation incentives whenever possible and will regularly revisit incentive design to ensure that performance-based incentives are being used. g. Available supporting weblinks and reference materials:
https://sdcommunitypower.org/programs/smart-home-flex/
5.1.1.2 Solar Batteries Savings (“SBS”) Program
a. Pilot Name: Solar Batteries Savings
b. Date of first availability: The program first became available on a pilot basis in Q2 2024. Pilot enrollment is limited to 2,000 residential energy storage systems. SDCP anticipates relaunching SBS as a full program in Q3 2025, which will remain active and available past July 1, 2027, for both active and new participants.
c. Customer class and device eligibility: The pilot is open to residential customers with a qualified device. Qualified devices in the pilot phase covered all major residential energy storage manufacturers. At program relaunch, eligibility will be limited to battery OEMs that have an active integration with SDCP’s DERMS platform, Virtual Peaker. SDCP is assessing a potential program expansion to include commercial customers.
d. Device dispatch: The pilot dispatch strategy is designed to deliver daily load shifting value. Under the pilot program design, participating batteries are charged from onsite solar Photo-Voltaic (“PV”) and discharged daily (weekdays only or weekdays and weekends, based on customer preference), during a two-hour window that changes monthly based on SDCP’s demand profile.
Participants can select the percentage of their battery’s useable capacity to enroll in the program, with a minimum requirement of 50%. The dispatch strategy for the relaunched program is still under development but will likely expand the dispatch window from two hours to four hours and simplify the design by eliminating weekend dispatches.
e. Dispatch signal: Resources are dispatched based on a multi-tier optimization framework. First, participating batteries are required to charge exclusively from on-site solar, the least carbon intensive resource available. Next, the pilot schedules battery discharges to occur during on-peak, maximizing participant bill savings. Within this constraint, the pilot then dispatches devices in a manner that maximizes peak load reduction, using SDCP’s DERMS. The DERMS allows for coordinated control and management of participating DERs and will, once 90 35
available, use MIDAS to incorporate day ahead pricing data into the dispatch and operationalization of the daily load shifting strategy. Finally, the pilot will override its daily load management strategy in the event of a grid emergency, to support statewide peak load reduction efforts.
f. Pilot Incentives: Customers receive two categories of incentives for participating in the pilot, an upfront and a performance incentive. The upfront incentive is a one-time, volumetric incentive based on the nameplate usable capacity of the battery being installed. The performance incentive is payment to customers that varies based on the amount of actual device discharge over the dispatch window during on-peak periods. In addition, the SBS pilot has two incentive tiers: Market Rate and Non-Market Rate; with higher Non-Market Rate incentives available for California Alternate Rates for Energy (“CARE”) and Family Electric Rate Assistance Program (“FERA”) customers and those located in one of SDCP’s Communities of Concern.
The performance-based incentive is based on the spirit of hourly marginal cost, in which charging and discharging profiles have a fixed value. Currently, there is no added benefit to providing incentives at a granular hourly level to achieve load impact results.
g. Available supporting weblinks and reference materials:
https://sdcommunitypower.org/programs/solar-battery-savings-program-2/
5.1.1.3 Managed Charging (V1G) Program
a. Pilot Name: EV Flex Connect
b. Date of first availability: The program first became available on a pilot basis in Q1 2025. Pilot enrollment is limited to 1,000 vehicles. Following evaluation of pilot performance, SDCP anticipates relaunching the pilot as a program which will remain active and available past July 1, 2027, for both active and new participants.
c. Customer class and device eligibility: The pilot is open to residential customers with a qualified vehicle. Qualified vehicles are currently limited to those with a commercially sanctioned (a.k.a. “partner”) Application programming Interface (“API”). Community Power is also undergoing an assessment of a commercial V1G offering.
d. Device dispatch: The pilot dispatch strategy is designed to deliver daily load shifting value. Participating vehicles are scheduled to charge during off-peak periods, with charging windows and durations optimized to ensure each vehicle reaches its desired state of charge by the scheduled departure time. The pilot is designed to achieve bulk system value from managed charging and to reduce peak load and spread load across the hours of the day.
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e. Dispatch signal: Resources are dispatched based on a multi-tier optimization framework, with optimization around time-of-use rate structures. First, the pilot reschedules all vehicle charging to occur off peak, to maximize bill savings for participants. Within this constraint, the pilot then optimizes charging schedules in a manner that maximizes peak load reduction, using SDCP’s V1G vendor platform. The V1G platform allows for coordinated control and management of participating vehicles and will, once available, use MIDAS to incorporate day ahead pricing data into the dispatch and operationalization of the daily load shifting strategy. This optimization is focused on spreading overnight charging load evenly across the off-peak period to avoid secondary peaks and impacts on slice-of-day resource adequacy. Finally, the pilot will override its daily load management strategy in the event of a grid emergency, to support statewide peak load reduction efforts. In addition, SDCP will also collaborate with SDG&E to understand how distribution operational needs can be incorporated into the optimization framework, seeking to balance bulk system and distribution value. f. Pilot Incentives: Customers may receive two categories of incentives for participating in the pilot, an upfront (or enrollment incentive) and a participation incentive for staying enrolled in the pilot. The upfront incentive is a flat, one-time, per vehicle payment for enrolling in the pilot. The participation incentive is a monthly incentive, paid out seasonally for vehicles that remain in the pilot through a load shifting seasonal window (summer or winter). SDCP is considering a more performance-based incentive following the evaluation of pilot results, once the slice of day capacity value is better understood. g. Available supporting weblinks and reference materials:
https://sdcommunitypower.org/programs/ev-flex-connect/
5.2 Evaluation of Programs
SDCP is in the process of developing and implementing a robust portfolio of programs, including load flexibility, that strikes the right balance between customer needs and grid benefits. As summarized above, this portfolio is focused initially on the residential customer segment and exploring various dispatch signals, including automated response. These signals are based on several factors, including day-ahead marginal prices. The program development process will include collaborating with external vendors to build a technology platform that can optimize and automate dispatch of DERs.
The next section of the Plan evaluates the cost-effectiveness, equity, technological feasibility, and benefits to the grid and to customers of implementing programs that enable automated response to dispatch signals, including MIDAS signals, year-round, that are available to every customer class by July 1, 2027. Without program results at this time, SDCP cannot quantify the magnitude of peak load reduction, and/or other benefits can be provided through programs that enable automated dispatch based on MIDAS signals.
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5.2.1 Cost-Effectiveness
The first evaluation factor is cost-effectiveness. SDCP will assess cost-effectiveness of new programs by comparing the estimated costs and incremental benefits associated with designing and implementing new load flexibility programs that allow for response to dynamic price signals and other grid conditions.
For a program to be cost-effectiveness, the expected benefits must exceed the costs of design and implementation.
5.2.1.1 Estimated Costs
The costs associated with implementing a new load flexibility program include program development, implementation, and administration costs. SDCP anticipates these cost categories would apply, regardless of customer class.
• Program development costs include the costs associated with program design and setup, including integrating new programs with the CEC’s MIDAS database and any applicable technology platform to the extent feasible.
• Program administration costs include ongoing costs to administer the program such as marketing, customer recruitment, customer education, development and maintenance of customer tools, and any upfront or ongoing incentive payments that are part of the design. • Technology and implementation costs include any external software systems that must be procured to communicate with and dispatch devices, as well as internal systems which must be developed and configured to integrate the external software. New load flexibility programs may require significant investments in new technology platforms.
5.2.1.2 Estimated Benefits
The following section describes the potential benefits associated with implementing programs that allow for automated response to dynamic price signals, including MIDAS signals, and the estimated realization of such benefits based on the additional load shift capacity available to be captured.
5.2.1.2.1 Potential Benefits
The potential benefits associated with implementing programs that achieve incremental load shift include avoided capacity and energy costs, improved reliability during peak periods, avoided GHG compliance costs, and avoided air quality, public health, and environmental costs associated with a reduction in fossil-fuel generation, consistent with the benefits discussed in Section 4.3.4.6. These potential benefits are not unique to programs implemented for any one customer class.
5.2.1.2.2 Realization of Benefits
There are several uncertainties and barriers associated with realizing the above-identified incremental load shift potential and its associated benefits. SDCP expects these barriers and uncertainties to apply across residential, C&I, and agricultural customer classes. These uncertainties and barriers are summarized as follows:
• While there has been a rapid increase in the number of devices on the market that are able to automate load reductions, SDCP is not aware of any devices capable of effectively responding to real-time signals without significantly compromising customers’ daily activities. Battery storage, EVs and even thermostats all require advance notice to meet customer needs. 93 38
• Removing the limits on how many program events can be called may bring additional load flexibility to utilities and CCAs, but frequent device dispatch without first understanding the impacts on customer experience runs the risk of eroding participation and satisfaction in the program.
• SDCP anticipates that directly exposing participants to market prices could result in deeper load reductions, to the extent that increasing prices will drive customers to shift more load away from the peak. However, the magnitude of additional load reduction as a function of price is not yet known. In addition, higher customer risk with dynamic prices is likely to reduce participation and benefits.
• SDCP anticipates that new programs would have to tap into load shift on 5- to 10- minute intervals to create incremental benefits relative to our programs and it is not yet known whether the issuance of multiple price signals over a peak period, or higher prices over the same period, would result in material incremental benefits, compared to existing programs.
5.2.1.2.3 Expected Incremental Benefits
Based on the above factors, following is a discussion of expected incremental benefits associated with programs that allow for automated response to dynamic price signals:
• The primary value stream for SDCP’s load flexibility programs will be avoided RA procurement.
To the extent a given program can generate MWs that meet the resource characteristics needed to avoid RA procurement; these avoided costs can be credited against the costs associated with implementing the program. While programs that expose customers to dynamic price signals may drive incremental load reductions when prices are highest, it is unknown how much and how reliable that incremental reduction would be, and how it would be credited under the current RA framework. Moreover, the magnitude of the load shift depends on significant adoption and acceptance of enabling technology.
• To the extent that new program structures and technology allow for faster load shift in response to short price spikes or drive greater load shift away from peak periods, SDCP could see reductions in energy purchase costs, but this is currently not yet known. Future program design will seek to maximize the energy savings associated with customer load flexibility, balanced against technological capability, customer acceptance, and impact on the overall energy system. • Given uncertainties around customer response to dynamic price signals and current penetration of enabling technology, SDCP is unable to determine whether there would be secondary benefits (reliability benefits, avoided transmission and distribution costs, avoided GHG compliance costs, avoided public health, air quality, and environmental costs) associated with further reducing demand during peak periods from programs with automated response to hourly price signals versus existing programs.
5.2.1.3 Discussion
Based on the foregoing evaluation, SDCP cannot conclude that the development of new programs that allow for automated responses to dynamic price signals would be cost-effective at this time. SDCP will incur new programs’ costs associated with design, implementation, and new technology investments. 94 39
While these costs could potentially be offset with capacity and/or energy cost savings, the magnitude of those benefits is uncertain.
In addition, SDCP anticipates that any incremental benefits will be limited in the near-term, while new technology is continuing to grow. SDCP will continue to assess the expected incremental costs and benefits associated with incorporating more dynamic price signals and/or allowing resources to be dispatched by MIDAS signals, as SDCP develops and potentially implements new programs.
5.2.2 Equity
The second criterion for evaluating new programs is equity. SDCP qualitatively evaluates whether programs that enable automated response to dynamic prices, including MIDAS signals, are likely to lead to equitable outcomes.
5.2.2.1 Equitable Access to Direct Benefits
When designing any program, SDCP ensures that all aspects of program design take equity into account.
SDCP has committed to equity and the specific strategies for addressing it in SDCP’s Community Power Plan (“CPP”). The CPP was created to provide strategic direction for developing customer energy programs that respond to community needs, with a focus on underserved communities and equity.
In accordance with the CPP, SDCP is committed to include equity as a core principle when designing programs that allow for response to dynamic signals, given the current access barriers and risk of price exposure that may disproportionately be experienced by lower income customers and customers from our communities of concern.
5.2.2.2 Equitable Access to Indirect Benefits
Program design also plays a major role in determining whether a program delivers incremental load shift benefits and results in cost savings and improved air quality, public health, and environmental outcomes that accrue to all customers. The realization of any indirect benefits is uncertain because SDCP cannot quantify load shift benefits that dynamic price signals would result.
5.2.2.3 Discussion
Based on the foregoing evaluation, SDCP is unable to conclude that implementing new programs that allow for automated response to dynamic price signals, including MIDAS signals, would materially address equity. Programs can be designed to ensure equitable access to participation and benefits regardless of if the programs incorporate sending dynamic signals directly to customers. Furthermore, the risk of price exposure from dynamic rates could potentially exacerbate inequities in outcomes.
5.2.3 Technological Feasibility
The third evaluation factor for programs is technological feasibility. SDCP’s evaluation assesses the technological feasibility of implementing programs that allow for automated response to dynamic price signals on the schedule specified in the LMS requirements. SDCP’s evaluation considers the feasibility of both the systems needed to dispatch dynamic price signals, including MIDAS signals, and external customer technology that is needed to enable response to hourly or sub-hourly signals. 95 40
5.2.3.1 SDCP’s Technology Systems
As described previously, SDCP will continue to coordinate and collaborate with external vendors and SDG&E to ensure technological platforms are configured to implement new programs. SDCP has started discussions with multiple parties in assessing whether it is technologically feasible to incorporate programs that enable automatic response to dynamic price signals, including MIDAS signals, into current platforms.
5.2.3.2 Enabling Customer Technology
The incremental benefits derived from implementing new programs that allow for response to dynamic price signals depend on customer participation and the widespread availability and acceptance of devices that can respond to sub-hourly price signals without compromising customer experience. Refer to Section 4.3.3.2 for a detailed description of common load flexibility technologies deployed across the state, and their capabilities and challenges.
5.2.3.3 Discussion
SDCP is uncertain whether the technology and platforms needed to enable programs that allow for response to dynamic price signals exist or could be updated on the LMS requirements’ timeframe, given close coordination and collaboration with external vendors and SDG&E will be required. However, SDCP has started discussions with those parties on technological feasibility in anticipation of developing and offering programs with enabling device automation technology.
5.2.4 Benefits to the Grid and Customers
The final two criteria for evaluating dynamic rates are benefits to the grid and to customers. SDCP is evaluating these factors separately, in contrast to the previous dynamic rates evaluation.
5.2.4.1 Benefits to the Grid
To the extent that new programs enabling responses to dynamic price signals result in consistent, material incremental load reduction, the following are potential grid benefits:
• Deferred or reduced need for new generation capacity or RA procurement. • Deferred or reduced need for wholesale energy purchases to meet peak demand. • Deferred or reduced need to upgrade transmission and/or distribution capacity to deliver energy to meet peak demand.
• Increased reliability is associated with reducing grid strain during periods of peak demand.
These benefits all depend, in significant part, on the magnitude of load shift resulting from new programs. Mutual benefit is necessary for effective, consistent load shift. With limited available information, SDCP is unable to quantify the load shift benefits of new MIDAS-integrated programs.
5.2.4.2 Benefits to Customers
The following is a summary of potential customers benefits associated with implementing new programs that allow for automated response to dynamic price signals:
96 41
• Pass-through cost savings associated with the realization of a reduced need for generation capacity, transmission and/or distribution upgrades, and higher-price wholesale energy purchases to meet peak load.
• Pass-through cost savings associated with avoided GHG compliance costs, to the extent that the incremental load shift reduces the need to rely on fossil-fuel resources to meet peak demand.
SDCP anticipates these savings will become less significant as SDCP’s energy supply transitions towards 100 percent renewable energy.
• Pass-through increased reliability, to the extent this grid benefit is realized. • Improved public health, air quality, and environmental outcomes, to the extent that the incremental load shift reduces the need to rely on fossil-fuel resources to meet peak demand. • Cost savings associated with participation, to the extent that devices automatically shift load away from higher price periods.
Based on the uncertainty of the magnitude of load reduction benefits that the new programs can achieve, SDCP is unable to conclude that there would be any incremental pass-through cost savings or reliability benefits to customers. Similarly, SDCP anticipates that any incremental air quality, public health, and environmental benefits would also be uncertain.
5.2.5 Compliance Approach
The following section of the Plan describes how SDCP plans to address the requirements to identify cost-effective programs that allow for automated response to dynamic price signals and offer customers voluntary participation in these programs, based on our evaluation of such programs.
5.2.5.1 Identification of Cost-Effective Load Flexibility Programs Consistent with the LMS requirements, SDCP will submit to the CEC, no later than October 1, 2024, a list of cost-effective load flexibility programs that enable automated response to MIDAS signals for each customer class, if any, where such a program is determined by SDCP’s Board to materially increase peak load reduction. SDCP is in the process of implementing its load flexibility programs, with pilots and/or programs designed to reduce peak load. SDCP will continue to evaluate the cost-effectiveness and incremental peak load reduction potential associated with incorporating automated response to MIDAS signals.
5.2.5.2 Voluntary Participation in Cost-Effective Load Flexibility Programs SDCP is currently implementing and developing load flexibility programs that may offer customers voluntary participation. However, SDCP is unable to demonstrate that offering such programs beginning on July 1, 2027 would be cost effective. SDCP will continue to assess the cost-effectiveness and peak load reduction potential of programs that enable automated response to MIDAS signals as more information becomes available.
6. Public Information Program
Adopted LMS amendments section 1623.1(a)(5) requires each large CCA to conduct a public information program to inform and educate impacted customers about dynamic rates and/or load flexibility programs. Specifically, the information program must explain why dynamic rates or load flexibility 97 42
programs, and their automation, are needed, how they will be used, and how they lower energy costs.
This section of the Plan addresses how SDCP will comply with the public information program requirements.
6.1 SDCP’s Communication Approach
As a community-driven local electricity provider, SDCP is committed to broad customer outreach and education, communication, and customer service. SDCP provides its customers with the information, education, and tools to best manage their energy use according to their needs.
SDCP communicates through a wide variety of channels, including our website, social media, in-person, and direct mail to help ensure customers are aware of SDCP more broadly and specifically about available time-dependent rates and load flexibility programs, and their benefits.
As part of our commitment to customer access and education, SDCP formally established a Language Access Policy to ensure that customers can access information and materials in their preferred language.
SDCP’s customer service agents regularly interact with customers over the phone and email to address questions and concerns and resolve issues. We strive to empower our customers with comprehensive information, education, and tools tailored to meet their unique energy needs.
SDCP has developed a comprehensive and customer-centric communication strategy that recognizes the unique customer segments that SDCP serves. This strategic approach is designed not only to disseminate information but to empower our customers, enabling them to make well-informed decisions aligned with their individual needs. Through our website, customers have access to a centralized hub of resources, where they can find detailed information and educational materials tailored to enhance their understanding of SDCP as an organization, energy efficiency, and time-dependent rates. Our active presence on various social media platforms amplifies our engagement, providing a space for interactive communication and real-time updates. In the spirit of transparency, SDCP maintains regular communication with regional media, providing factual and timely information to the broader public.
SDCP’s communication and community outreach efforts reflect the diverse communities we serve, so a broad mix of communication channels is used to reach all customers. This includes in-person outreach in the community at public events with information and resources available to the attendees. SDCP regularly participates in events across our member agencies as we aim to increase general awareness and answer questions in a friendly, helpful manner. In addition to community outreach, SDCP consistently sponsors large events throughout the greater San Diego region to increase general brand awareness.
6.2 Current Outreach and Marketing
SDCP recognizes the importance of collaboration and public outreach. SDCP has engaged in a variety of public relations, marketing, community outreach, and local government affairs activities to drive energy awareness and education, spark community engagement, and maintain high customer enrollment. We work closely with internal and external stakeholders to encourage participation in programs and leverage relationships with community partners to amplify our marketing and outreach efforts. 98 43
As noted above, SDCP’s commitment to broad, in-person outreach and engagement is critical to our efforts. In 2023 SDCP participated in over 70 in-person events throughout our service territory which created the opportunity for approximately 250,000 interactions.
Having recently completed mass enrollment, SDCP has expanded marketing efforts to continue to educate our customers about SDCP and specifically, on the simple actions they can take to limit energy use during times of peak use. Energy tips and education around time-dependent rates can be found across our digital communication channels and in printed materials, including the Power Content Label mailer, which serves as an annual touchpoint with customers. This approach has expanded to digital efforts in both organic and paid social media, and into other marketing efforts, including a year-long sponsorship agreement with San Diego Magazine across print and digital channels and other local print and television outlets.
To achieve decarbonization goals, SDCP will continue to educate customers on the benefits of peak load reduction through time-dependent rates and load flexibility programs, how they work and how they can save the customers money. SDCP will continue to develop new strategies, processes and capacity to conduct more community outreach, expand marketing and brand awareness efforts, and provide timely, accurate information across multiple channels.
6.3 Compliance Approach
SDCP will continue with communication best practices to maintain its outreach, education, and marketing of rates, programs, and pilots that support load flexibility and recognize the benefits of reducing peak load. In parallel, SDCP will also update education and marketing materials to incorporate discussion of new rates, programs, and pilots, along with the role of automation.
7. Delay and Modification of Compliance Requirements
Adopted LMS amendments section 1623.1(a)(2) of the LMS regulation specifies that a Large CCA may approve a compliance plan, or material revisions to an approved plan, that delays or modifies compliance with certain LMS requirements. To do so, the compliance plan must demonstrate one of the following factors:
• Despite good faith efforts to comply, requiring timely compliance would result in extreme hardship.
• Requiring timely compliance would result in reduced system reliability, equity, safety, or efficiency.
• Requiring timely compliance would not be technologically feasible or cost-effective to implement.
• Or despite good faith efforts to implement a compliance plan, it must be modified to provide a more technologically feasible, equitable, safe, or cost-effective way to achieve the LMS requirements or the plan’s goals.
This section of the Plan addresses how SDCP’s Plan delays or modifies compliance with certain elements of the LMS requirements.
99 44
7.1 Providing RINs to Customers
Adopted LMS amendments section 1623(c)(4) requires each Large CCA to provide customers access to their RIN(s) on billing statements and in online accounts by April 1, 2024, using both text and QR code.
As detailed in section 3.1.2 of this Plan, SDCP made the RINs available to customers in the required formats within the designated time.
7.2 Statewide RIN Access Tool
7.2.1 Development of Statewide Tool
Adopted LMS amendments section 1623(c) requires the utilities and Large CCAs to develop a single statewide standard tool for authorized rate data access by third parties, along with a single set of terms and conditions for third parties using the tool, for submission to the CEC by October 1, 2024, for approval.
As discussed in section 3.1.3, SDCP has been working with the other regulated LSEs in creating the statewide RIN tool pursuant to 20 CCR Section 1623(c). A proposed plan for the tool was submitted to the CEC for review on October 1, 2024. We will continue to work with the other LSEs and the CEC to implement and maintain the statewide RIN tool in a timely manner, subject to the Commission’s approval.
7.2.2 Implementation of Statewide Tool
Adopted LMS amendments section 1623(c)(3) also requires the utilities and Large CCAs to implement and maintain the tool, upon its approval by the CEC. SDCP does not anticipate needing to modify compliance with this requirement currently. However, SDCP notes that integration of the approved tool with internal systems could be delayed if the development and/or CEC approval of the tool are delayed, because integrating the tool before it is finalized and approved would not be technologically feasible, or if the cost of integrating the tool would cause extreme hardship for SDCP or SDCP’s customers.
7.3 Dynamic Rates
Adopted LMS amendments section 1623.1(b)(2) directs each Large CCA to apply for approval of at least one dynamic rate for the customer class(es) from its Board by July 1, 2025, for which the Board determines such rate will materially reduce peak load. Section 1623.1(b)(4) requires CCAs to offer customers voluntary participation in such a rate or a specified load flexibility program by July 1, 2027.
As discussed in Section 4.3, based on its evaluation of dynamic rates, SDCP cannot currently conclude that developing and implementing such rates on the LMS timeframe for any customer class would result in material reductions in peak load or be cost effective. This is due to the following:
• Delayed SDG&E service area dynamic rate pilots, and corresponding data, to evaluate peak load reduction and cost-effectiveness.
• There is a significant market risk to customers on dynamic rates, even with enabling load-shifting technology. 100
45 • Customers understand time-dependent rates and programs better than a dynamic, market-based rate that fluctuates hourly.
While dynamic rates have the potential to provide incremental load shift and related benefits, there are significant uncertainties in the magnitude of such benefits. Without evaluation data from SDG&E service area dynamic rate pilots, it is incredibly difficult to quantify incremental load shift benefits and cost-effectiveness of dynamic rate implementation. In addition, implementation of unfamiliar and complex rate structures without sufficient testing and refinement of new rate designs, as well as thorough education, is likely to cause customer confusion, risking low adoption and limiting any incremental load shift benefits. The realization of incremental load shift benefits is made more uncertain by additional risks customers may bear with dynamic rates, especially if new enabling technology is not widely adopted.
While SDCP is not required to propose dynamic rates where such rates are not determined to materially reduce peak load, SDCP has determined that, for the reasons set forth in this Plan, the LMS requirements must be modified to provide a more cost-effective and technologically feasible way for SDCP to, in good faith, meet the LMS requirements and achieve the LMS goals. Thus, SDCP proposes to modify the dynamic rate requirements of the LMS to defer the development or proposal of new hourly or sub-hourly rate options and offering new rates to SDCP’s customers would be likewise deferred. SDCP believes proposing dynamic rates to our Board by July 1, 2025, to implement them by July 1, 2027, is premature. SDCP will continue offering our suite of time-dependent rates while gathering information for analysis once data is available from dynamic rate pilots in SDG&E’s service area. The results of the pilots will help SDCP better understand the effectiveness of the pilot approach, how customers with different technologies respond to different dispatch signals, and to what extent incremental load shift opportunities exist beyond existing time-dependent rates and programs. As SDCP receives and analyzes results from those pilots, SDCP will be better positioned to evaluate the cost-effectiveness and flexibility of dynamic rates. SDCP will review dynamic rates in the next Plan update. In lieu of developing and proposing adoption of new dynamic rates, SDCP has and will continue to implement and offer load flexibility programs to support the intent and goals of the LMS and to meet LMS compliance.
7.4 Dynamic Response Load Flexibility Programs
7.4.1 Identification of Cost-Effective Load Flexibility Programs Adopted LMS amendments section 1623.1(b)(3) requires each Large CCA to submit a list of cost-effective MIDAS-integrated load flexibility programs to the CEC Executive Director by October 1, 2024.
The portfolio of load flexibility programs must provide at least one option to automate response to MIDAS signals (that indicate, for example, hourly marginal cost-based rates, marginal prices, or hourly or sub-hourly GHG emissions) for every customer class where such a program would materially reduce peak load.
As discussed in Section 5.3, adding or modifying programs to allow response to MIDAS signals has not yet been determined to result in material incremental reductions in peak load for any customer class or to be cost effective. This is in part due to the uncertainties in incremental peak load reduction potential and customer acceptance when introducing hourly or sub-hourly price signals and exposure to market price spikes and volatility.
SDCP is required to identify MIDAS-integrated dynamic load flexibility programs for customer classes where such programs are determined to be cost-effective and materially reduce peak load. SDCP 101
46 anticipates submitting a list that includes planned load flexibility programs and pilots that achieve LMS goals without automated response to MIDAS signals, by October 1, 2024, because SDCP’s evaluation has not concluded that developing and implementing programs or pilots with automated response to MIDAS would be cost-effective or materially reduce peak load. SDCP is in the process of implementing its load flexibility programs, with pilots and/or programs designed to reduce peak load. Thus, SDCP will evaluate the cost-effectiveness and incremental peak load reduction potential associated with incorporating automated response to MIDAS signals into these pilots and/or programs and include them on a future list as appropriate.
7.4.2 Voluntary Participation in Cost-Effective Load Flexibility Programs Adopted LMS amendments section 1623.1(b)(4) requires each Large CCA to offer customers voluntary participation in either a dynamic rate, if approved by the Board, or cost-effective MIDAS-integrated load flexibility program by July 1, 2027.
SDCP is required to offer voluntary participation in cost-effective load flexibility programs that materially reduce peak load. As discussed in Sections 5 and 7.4.1 above, SDCP’s evaluation has been unable to conclude that developing and implementing new load flexibility programs or pilots with automated response to MIDAS signals would be cost effective or materially reduce peak load. SDCP will assess the cost-effectiveness and peak load potential of planned and new programs that enable automated response to MIDAS signals as SDCP develops and refines load flexibility programs. Based on feedback from CEC staff, SDCP has and will continue to implement and offer load flexibility programs that are LMS compliant and support the intent and goals of the LMS. 102
47 Appendix A
The following are the RINs associated with each SDCP’s rates and rate permutations that were uploaded to MIDAS, as of 1/1/2024.
RIN Rate Permutation
USCA-XXSA-0001-0000 G-A6-TOU-P 2020 Vintage
USCA-XXSA-0002-0000 G-A6-TOU-P 2021 Vintage
USCA-XXSA-0003-0000 G-A6-TOU-P 2022 Vintage
USCA-XXSA-0004-0000 G-A6-TOU-T 2020 Vintage
USCA-XXSA-0005-0000 G-A6-TOU-T 2021 Vintage
USCA-XXSA-0006-0000 G-A6-TOU-T 2022 Vintage
USCA-XXSA-0007-0000 G-AL-TOU-P 2020 Vintage
USCA-XXSA-0008-0000 G-AL-TOU-P 2021 Vintage
USCA-XXSA-0009-0000 G-AL-TOU-P 2022 Vintage
USCA-XXSA-0010-0000 G-AL-TOU-S 2020 Vintage
USCA-XXSA-0011-0000 G-AL-TOU-S 2021 Vintage
USCA-XXSA-0012-0000 G-AL-TOU-S 2022 Vintage
USCA-XXSA-0013-0000 G-AL-TOU-T 2020 Vintage
USCA-XXSA-0014-0000 G-AL-TOU-T 2021 Vintage
USCA-XXSA-0015-0000 G-AL-TOU-T 2022 Vintage
USCA-XXSA-0016-0000 G-DG-R-P 2020 Vintage
USCA-XXSA-0017-0000 G-DG-R-P 2021 Vintage
USCA-XXSA-0018-0000 G-DG-R-P 2022 Vintage
USCA-XXSA-0019-0000 G-DG-R-S 2020 Vintage
USCA-XXSA-0020-0000 G-DG-R-S 2021 Vintage
USCA-XXSA-0021-0000 G-DG-R-S 2022 Vintage
USCA-XXSA-0022-0000 G-DG-R-T 2020 Vintage
USCA-XXSA-0023-0000 G-DG-R-T 2021 Vintage
USCA-XXSA-0024-0000 G-DG-R-T 2022 Vintage
USCA-XXSA-0025-0000 G-OL-TOU 2020 Vintage
USCA-XXSA-0026-0000 G-OL-TOU 2021 Vintage
USCA-XXSA-0027-0000 G-OL-TOU 2022 Vintage
USCA-XXSA-0028-0000 G-PA-T-1-P 2020 Vintage
USCA-XXSA-0029-0000 G-PA-T-1-P 2021 Vintage
USCA-XXSA-0030-0000 G-PA-T-1-P 2022 Vintage
USCA-XXSA-0031-0000 G-PA-T-1-S 2020 Vintage
USCA-XXSA-0032-0000 G-PA-T-1-S 2021 Vintage
USCA-XXSA-0033-0000 G-PA-T-1-S 2022 Vintage
USCA-XXSA-0034-0000 G-PA-T-1-T 2020 Vintage
USCA-XXSA-0035-0000 G-PA-T-1-T 2021 Vintage
USCA-XXSA-0036-0000 G-PA-T-1-T 2022 Vintage
USCA-XXSA-0037-0000 G-TOU-A-P 2020 Vintage
103
48 RIN Rate Permutation
USCA-XXSA-0038-0000 G-TOU-A-P 2021 Vintage
USCA-XXSA-0039-0000 G-TOU-A-P 2022 Vintage
USCA-XXSA-0040-0000 G-TOU-A-S 2020 Vintage
USCA-XXSA-0041-0000 G-TOU-A-S 2021 Vintage
USCA-XXSA-0042-0000 G-TOU-A-S 2022 Vintage
USCA-XXSA-0043-0000 G-TOU-M 2020 Vintage
USCA-XXSA-0044-0000 G-TOU-M 2021 Vintage
USCA-XXSA-0045-0000 G-TOU-M 2022 Vintage
USCA-XXSA-0046-0000 G-TOU-PA-P 2020 Vintage
USCA-XXSA-0047-0000 G-TOU-PA-P 2021 Vintage
USCA-XXSA-0048-0000 G-TOU-PA-P 2022 Vintage
USCA-XXSA-0049-0000 G-TOU-PA-P Over 20kW-2020 Vintage
USCA-XXSA-0050-0000 G-TOU-PA-P Over 20kW-2021 Vintage
USCA-XXSA-0051-0000 G-TOU-PA-P Over 20kW-2022 Vintage
USCA-XXSA-0052-0000 G-TOU-PA-S 2020 Vintage
USCA-XXSA-0053-0000 G-TOU-PA-S 2021 Vintage
USCA-XXSA-0054-0000 G-TOU-PA-S 2022 Vintage
USCA-XXSA-0055-0000 G-TOU-PA-S Over 20kW-2020 Vintage
USCA-XXSA-0056-0000 G-TOU-PA-S Over 20kW-2021 Vintage
USCA-XXSA-0057-0000 G-TOU-PA-S Over 20kW-2022 Vintage
USCA-XXSA-0150-0000 A6-TOU-P 2020 Vintage
USCA-XXSA-0151-0000 A6-TOU-P 2021 Vintage
USCA-XXSA-0152-0000 A6-TOU-P 2022 Vintage
USCA-XXSA-0153-0000 A6-TOU-T 2020 Vintage
USCA-XXSA-0154-0000 A6-TOU-T 2021 Vintage
USCA-XXSA-0155-0000 A6-TOU-T 2022 Vintage
USCA-XXSA-0156-0000 AL-TOU-2-P 2020 Vintage
USCA-XXSA-0157-0000 AL-TOU-2-P 2021 Vintage
USCA-XXSA-0158-0000 AL-TOU-2-P 2022 Vintage
USCA-XXSA-0159-0000 AL-TOU-2-S 2020 Vintage
USCA-XXSA-0160-0000 AL-TOU-2-S 2021 Vintage
USCA-XXSA-0161-0000 AL-TOU-2-S 2022 Vintage
USCA-XXSA-0162-0000 AL-TOU-2-T 2020 Vintage
USCA-XXSA-0163-0000 AL-TOU-2-T 2021 Vintage
USCA-XXSA-0164-0000 AL-TOU-2-T 2022 Vintage
USCA-XXSA-0165-0000 AL-TOU-P 2020 Vintage
USCA-XXSA-0166-0000 AL-TOU-P 2021 Vintage
USCA-XXSA-0167-0000 AL-TOU-P 2022 Vintage
USCA-XXSA-0168-0000 AL-TOU-S 2020 Vintage
USCA-XXSA-0169-0000 AL-TOU-S 2021 Vintage
USCA-XXSA-0170-0000 AL-TOU-S 2022 Vintage
USCA-XXSA-0171-0000 AL-TOU-T 2020 Vintage
104
49 RIN Rate Permutation
USCA-XXSA-0172-0000 AL-TOU-T 2021 Vintage
USCA-XXSA-0173-0000 AL-TOU-T 2022 Vintage
USCA-XXSA-0174-0000 DG-R-P 2020 Vintage
USCA-XXSA-0175-0000 DG-R-P 2021 Vintage
USCA-XXSA-0176-0000 DG-R-P 2022 Vintage
USCA-XXSA-0177-0000 DG-R-S 2020 Vintage
USCA-XXSA-0178-0000 DG-R-S 2021 Vintage
USCA-XXSA-0179-0000 DG-R-S 2022 Vintage
USCA-XXSA-0180-0000 DG-R-T 2020 Vintage
USCA-XXSA-0181-0000 DG-R-T 2021 Vintage
USCA-XXSA-0182-0000 DG-R-T 2022 Vintage
USCA-XXSA-0183-0000 DR-SES 2020 Vintage
USCA-XXSA-0184-0000 DR-SES 2021 Vintage
USCA-XXSA-0185-0000 DR-SES 2022 Vintage
USCA-XXSA-0186-0000 EV-HP-P 2020 Vintage
USCA-XXSA-0187-0000 EV-HP-P 2021 Vintage
USCA-XXSA-0188-0000 EV-HP-P 2022 Vintage
USCA-XXSA-0189-0000 EV-HP-S 2020 Vintage
USCA-XXSA-0190-0000 EV-HP-S 2021 Vintage
USCA-XXSA-0191-0000 EV-HP-S 2022 Vintage
USCA-XXSA-0192-0000 EV-TOU 2020 Vintage
USCA-XXSA-0193-0000 EV-TOU 2021 Vintage
USCA-XXSA-0194-0000 EV-TOU 2022 Vintage
USCA-XXSA-0195-0000 EV-TOU-2 2020 Vintage
USCA-XXSA-0196-0000 EV-TOU-2 2021 Vintage
USCA-XXSA-0197-0000 EV-TOU-2 2022 Vintage
USCA-XXSA-0198-0000 EV-TOU-5 2020 Vintage
USCA-XXSA-0199-0000 EV-TOU-5 2021 Vintage
USCA-XXSA-0200-0000 EV-TOU-5 2022 Vintage
USCA-XXSA-0201-0000 LS-2-AD 2020 Vintage
USCA-XXSA-0202-0000 LS-2-AD 2021 Vintage
USCA-XXSA-0203-0000 LS-2-AD 2022 Vintage
USCA-XXSA-0204-0000 OL-TOU 2020 Vintage
USCA-XXSA-0205-0000 OL-TOU 2021 Vintage
USCA-XXSA-0206-0000 OL-TOU 2022 Vintage
USCA-XXSA-0207-0000 PA-T-1-P 2020 Vintage
USCA-XXSA-0208-0000 PA-T-1-P 2021 Vintage
USCA-XXSA-0209-0000 PA-T-1-P 2022 Vintage
USCA-XXSA-0210-0000 PA-T-1-S 2020 Vintage
USCA-XXSA-0211-0000 PA-T-1-S 2021 Vintage
USCA-XXSA-0212-0000 PA-T-1-S 2022 Vintage
USCA-XXSA-0213-0000 PA-T-1-T 2020 Vintage
105
50 RIN Rate Permutation
USCA-XXSA-0214-0000 PA-T-1-T 2021 Vintage
USCA-XXSA-0215-0000 PA-T-1-T 2022 Vintage
USCA-XXSA-0216-0000 TOU-A-2-P 2020 Vintage
USCA-XXSA-0217-0000 TOU-A-2-P 2021 Vintage
USCA-XXSA-0218-0000 TOU-A-2-P 2022 Vintage
USCA-XXSA-0219-0000 TOU-A-2-S 2020 Vintage
USCA-XXSA-0220-0000 TOU-A-2-S 2021 Vintage
USCA-XXSA-0221-0000 TOU-A-2-S 2022 Vintage
USCA-XXSA-0222-0000 TOU-A-3-P 2020 Vintage
USCA-XXSA-0223-0000 TOU-A-3-P 2021 Vintage
USCA-XXSA-0224-0000 TOU-A-3-P 2022 Vintage
USCA-XXSA-0225-0000 TOU-A-3-S 2020 Vintage
USCA-XXSA-0226-0000 TOU-A-3-S 2021 Vintage
USCA-XXSA-0227-0000 TOU-A-3-S 2022 Vintage
USCA-XXSA-0228-0000 TOU-DR 2020 Vintage
USCA-XXSA-0229-0000 TOU-DR 2021 Vintage
USCA-XXSA-0230-0000 TOU-DR 2022 Vintage
USCA-XXSA-0231-0000 TOU-DR-1 2020 Vintage
USCA-XXSA-0232-0000 TOU-DR-1 2021 Vintage
USCA-XXSA-0233-0000 TOU-DR-1 2022 Vintage
USCA-XXSA-0234-0000 TOU-ELEC 2020 Vintage
USCA-XXSA-0235-0000 TOU-ELEC 2021 Vintage
USCA-XXSA-0236-0000 TOU-ELEC 2022 Vintage
USCA-XXSA-0237-0000 TOU-M 2020 Vintage
USCA-XXSA-0238-0000 TOU-M 2021 Vintage
USCA-XXSA-0239-0000 TOU-M 2022 Vintage
USCA-XXSA-0240-0000 TOU-PA-2-P 2020 Vintage
USCA-XXSA-0241-0000 TOU-PA-2-P 2021 Vintage
USCA-XXSA-0242-0000 TOU-PA-2-P 2022 Vintage
USCA-XXSA-0243-0000 TOU-PA-2-S 2020 Vintage
USCA-XXSA-0244-0000 TOU-PA-2-S 2021 Vintage
USCA-XXSA-0245-0000 TOU-PA-2-S 2022 Vintage
USCA-XXSA-0246-0000 TOU-PA-3-P 2020 Vintage
USCA-XXSA-0247-0000 TOU-PA-3-P 2021 Vintage
USCA-XXSA-0248-0000 TOU-PA-3-P 2022 Vintage
USCA-XXSA-0249-0000 TOU-PA-3-P Over 20kW-2020 Vintage
USCA-XXSA-0250-0000 TOU-PA-3-P Over 20kW-2021 Vintage
USCA-XXSA-0251-0000 TOU-PA-3-P Over 20kW-2022 Vintage
USCA-XXSA-0252-0000 TOU-PA-3-S 2020 Vintage
USCA-XXSA-0253-0000 TOU-PA-3-S 2021 Vintage
USCA-XXSA-0254-0000 TOU-PA-3-S 2022 Vintage
USCA-XXSA-0255-0000 TOU-PA-3-S Over 20kW-2020 Vintage
106
51 RIN Rate Permutation
USCA-XXSA-0256-0000 TOU-PA-3-S Over 20kW-2021 Vintage
USCA-XXSA-0257-0000 TOU-PA-3-S Over 20kW-2022 Vintage
USCA-XXSA-0264-0000 TOU-A-P 2020 Vintage
USCA-XXSA-0265-0000 TOU-A-P 2021 Vintage
USCA-XXSA-0266-0000 TOU-A-P 2022 Vintage
USCA-XXSA-0268-0000 TOU-A-S 2020 Vintage
USCA-XXSA-0269-0000 TOU-A-S 2021 Vintage
USCA-XXSA-0270-0000 TOU-A-S 2022 Vintage
USCA-XXSA-0272-0000 TOU-DR-2 2020 Vintage
USCA-XXSA-0273-0000 TOU-DR-2 2021 Vintage
USCA-XXSA-0274-0000 TOU-PA-P 2020 Vintage
USCA-XXSA-0275-0000 TOU-PA-P 2021 Vintage
USCA-XXSA-0276-0000 TOU-PA-P 2022 Vintage
USCA-XXSA-0277-0000 TOU-DR-2 2022 Vintage
USCA-XXSA-0278-0000 TOU-PA-S 2020 Vintage
USCA-XXSA-0279-0000 TOU-PA-S 2021 Vintage
USCA-XXSA-0280-0000 TOU-PA-S 2022 Vintage
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SAN DIEGO COMMUNITY POWER
Staff Report – Item 11
______________________________________________________________________ TO: Board of Directors
FROM: Jack Clark, Chief Operating Officer
Jen Lebron, Senior Director of Public Affairs
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Authorize Amendment No. 1 to Professional Services Agreement with JSR Strategies LLC to Increase Contract Amount to $650,000 for Marketing, Communications, Website Design, and Maintenance Services
DATE: August 28, 2025
______________________________________________________________________ RECOMMENDATION:
Authorize the Chief Executive Officer to execute Amendment No. 1 to the Professional Services Agreement with JSR Strategies LLC for Marketing, Communications, Website Design, and Website Maintenance services, increasing the not-to-exceed amount by $167,545 for a total contract value not to exceed $650,000.
BACKGROUND:
San Diego Community Power (Community Power) has continuous needs to educate and inform its customers about its services and programs. While it maintains a small in-house marketing and communications team, additional expertise and capacity from a third-party vendor is necessary to reach its nearly one million customers.
On May 23, 2024, the Community Power Board of Directors approved a professional services agreement with JSR Strategies for Marketing, Communications, Website Design, and Website Maintenance services in a not-to-exceed (NTE) amount of $482,455 over the initial two-year contract term, with options for two, one-year extensions at a NTE of $200,000 per year. JSR Strategies was selected through a competitive procurement process based on its proven experience in branding, website development and campaign management for other Community Choice Aggregators, as well as its ability to effectively support Community Power’s ongoing outreach, communications and customer engagement.
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ANALYSIS AND DISCUSSION:
Since execution of the contract, Community Power programmatic design and outreach needs have expanded. Staff is seeking to increase the initial contract amount to include the website redesign services and some marketing and outreach work to include the expansion of our program offerings, such as Solar Battery Savings, which is in the process of an expanded relaunch from the original pilot program, and the San Diego Regional Energy Network (SDREN). Note that a separate procurement process was released and a contract is anticipated for marketing and outreach work that is SDREN specific.
To ensure sufficient resources remain available for the completion of the website redesign, implementation of the brand refresh, and general marketing and communications activities aimed at increasing public awareness of Community Power benefits and programs, staff recommend increasing the contract NTE by $167,545, for a revised two-year total of $650,000. The optional years would retain NTE amounts of $200,000 each.
Approval of this amendment will ensure Community Power has the marketing and communications infrastructure needed to achieve its goals, including the launching of several programs, and effectively engage customers and stakeholders.
FISCAL IMPACT:
Approval of Amendment No. 1 will increase the contract not-to-exceed amount for JSR Strategies from $482,455 to $650,000 over the initial two-year term. The additional $167,545 will be used to complete the Community Power brand refresh, website redesign and other priority marketing and communications efforts, including expanded Solar Battery Savings program outreach. Sufficient funding for the amended contract is included in the FY 2025–2026 operating budget.
STRATEGIC PLAN:
This activity supports the strategic plan goal of trusted brand development that supports engagement, participation and program success.
ATTACHMENTS:
A: San Diego Community Power Professional Services Agreement with JSR Strategies LLC
B: Amendment No. 1 to Professional Services Agreement Between San Diego Community Power and JSR Strategies, LLC
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ITEM 11
ATTACHMENT A
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SAN DIEGO COMMUNITY POWER
PROFESSIONAL SERVICES AGREEMENT
This Professional Services Agreement ("Agreement") is made and entered into this 11th day of� 2024, by and between SAN DIEGO COMMUNITY POWER, a California joint powers agency ("SDCP") and JSR Strategies LLC, a limited liability company ("Consultant" of "JSR"). SDCP and Consultant are sometimes individually referred to as "Party" and collectively as "Parties."
RECITALS
A. Consultant desires to perform and assume responsibility for the provision of certain professional services required by SDCP on the terms and conditions set forth in this Agreement.
Consultant represents that it is experienced in Marketing, Communication, Website Design, & Maintenance services for SDCP customers, is licensed in the State of California, and is familiar with the plans of SDCP.
B. SDCP desires to engage Consultant to render such professional services for Marketing, Communication, Website Design, & Maintenance services for its customers. ("Project") as set forth in this Agreement.
1. Scope of Services and Term.
AGREEMENT
General Scope of Services. Consultant promises and agrees to furnish to SDCP all labor, materials, tools, equipment, services, and incidental and customary work necessary to fully and adequately deliver Marketing, Communication, Website Design, & Maintenance services necessary for the Project ("Services"). The Services are more particularly described in Exhibit A attached hereto, and which are stated in the proposal to SDCP. All Services shall be subject to, and performed in accordance with, this Agreement, the exhibits attached hereto, and all applicable local, state, and federal laws, rules and regulations.
1.1 Term. The term of this Agreement shall be from May 23, 2024 to May 22, 2026, unless earlier terminated as provided herein. Consultant shall complete the Services within the term of this Agreement and shall meet any other established schedules and deadlines. SDCP reserves the right to contract for up to two additional one-year extensions for these services.
2. Responsibilities of Consultant.
2.1 Control and Payment of Subordinates: Independent Contractor. The Services shall be performed by Consultant or under its supervision. Consultant will determine the means, methods and details of performing the Services subject to the requirements of this Agreement.
SDCP retains Consultant on an independent contractor basis and not as an employee. Consultant retains the right to perform similar or different services for others during the term of this Agreement. Any additional personnel performing the Services under this Agreement on behalf of Consultant shall also not be employees of SDCP and shall at all times be under Consultant's 111
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ITEM 11
ATTACHMENT B
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AMENDMENT NO. 1
TO PROFESSIONAL SERVICES AGREEMENT BETWEEN
SAN DIEGO COMMUNITY POWER AND JSR STRATEGIES, LLC
THIS AMENDMENT NO. 1 to the Professional Services Agreement between San Diego Community Power and JSR Strategies, LLC (this “Amendment No. 1”) is made and entered into this _____ day of _______________, 2025 (“Amendment Effective Date”), by and between SAN DIEGO COMMUNITY POWER, a California joint powers agency (“Community Power”) and JSR Strategies LLC, a limited liability company (“Consultant” or “JSR”). Community Power and Consultant are sometimes individually referred to herein as the “Party” and collectively as the “Parties.”
RECITALS
A. WHEREAS, the Parties entered into that certain Professional Services Agreement between Community Power and JSR dated June 11, 2024 (the “Agreement”); and, B. WHEREAS, pursuant to the Agreement, Consultant provides Marketing, Communication, Website Design, & Maintenance services for Community Power; and C. WHEREAS, the parties desire to amend the Agreement to increase the Not-to-Exceed amount of the Agreement by $167,545 in consideration of expanded Marketing, Communication, Website Design, & Maintenance services to meet Community Power needs for the launching of several customer programs.
NOW, THEREFORE, IT IS AGREED BY AND BETWEEN THE PARTIES AS FOLLOWS:
1. Recitals. The Recitals set forth above are true and correct and are incorporated into the body of this Amendment as though expressly set forth herein.
2. Amendment of Section 3.1 (Compensation). Section 3.1 of the Agreement is amended to increase the total compensation of the Agreement by $167,545 for a new total Not-to-Exceed (“NTE”) amount of $650,000 (up from $482,455).
3. Effect of Amendment. Except as expressly set forth in this Amendment No. 1, all other sections, provisions, exhibits and commitments of the Agreement remain unchanged and in full force and effect.
4. Counterparts. This Amendment No. 1 may be executed in one or more counterparts, including facsimile counterparts, each of which shall, for all purposes, be deemed an original and all such counterparts, taken together, shall constitute one and the same instrument.
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IN WITNESS WHEREOF, the Parties have executed this Amendment No. 1 to the Agreement between Community Power and Consultant, as of the Amendment Effective Date set forth above.
SAN DIEGO COMMUNITY POWER
_____________________________________
Karin Burns
Chief Executive Officer
JSR STRATEGIES, LLC
_____________________________________
Jessica Rhodes, CEO
Principal & CEO
ATTEST:
_________________________________
Maricela Hernandez, Clerk of the Board
Community Power
APPROVED AS TO FORM:
_________________________________
Veera Tyagi, General Counsel
Community Power
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SAN DIEGO COMMUNITY POWER
Staff Report – Item 12
______________________________________________________________________ TO: Board of Directors
FROM: Dr. Eric W. Washington, Chief Financial Officer
Jeb Spengler, Senior Strategic Finance Manager
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Adoption of Resolution No. 2025-08, Approving a Second Revision to San Diego Community Power (Community Power) Investment Policy DATE: August 28, 2025
______________________________________________________________________ RECOMMENDATION:
Adoption of Resolution No. 2025-08, approving a second revision to Community Power’s Investment Policy.
BACKGROUND:
On October 1, 2019, the Founding Members of San Diego Community Power (Community Power) adopted the Joint Powers Agreement (JPA) which was amended and restated on December 16, 2021.
Section 3.2.12 of the JPA specifies that the Community Power Board of Directors (Board) may at its discretion adopt rules, regulations, policies, bylaws and procedures governing the operation of Community Power.
Further, Section 4.5.5 of the JPA states that one of the general purposes of the Board is to set policy.
Section 5.10.2(C) of the JPA states that one of the primary purposes of the Finance and Risk Management Committee (FRMC) is to review and recommend to the Board financial policies and procedures to ensure equitable contributions by Parties consistent with a recommendation for Board approval of the Investment Policy herein. Further, this section states the FRMC may have such other responsibilities as may be approved by the Board, including but not limited to advising the Chief Executive Officer on fiscal and risk management policies and procedures, rules and regulations governing investment of surplus funds, audits to achieve best practices in corporate governance and selection and designation of financial institutions for deposit of Community Power funds, and credit/depository matters.
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On May 25, 2023, the Board approved the Community Power Investment Policy. The policy requires an annual review. In addition, the policy allowed Community Power to engage the services of an investment adviser, who is registered under the Investment Advisers Act of 1940, to assist in the management of Community Power’s investment portfolio in a manner consistent with Community Power’s objectives.
On February 15, 2024, the Community Power Board approved a professional services agreement with Chandler Asset Management. Subsequently, Community Power initiated a transition process that involved a review of Community Power’s Investment Policy by Chandler Asset Management, which identified possible revisions.
On June 27, 2024, the Community Power Board approved Resolution 2024-03 Adopting the First Revision to the Community Power Investment Policy following recommendations made by Chandler Asset Management to update language to better serve Community Power’s investment objectives.
ANALYSIS AND DISCUSSION:
Chandler Asset Management made recommendations for the following revisions to the Community Power Investment Policy to update language to better serve Community Power’s investment objectives.
Changes to Acceptable Investment Type has been expanded to include Local Government Investment Pools/JPAs as an Authorized Investment. This change expands the pool of investment options for Community Power’s large, liquid reserve balances outside of bank deposit-type accounts and Local Agency Investment Funds (LAIF) Further updates to Acceptable Investment Type clarify the maximum percentage of the investment portfolio that may be invested in any specific investment product. Specifically, a note has been added to Placement Service Deposits that no more than 30% of the total portfolio may be invested in a combination of qualifying placement service deposits. Note that under a provision sunsetting January 1st, 2031, the maximum investment allowed is 50% of the total portfolio.
The glossary has been updated to ensure all terms are clearly defined.
All changes or updates to the Community Power Investment Policy will require Board approval.
FISCAL IMPACT:
N/A
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COMMITTEE REVIEW:
This item was presented to the Finance and Risk Management Committee at the August 21 meeting. The Committee members recommended Board adoption of Resolution No. 2025-08, approving a second revision to the Community Power’s Investment Policy.
STRATEGIC PLAN:
This activity supports the strategic plan goal of addressing affordability by increasing investment earning opportunities on available reserve balances. In addition, this activity supports the development of a rate stabilization reserve to mitigate power cost fluctuations and economic downturns.
ATTACHMENTS:
Attachment A: Resolution No. 2025-08, approving a second revision to the Community Power’s Investment Policy
Exhibit A: Community Power Investment Policy Second Revision Exhibit B: Redline Version of Community Power Investment Policy Second Revision
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ITEM 12
ATTACHMENT A
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RESOLUTION NO. 2025-08
A RESOLUTION OF THE BOARD OF DIRECTORS OF
SAN DIEGO COMMUNITY POWER, ADOPTING THE SECOND REVISION TO THE SAN DIEGO COMMUNITY POWER INVESTMENT POLICY.
A. San Diego Community Power (Community Power) is a joint powers authority formed pursuant to the Joint Exercise of Powers Act, Cal. Gov. Code § 6500 et seq., California Public Utilities Code § 366.2, and a Joint Powers Agreement effective on October 1, 2019, and amended on December 16, 2021 (“JPA Agreement”).
B. The JPA Agreement provides that the Community Power Board of Directors (“Board”) may at its discretion adopt rules, regulations, policies, bylaws, and procedures governing the operation of Community Power.
C. The Board has determined that an Investment Policy that comports with the requirements of California Government Code Sections 53600-53608 is in the best interests of Community Power to ensure assets are protected.
D. The purpose of the Investment Policy is to identify (1) the objectives and priorities for Community Power investments; (2) the types of investments that are permitted and prohibited; and (3) the controls Community Power will implement to ensure assets are protected.
E. The Community Power Board proposes to adopt the Second Revision to the Community Power Investment Policy, attached hereto as Exhibit A.
NOW, THEREFORE, BE IT RESOLVED by the Board of Directors of San Diego Community Power as follows:
Section 1. The Board of Directors hereby adopts the Second Revision to the Community Power Investment Policy.
Section 2. This resolution shall take effect immediately upon its adoption. 144
PASSED, APPROVED AND ADOPTED at a regular meeting of the Board of Directors of San Diego Community Power held on August 28, 2025, by the following vote:
AYES:
NOES:
ABSTAIN:
ABSENT:
__________________________________
, Chair
Board of Directors
San Diego Community Power
ATTEST: APPROVED AS TO FORM:
__________________________________ _______________________________ Maricela Hernandez, MMC, CPMC Veera Tyagi, General Counsel Secretary, Board of Directors San Diego Community Power San Diego Community Power
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ITEM 12
EXHIBIT A
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BOARD POLICY
Policy Investment Original Adoption Date May 25, 2023
Approval Date August 28, 2025 Resolution No. 2025-08
PURPOSE AND SCOPE:
The San Diego Community Power (“Community Power”) Investment Policy (“Policy”) establishes investment guidelines for protecting Community Power’s cash reserves, deposits, and investments (collectively, “Funds”) while producing a reasonable rate of return on investments.
This Policy articulates: (1) the objectives and priorities for Community Power investments; (2) the types of investments that are permitted and prohibited; and (3) the controls Community Power will implement to ensure investments are protected.
This Policy is adopted pursuant to California Government Code Section (“Section”) 53600-53608 and must be adopted or amended by resolution. The Community Power Board of Directors (“Board”) is not required to adopt a formal Investment Policy by statute, however, it is in the best practice to ensure agency assets are protected.
BACKGROUND:
On October 1, 2019, the founding members of Community Power adopted the Joint Powers Agreement (JPA) which was amended and restated on December 16, 2021.
Section 3.2.12 of the JPA specifies that the Board may at its discretion adopt rules, regulations, policies, bylaws and procedures governing the operation of Community Power.
Further, Section 4.5.5 of the JPA states that one of the general purposes of the Board is to set policy.
Section 5.10.2(C) of the JPA states that one of the primary purposes of the Financial and Risk Management Committee (FRMC) is to review and recommend to the Board financial policies and procedures to ensure equitable contributions by parties consistent with a recommendation for Board approval of the Policy herein. Further, this section states the FRMC may have such other responsibilities as may be approved by the Board, including but not limited to, advising the Chief Executive Officer on fiscal and risk management policies and procedures, rules and regulations governing investment of surplus funds, audits to achieve best practices in corporate governance, selection and designation of financial institutions for deposit of Community Power funds, and credit/depository matters.
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INVESTMENT OBJECTIVES:
To the extent possible, investments will align with Community Power’s mission, vision, value, and goals. When managing Funds, Community Power’s primary objectives shall be to (1) safeguard the principal of the Funds, (2) meet the liquidity needs of Community Power, (3) achieve a return on Funds invested, and (4) exercise a high standard of care on Funds within Community Power’s control.
1) Safety: Safety of principal is the foremost objective of cash and investment management activities. The investment of Funds shall be undertaken in a manner that seeks to ensure the preservation of principal.
2) Liquidity: The Funds of Community Power shall remain sufficiently liquid to meet all operating needs that may be reasonably anticipated. Since all possible cash demands cannot be anticipated, the investment of Funds in deposits or instruments that are available on demand is recommended.
3) Return on Investments: Community Power’s deposit and investment portfolio shall be designed with the objective of attaining a market rate of return throughout the economic cycle while considering investment risk and liquidity constraints. The return on deposits and investments is of secondary importance compared to the safety and liquidity objectives described in Investment Objectives, Section (1) and Investment Objectives, Section (2), above.
4) Standard of Care: Community Power will manage the Funds in accordance with the “Prudent Investor Standard” pursuant to California Government Code Section 53600.31 as follows:
“All governing bodies of local agencies or persons authorized to make investment decisions on behalf of those local agencies investing public funds are trustees and therefore fiduciaries subject to the prudent investor standard. When investing, reinvesting, purchasing, acquiring, exchanging, selling or managing public funds, a trustee shall act with care, skill, prudence and diligence under the circumstances then prevailing, that a prudent person acting in a like capacity and familiarity with those matters would use in the conduct of funds of a like character and with like aims, to safeguard the principal and maintain the liquidity needs of the agency. Within the limitations of this section and considering individual investments as part of an overall strategy, investments may be acquired as authorized by law.”
1 All further statutory references are to the California Government Code unless otherwise stated. 148
DELEGATION OF AUTHORITY:
Pursuant to Section 53607, the Board has the authority to delegate the responsibility to manage Community Power’s funds to the Treasurer. The Treasurer has authority to appoint Deputy Treasurer(s) as the Treasurer deems necessary to carry out the duties in accordance with the Policy.
Community Power may engage the services from one or more external investment advisers, who are registered under the Investment Advisers Act of 1940, to assist in the management of Community Power’s investment portfolio in a manner consistent with Community Power’s Policy.
External investment advisers may be granted discretion to purchase and sell investment securities in accordance with the investment objective set forth in this Policy.
Scope
This Policy applies to all funds and investment under the direct authority of Community Power.
This Policy does not apply to the investment of bond proceeds, which would be governed by any applicable bond documents, and any other funds specifically exempted by the Board.
Acceptable Investment Types: To the extent possible, investments will align with Community Power’s mission, vision, value, and goals.
1. Deposits at Bank(s): Funds may be invested in non-interest-bearing depository accounts to meet Community Power’s operating and collateral needs and grant requirements.
Funds not needed for these purposes may be invested in interest-bearing depository accounts or Federal Deposit Insurance Corporation (FDIC) insured certificates of deposit with maturities not to exceed five (5) years. Banks eligible to receive deposits will be federally or state chartered and will conform to Section 53635.2 which requires that banks “have received an overall rating of not less than ‘satisfactory’ in its most recent evaluation by the appropriate federal financial supervisory agency of its record of meeting the credit needs of California's communities, including low- and moderate-income neighborhoods, pursuant to Section 2906 of Title 12 of the United States Code.” As per Section 53652, banks must collateralize the deposits of public agencies in an amount equal to no less than 110% of as currently stated in the value of the deposits. The Treasurer will monitor the credit quality of eligible banks holding Community Power deposits that exceed FDIC insurance limits to ensure the safety of Community Power deposits. There are no limits on the dollar amount or percentage that Community Power may invest in collateralized bank deposits.
2. Local Agency Investment Fund (LAIF): Funds may be invested in the Local Agency Investment Fund established by the California State Treasurer for the benefit of local agencies. LAIF’s investments in instruments prohibited by or not specified in Community Power’s policy do not exclude the investment in LAIF itself from Community Power’s list 149
of allowable investments, provided LAIF’s reports allow the Treasurer to adequately judge the risk inherent in LAIF’s portfolio.
3. US Treasury Obligations: Funds may be invested in United States Treasury obligations with a term to maturity not exceeding five (5) years and subject to the limitations set forth in Sections 53601 et seq. and 53635 et seq.
4. Federal Agency Securities: Funds may be invested in Federal Agency Securities or Government-Sponsored Enterprise (GSE) obligations with a term to maturity not exceeding five (5) years and subject to the limitations set forth in Sections 53601 et seq. and 53635 et seq. No more than 20% of the total portfolio may be invested in callable agency securities and no more than 30% of the total portfolio may be invested in any single Agency/ GSE issuer.
5. Bankers’ Acceptances: Funds may be invested in Banker’s Acceptances provided that they are issued by institutions which have short-term debt obligations rated “A-1” or its equivalent or better by at least one Nationally Recognized Statistical Rating Organization (NRSRO). Not more than 40% of the portfolio may be invested in Bankers’ Acceptances, and no more than 5% of the portfolio may be invested in any single issuer. The maximum maturity shall not exceed 180 days.
6. Negotiable Certificates of Deposit: Funds may be invested in negotiable certificates of deposit in accordance with the requirements of Section 53601 and 53601.8, and subject to the following limitations:
A. Issued by an entity as defined in Section 53601(i); and B. No more than 30% of the total portfolio shall be invested in certificates of deposit, no more than 5% of the total portfolio may be invested in any single issuer, and the maximum maturity does not exceed 5 years.
7. Placement Service Deposits: Funds may be invested in deposits placed with a private sector entity that assists in the placement of deposits with eligible financial institutions located in the United States (Section 53601.8). No more than 30% of the total portfolio may be invested in a combination of qualifying placement service deposits. The full amount of principal and the interest that may be accrued during the maximum term of each deposit shall at all times be insured by federal deposit insurance. Under a provision sunsetting on January 1, 2031, no more than 50% of the portfolio may be invested in deposits through a placement service. The maximum maturity shall not exceed five (5) years.
8. Money Market Funds: Funds may be invested in money market funds pursuant to Section 53601(l)(2) and subject to Section 53601(l)(4). No more than 20% of the portfolio 150
may be invested in the shares of any one Money Market Fund. No more than 20% of the total portfolio may be invested in these securities.
9. Commercial Paper: Funds may be invested in commercial paper of “prime” quality of the highest ranking or of the highest letter and number rating as provided for by an NRSRO.
The entity that issues the commercial paper must meet all of the following conditions in either paragraph A or paragraph B below:
A. The entity meets the following criteria: (i) is organized and operating in the United States as a general corporation, (ii) has total assets in excess of five hundred million dollars ($500,000,000), and (iii) has debt other than commercial paper, if any, that is rated in a rating category of “A” or its equivalent or higher by an NRSRO.
B. The entity meets the following criteria: (i) is organized within the United States as a special purpose corporation, trust, or limited liability company, (ii) has program-wide credit enhancements including, but not limited to, over collateralization, letters of credit, or surety bond, and (iii) has commercial paper that is rated “A-1” or higher, or the equivalent, by an NRSRO.
• No more than 10% of the outstanding commercial paper of any single issuer. • No more than 25% of Community Power’s investment assets under management may be invested in Commercial Paper. Under a provision sunsetting on January 1, 2026, no more than 40% of the total portfolio may be invested in Commercial Paper if Community Power’s investment assets under management are greater than $100,000,000.
• No more than 5% of the total portfolio may be invested in any single issuer. The maximum maturity does not exceed 270 days.
10. Medium Term Notes (MTN): The issuer is a corporation organized and operating within the United States or by depository institutions licensed by the United States or any state and operating within the United States (Section 53601 et seq). The securities are rated in a rating category of “A” or its equivalent or better by at least one NRSRO. No more than 30% of the total portfolio may be invested in MTNs, no more than 5% of the total portfolio may be invested in any single issuer and the maximum maturity does not exceed five (5) years.
11. Pass Thru Securities: Asset-Backed, Mortgage-Backed, Mortgage Pass-Through Securities, and Collateralized Mortgage Obligations (Section 53601 et seq) from issuers not defined in sections 3 and 4 of the Acceptable Investment Types section of this Policy, provided that, the securities are rated in a rating category of “AA” or its equivalent or better by an NRSRO, no more than 20% of the total portfolio may be invested in these securities, no more than 5% of the total portfolio may be invested in any single Asset-Backed or 151
Commercial Mortgage security issuer and the maximum maturity does not exceed five (5) years.
12. Municipal Securities: These include obligations of Community Power, the State of California and any local agency within the State of California (Section 53601). provided that, the securities are rated in a rating category of “A” or its equivalent or better by at least one NRSRO, no more than 5% of the total portfolio may be invested in any single issuer, no more than 30% of the total portfolio may be in Municipal Securities and the maximum maturity does not exceed five (5) years.
13. Municipal Securities: Registered treasury notes or bonds of any of the other 49 states in addition to California, including bonds payable solely out of the revenues from a revenue-producing property owned, controlled, or operated by a state or by a department, board, agency, or authority of any of the other 49 states, in addition to California (Section 53601). The securities are rated in a rating category of “A” or its equivalent or better by at least one NRSRO, no more than 5% of the total portfolio may be invested in any single issuer, no more than 30% of the total portfolio may be in Municipal Securities and the maximum maturity does not exceed five (5) years.
14.Supranationals: Issues are US dollar denominated senior unsecured unsubordinated obligations issued or unconditionally guaranteed by the International Bank for Reconstruction and Development, International Finance Corporation, or Inter-American Development Bank. (Section 53601). The securities are rated in a rating category of “AA” or its equivalent or better by an NRSRO, no more than 30% of the total portfolio may be invested in these securities, no more than 10% of the total portfolio may be invested in any single issue and the maximum maturity does not exceed five (5) years.
15. Local Government Investment Pools (LGIPs): Shares of beneficial interest issued by a Joint Powers Authority (JPA) organized pursuant to California Government Code Section 6509.7 that invest in the securities and obligations authorized in subdivisions (a) to (r), inclusive. Each share shall represent an equal proportional interest in the underlying pool of securities owned by the JPA. To be eligible under this section, the JPA issuing the shares will have retained an investment adviser who is registered with the SEC (or exempt from registration), has assets under management in excess of five hundred million dollars ($500,000,000), and has not less than five years of experience investing in the securities and obligations authorized in subdivisions (a) to (q) of Government Code Section 53601, inclusive.
PROHIBITED INVESTMENT TYPES:
Pursuant to Section 53601.6, Community Power shall not invest Funds in any security that could result in a zero-interest accrual, or less, if held to maturity. These prohibited investments include, but are not limited to, inverse floaters, range notes, or mortgage-derived interest-only strips. The purchase of foreign currency denominated securities is prohibited. The purchase of Crypto Asset 152
Securities is prohibited. The purchase of a security with a forward settlement date exceeding 45 days from the time of the investment is prohibited. Trading securities for the sole purpose of speculating on the future direction of interest rates is prohibited. Purchasing or selling securities on margin is prohibited. The use of reverse repurchase agreements, securities lending or any other form of borrowing or leverage is prohibited. Community Power is prohibited from investing in any company or organization whose business do not align with Community Power’s mission, vision, value, and goals.
INVESTMENT PORTFOLIO MANAGEMENT:
The term to maturity of any Funds invested shall not exceed five (5) years pursuant to Section 53601. The Treasurer will allocate Funds among authorized investments consistent with the objectives and standards of care outlined in this Policy.
COLLATERALIZATION:
Certificates of Deposit (CDs). Community Power shall require any commercial bank or savings and loan association to deposit eligible securities with an agency of a depository approved by the State Banking Department to secure any uninsured portion of a Non-Negotiable Certificate of Deposit. The value of eligible securities as defined pursuant to California Government Code, Section 53651, pledged against a Certificate of Deposit shall be equal to 150% of the face value of the CD if the securities are classified as mortgages and 110% of the face value of the CD for all other classes of security.
Bank Deposits. A bank or financial institution may pledge securities or other deposits for the purpose of securing repayment of deposited funds. Community Power shall require any bank or financial institution to comply with the collateralization criteria defined in California Government Code, Section 53651.
RISK MANAGEMENT AND DIVERSIFICATION:
Community Power’s investment portfolio will be diversified to avoid incurring unreasonable and avoidable risks associated with concentrating investments in specific security types, maturity segment, or in individual financial institutions. No more than 5% of the investment portfolio shall be in securities of any one issuer except for U.S. Treasuries, U.S. Government Agency issues, Supranationals and investment pools such as LAIF and money market funds.
A. Credit Risk: Credit risk, defined as the risk of loss due to failure of the insurer of a security, shall be mitigated by investing in those securities with an “A” or above rating and approved in this Policy and by diversifying the investment portfolio so that the failure of any one issuer would not unduly harm Community Power’s cash flow. 153
B. Market Risk: Market risk or interest rate risk, defined as the risk of market value fluctuations due to overall changes in the general level of interest rates, shall be mitigated by implementing a short term and long-term investment strategies. It is explicitly recognized herein, however, that in a diversified portfolio, occasional measured losses are inevitable and must be considered within the context of overall investment return.
The duration of the portfolio will generally be approximately equal to the duration (typically, plus or minus 20%) of a Market Benchmark, an index selected by Community Power based on Community Power’s investment objectives, constraints and risk tolerances.
C. Credit Rating: This Policy sets forth minimum credit ratings for each type of security.
These credit ratings apply to the initial purchase of a security and do not automatically force the sale of a security if the credit ratings of the security fall below the policy limits.
Minimum credit ratings:
1. For securities with maturities of 13 months or less, the rating must be in the highest short-term rating category (without regard to qualification of such rating symbol such as “+” or “- “) by at least one NRSRO.
2. For securities with maturities greater than 13 months, the rating must be “A” or higher by at least one NRSRO.
The monitoring of credit ratings consists of the following procedures:
1. When a credit rating downgrade occurs which results in a rating below the minimum credit requirement, Community Power’s Finance Department or external investment adviser will analyze and evaluate the credit rating to determine whether to hold or sell the investment.
2. In the event a security in the Fund receives a credit rating downgrade which results in a rating below the minimum credit rating requirement, Community Power’s Treasurer will report the rating change to the Finance and Risk Management Committee in the monthly public report. In the same manner, the Finance and Risk Management Committee will be informed on the decision to hold or sell a downgraded security.
3. The Investment Officials or authorized employees involved in the investment process and external investment advisers shall meet at least quarterly to review and update the approved list of securities and establish credit criteria for each category of security.
To ensure that the Fund maintains the highest overall credit rating with the contracted NRSRO, the asset allocation and portfolio holdings will be provided to the contracted NRSRO on a monthly basis.
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BROKERS:
The Treasurer shall endeavor to complete investment transactions with institutions eligible to transact investment business with Community Power, in accordance with Section 53601.5, including:
A. Institutions licensed by the state as a broker-dealer.
B. Institutions that are members of a federally regulated securities exchange.
C. Primary government dealers as designated by the Federal Reserve Bank and non-primary government dealers.
D. Nationally or state-chartered banks.
E. The Federal Reserve Bank.
F. Direct issuers of securities eligible for purchase.
Broker/dealers shall be approved by the Chief Executive Officer upon recommendation by the Treasurer. Selection of broker/dealers shall be based upon the following criteria: the reputation and financial strength of the company or financial institution, the reputation and expertise of the individuals employed, and pursuant to the requirements of Section 53601.5. The Treasurer shall require any selected broker, brokerage firm, dealer, or securities firm to affirm that it has not, within any 48-consecutive month period, made a political contribution to any member of the Board, or any candidate who may join the Board in an amount exceeding the limitations contained in Rule G-37 of the Municipal Securities Rulemaking Board, the Political Reform Act, including section 84308, or any applicable Community Power Policy, as amended from time to time. The selected broker or dealers shall be provided with and acknowledge receipt of this Policy.
LOSSES:
Losses are acceptable on a sale before maturity and may be taken if required to meet the liquidity needs of Community Power or if the reinvestment proceeds will earn an income flow with a present value higher than the present value of the income flow that would have been generated by the original investment, considering any investment loss or foregoing interest on the original investment.
DELIVERY AND SAFEKEEPING:
The delivery and safekeeping of all securities shall be made through a third-party custodian when practical and cost effective as determined by the Treasurer, or a duly appointed Deputy Treasurer, and in accordance with Section 53608.
The Treasurer shall review all transaction confirmations for conformity with the original transaction and monitor for excessive trading.
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ETHICS AND CONFLICT OF INTEREST:
The Investment Officials or authorized employees involved in the investment process, shall act as custodians of the public trust and will refrain from personal business activities that could conflict with proper execution of the investment program, or which could impair their ability to make impartial decisions. Investment Officials and any external investment advisers acknowledge that all direct Community Power investments are subject to public review and evaluation.
Community Power Investment Officials involved in the investment process shall refrain from personal business activity that could create a conflict of interest or the appearance of a conflict with proper execution of the investment program, or which could impair their ability to make impartial investment decisions.
Community Power Investment Officials shall disclose to General Counsel or designee (i) any material interests in financial institutions with which they conduct business, and (ii) disclose any personal investments with a direct, indirect or beneficial interest totaling $2,000 or more.
Investment Officials shall refrain from undertaking any personal investment transactions with the same individual from the external investment adviser with whom business is conducted on behalf of Community Power.
Investment Officials, pursuant with all applicable laws, shall not accept honoraria, gifts, and gratuities from advisers, brokers, dealers, bankers, or other entity with whom Community Power conducts business.
Any external investment adviser contracted by Community Power will comply with Municipal Securities Rulemaking Board Rule G-37 and shall follow the Investment Adviser Fiduciary Standard established by the U.S. Securities and Exchange Commission.
INTERNAL CONTROLS:
The Treasurer is responsible for establishing and maintaining an internal control structure designed to ensure that the assets of the entity are protected from loss, theft or misuse. The internal control structure shall be designed to provide reasonable assurance that these objectives are met.
Accordingly, the Treasurer shall establish and maintain internal controls that shall address the following points:
A. Control of Collusion: Collusion is a situation where two or more employees are working in conjunction to defraud their employer. To achieve a segregation of duties, individuals who authorize investment transactions shall not also record or reconcile said transactions.
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B. Clear Delegation of Authority to Subordinate Staff Members: Subordinate staff members must have a clear understanding of their authority and responsibilities to avoid improper actions. Clear delegation of authority also preserves the internal control structure that is contingent on the various staff positions and their respective responsibilities.
C. Delivery-Versus-Payment (DVP): All investment transactions shall be conducted on a delivery-versus-payment basis.
D. Safekeeping and Custody: Securities purchased from any bank or dealer, including appropriate collateral (as defined by California Government Code), that are not insured by the FDIC, shall be placed with an independent third party for custodial safekeeping.
To protect against potential losses due to failure of individual securities dealers, and to enhance access to securities, interest payments and maturity proceeds, all cash and securities in Community Power’s portfolio shall be held in safekeeping in Community Power’s name by a third-party custodian, acting as agent for Community Power under the terms of a custody agreement executed by the bank and Community Power. All investment transactions will require a safekeeping receipt or acknowledgment generated from the trade. A monthly report will be received by Community Power from the custodian listing all securities held in safekeeping with current market data and other information.
The only exceptions to the foregoing shall be depository accounts and securities purchases made with: (1) local government investment pools; (2) time certificates of deposit, (3) Local Agency Investment Fund, and (4) mutual funds and money market mutual funds, since these securities are not deliverable.
E. Avoidance of Physical Delivered Bearer Securities: Book entry securities are much easier to transfer and account for since actual delivery of a document never takes place.
Bearer securities must be properly safeguarded against loss or destruction. The potential for fraud and loss increases with such securities.
F. Written Confirmation of Telephone Wire Transfers: Due to the potential for error and improprieties arising from telephone transactions, all telephone transactions should be supported by written or electronic communications and approved by the appropriate person. Community Power will consider entering into a Wire Transfer Agreement with the Lead Bank or Third-Party.
G. Audits: Community Power’s Funds shall be subject to a process of independent review by its external auditors. Community Power’s external auditors shall review the investment portfolio in connection with Community Power’s annual audit for compliance with the Policy pursuant to Section 27134. The results of the audit shall be reported to the Treasurer.
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REPORTS:
A. Monthly: The Treasurer will perform a monthly review of the investment function.
Following the commencement of investment transactions, the Treasurer shall submit a monthly report of all investment transactions to the Finance and Risk Management Committee. Investment transactions are defined as the purchase, sale or exchange of securities.
B. Annually: The Treasurer will submit an annual report to the Finance and Risk Management Committee within 60 days of the end of a fiscal year providing the following:
• A list of individual securities by investment type, issuer, credit risk rating, CUSIP number, settlement date of purchase, date of maturity, par value and dollar amount invested on all securities, and the market value and source of the market value information;
• A statement that the portfolio is in compliance with this Policy and in accordance with Section 53646 or the manner in which the portfolio is not in compliance; and • A statement of Community Power’s ability to meet anticipated cash requirements for the upcoming 12 months.
• The Treasurer shall monitor and evaluate the portfolio’s performance relative to the chosen market benchmark(s), which will be included in the Treasurer’s annual report.
The Treasurer shall select an appropriate, readily available index to use as a market benchmark. Benchmarks may change over time based on changes in market conditions or cash flow requirements.
C. Annual Review: This Policy will be reviewed annually by the Treasurer. The Board is authorized to approve changes to this Policy following the review of proposed changes by the Finance Risk Management Committee.
Prior Versions:
Date Action Resolution No. Policy No.
5/25/2023 Adoption N/A 2023-07
6/27/2024 Amendment 2024-04 2023-08
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Glossary of Investment Terms
ASSET BACKED SECURITIES. Securities supported by pools of installment loans or leases or by pools of revolving lines of credit.
BANKERS’ ACCEPTANCES. A short-term, negotiable, unconditional, and time draft drawn on and accepted by a bank. It is typically used in trade to finance the purchase and sale of goods.
BENCHMARK. A comparison security or portfolio. A performance benchmark is a partial market index, which reflects the mix of securities allowed under a specific investment policy.
BROKER. A broker brings buyers and sellers together for a transaction for which the broker receives a commission. A broker does not sell securities from his own position.
CALLABLE. A callable security gives the issuer the option to call it from the investor prior to its maturity. The main cause of a call is a decline in interest rates. If interest rates decline, the issuer will likely call its current securities and reissue them at a lower rate of interest.
CERTIFICATE OF DEPOSIT (CD). A time deposit with a specific maturity evidenced by a certificate. Large denomination CDs may be marketable.
CERTIFICATE OF DEPOSIT ACCOUNT REGISTRY SYSTEM (CDARS). A private placement service that allows local agencies to purchase more than $250,000 in CDs from a single financial institution (must be a participating institution of CDARS) while still maintaining FDIC insurance coverage. CDARS is currently the only entity providing this service. CDARS facilitates the trading of deposits between the California institution and other participating institutions in amounts that are less than $250,000 each, so that FDIC coverage is maintained.
COLLATERAL. Securities or cash pledged by a borrower to secure repayment of a loan or repurchase agreement. Also, securities pledged by a financial institution to secure deposits of public monies.
COLLATERALIZED MORTGAGE OBLIGATIONS (CMO). Classes of bonds that redistribute the cash flows of mortgage securities (and whole loans) to create securities that have different levels of prepayment risk, as compared to the underlying mortgage securities.
COMMERCIAL PAPER. The short-term unsecured debt of corporations.
COUPON. The rate of return at which interest is paid on a bond.
CREDIT RISK. The risk that principal and/or interest on an investment will not be paid in a timely manner due to changes in the condition of the issuer.
CRYPTO ASSET. Digital assets that use public ledgers over the internet to prove ownership.
They use cryptography, peer-to-peer networks and a distributed ledger technology (DLT) – such as blockchain – to create, verify and secure transactions. 159
CUSIP. Committee on Uniform Securities Identification Procedures. A CUSIP number identifies most financial instruments, including: stocks of all registered U.S. and Canadian companies, commercial paper, and U.S. government and municipal bonds.
DEALER. A dealer acts as a principal in security transactions, selling securities from and buying securities for his own position.
DELIVERY vs PAYMENT (DVP). A securities industry procedure whereby payment for a security must be made at the time the security is delivered to the purchaser’s agent.
DISCOUNT. The difference between the par value of a bond and the cost of the bond, when the cost is below par. Some short-term securities, such as T-bills and banker’s acceptances, are known as discount securities. They sell at a discount from par and return the par value to the investor at maturity without additional interest. Other securities, which have fixed coupons, trade at a discount when the coupon rate is lower than the current market rate for securities of that maturity and/or quality.
DIVERSIFICATION. Dividing investment funds among a variety of investments to avoid excessive exposure to any one source of risk.
DURATION. The weighted average time to maturity of a bond where the weights are the present values of the future cash flows. Duration measures the price sensitivity of a bond to changes in interest rates. (See modified duration).
FEDERAL FUNDS RATE. The rate of interest charged by banks for short-term loans to other banks. The Federal Reserve Bank through open-market operations establishes it.
ISSUER. The entity identified as the counterparty or obligator related to a security trade.
INVERSE FLOATER. A bond or other type of debt whose coupon rate has an inverse relationship to a benchmark rate.
INVESTMENT OFFICIALS. This includes any applicable Community Power staff participating in the investment process; Community Power Treasurer; Community Power Deputy Treasurer(s); and Community Power Board of Directors.
LEVERAGE. Borrowing funds in order to invest in securities that have the potential to pay earnings at a rate higher than the cost of borrowing.
LIQUID. Term for securities that can be converted to cash quickly.
LIQUIDITY. The speed and ease with which an asset can be converted to cash.
LOCAL AGENCY INVESTMENT FUND (LAIF). A voluntary investment fund open to government entities and certain non-profit organizations in California that is managed by the State Treasurer’s Office.
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LOCAL GOVERNMENT INVESTMENT POOL. Investment pools that range from the State Treasurer’s Office Local Agency Investment Fund (LAIF) to county pools, to Joint Powers Authorities (JPAs). These funds are not subject to the same SEC rules applicable to money market mutual funds.
MARGIN. The difference between the market value of a security and the loan a broker makes using that security as collateral.
MARKET RISK. The risk that the value of securities will fluctuate with changes in overall market conditions or interest rates.
MARKET VALUE. The price at which a security can be traded.
MATURITY. The final date upon which the principal of a security becomes due and payable.
MEDIUM TERM NOTES. Unsecured, investment-grade senior debt securities of major corporations which are sold in relatively small amounts on either a continuous or an intermittent basis. MTNs are highly flexible debt instruments that can be structured to respond to market opportunities or to investor preferences.
MODIFIED DURATION. The percent change in price for a 100 basis point change in yields.
Modified duration is the best single measure of a portfolio’s or security’s exposure to market risk.
MONEY MARKET. The market in which short-term debt instruments (T-bills, discount notes, commercial paper, and banker’s acceptances) are issued and traded.
MORTGAGE BACK SECURITY. Debt obligations that represent claims to the cash flows from pools of mortgage loans, most commonly on residential property.
MORTGAGE-DERIVED INTEREST-ONLY STRIPS. A financial product created by separating the interest and principal payments of a mortgage-backed security.
MORTGAGE PASS-THROUGH SECURITIES. A securitized participation in the interest and principal cash flows from a specified pool of mortgages. Principal and interest payments made on the mortgages are passed through to the holder of the security.
MUNICIPAL SECURITIES. Securities issued by state and local agencies to finance capital and operating expenses.
MUTUAL FUND. An entity which pools the funds of investors and invests those funds in a set of securities which is specifically defined in the fund’s prospectus. Mutual funds can be invested in various types of domestic and/or international stocks, bonds, and money market instruments, as set forth in the individual fund’s prospectus. For most large, institutional investors, the costs associated with investing in mutual funds are higher than the investor can obtain through an individually managed portfolio.
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NATIONALLY RECOGNIZED STATISTICAL RATING ORGANIZATION (NRSRO). A credit rating agency that the Securities and Exchange Commission in the United States uses for regulatory purposes. Credit rating agencies provide assessments of an investment's risk. The issuers of investments, especially debt securities, pay credit rating agencies to provide them with ratings. The three most prominent NRSROs are Fitch, S&P, and Moody's.
NEGOTIABLE CD. A short-term debt instrument that pays interest and is issued by a bank, savings or federal association, state or federal credit union, or state-licensed branch of a foreign bank. Negotiable CDs are traded in a secondary market and are payable upon order to the bearer or initial depositor (investor).
PREMIUM. The difference between the par value of a bond and the cost of the bond, when the cost is above par.
RANGE NOTES. A structured investment where the coupon is linked to the performance of a reference index
REPURCHASE AGREEMENT. Short-term purchases of securities with a simultaneous agreement to sell the securities back at a higher price. From the seller’s point of view, the same transaction is a reverse repurchase agreement.
SAFEKEEPING. A service to bank customers whereby securities are held by the bank in the customer’s name.
SUPRANATIONAL. A Supranational is a multi-national organization whereby member states transcend national boundaries or interests to share in the decision making to promote economic development in the member countries.
TOTAL RATE OF RETURN. A measure of a portfolio’s performance over time. It is the internal rate of return, which equates the beginning value of the portfolio with the ending value; it includes interest earnings, realized and unrealized gains, and losses in the portfolio.
U.S. TREASURY OBLIGATIONS. Securities issued by the U.S. Treasury and backed by the full faith and credit of the United States. Treasuries are considered to have no credit risk and are the benchmark for interest rates on all other securities in the US and overseas. The Treasury issues both discounted securities and fixed coupon notes and bonds.
TREASURY BILLS. All securities issued with initial maturities of one year or less are issued as discounted instruments and are called Treasury bills. The Treasury currently issues three- and six-month T-bills at regular weekly auctions. It also issues “cash management” bills as needed to smooth out cash flows.
TREASURY NOTES. All securities issued with initial maturities of two to ten years are called Treasury notes and pay interest semi-annually.
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TREASURY BONDS. All securities issued with initial maturities greater than ten years are called Treasury bonds. Like Treasury notes, they pay interest semi-annually.
VOLATILITY. The rate at which security prices change with changes in general economic conditions or the general level of interest rates.
YIELD TO MATURITY. The annualized internal rate of return on an investment which equates the expected cash flows from the investment to its cost. 163
ITEM 12
EXHIBIT B
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San Diego Community Power
Investment Policy
Subject: Investment Policy
Purpose: The San Diego Community Power (“SDCP”) Investment Policy (“Policy”) establishes investment guidelines for protecting SDCP’s cash reserves, deposits, and investments (collectively, “Funds”) while producing a reasonable rate of return on investments.
Thise Policy articulates: (1) the objectives and priorities for SDCP investments; (2) the types of investments that are permitted and prohibited; and (3) the controls SDCP will implement to ensure assets investments are protected.
This Policy is adopted pursuant to California Government Code Section (“Section”) 53600-53608 and must be adopted or amended by resolution. The SDCP Board of Directors (“Board”) is not required to adopt a formal Investment Policy by statute, however, it is in the best practice to ensure agency assets are protected.
Background
On October 1, 2019, the fFounding mMembers of San Diego Community Power (SDCP) adopted the Joint Powers Agreement (JPA) which was amended and restated on December 16, 2021.
Section 3.2.12 of the JPA specifies that the SDCP Board of Directors (Board) may at its discretion adopt rules, regulations, policies, bylaws and procedures governing the operation of SDCP.
Further, Section 4.5.5 of the JPA states that one of the general purposes of the Board is to set policy.
Section 5.10.2(C) of the JPA finally states that one of the primary purposes of the Financial and Risk Management Committee (FRMC) is to review and recommend to the Board financial policies and procedures to ensure equitable contributions by pParties consistent with a recommendation for Board approval of the Investment Policy herein. Further, this section states Policy Number: 2023-07
Original Adoption Date: May 25, 2023
Revision Date: June 27, 2024TBDAugust
28, 2025
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the FRMC may have such other responsibilities as may be approved by the Board, including but not limited to, advising the Chief Executive Officer on fiscal and risk management policies and procedures, rules and regulations governing investment of surplus funds, audits to achieve best practices in corporate governance, and selection and designation of financial institutions for deposit of SDCP funds, and credit/depository matters.
Investment Objectives
To the extent possible, investments will align with SDCP’s mission, vision, value, and goals.
When managing Funds, SDCP’s primary objectives shall be to (1) safeguard the principal of the Funds, (2) meet the liquidity needs of SDCP, (3) achieve a return on Funds invested, and (4) exercise a high standard of care on Funds within SDCP’s control. 1) Safety: Safety of principal is the foremost objective of cash and investment management activities. The investment of Funds shall be undertaken in a manner that seeks to ensure the preservation of principal.
2) Liquidity: The Funds of SDCP shall remain sufficiently liquid to meet all operating needs that may be reasonably anticipated. Since all possible cash demands cannot be anticipated, the investment of Funds in deposits or instruments that are available on demand is recommended.
3) Return on Investments: SDCP’s deposit and investment portfolio shall be designed with the objective of attaining a market rate of return throughout the economic cycle while considering investment risk and liquidity constraints. The return on deposits and investments is of secondary importance compared to the safety and liquidity objectives described in Investment Objectives, Section (1) and Investment Objectives, Section (2), above.
4) Standard of Care: SDCP will manage the Funds in accordance with the “Prudent Investor Standard” pursuant to California Government Code Section 53600.31 as follows:
“All governing bodies of local agencies or persons authorized to make investment decisions on behalf of those local agencies investing public funds are trustees and therefore fiduciaries subject to the prudent investor standard. When investing, reinvesting, purchasing, acquiring, exchanging, selling or managing public funds, a trustee shall act with care, skill, prudence and diligence under the circumstances then prevailing, that a prudent person acting in a like capacity and familiarity with those matters would use in the conduct of funds of a like character and with like aims, to safeguard the principal and maintain the liquidity needs of the agency. Within the limitations of this section and considering individual investments as part of an overall strategy, investments may be acquired as authorized by law.”
1 All further statutory references are to the California Government Code unless otherwise stated. 166
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Investment Objectives
To the extent possible, investments will align with SDCP’s mission, vision, value, and goals.
When managing Funds, SDCP’s primary objectives shall be to (1) safeguard the principal of the Funds, (2) meet the liquidity needs of SDCP, (3) achieve a return on Ffunds invested, and (4) exercise a high standard of care on Funds within SDCP’s control. 1) Safety: Safety of principal is the foremost objective of cash and investment management activities. The investment of Funds shall be undertaken in a manner that seeks to ensure the preservation of principal.
2) Liquidity: The Funds of SDCP shall remain sufficiently liquid to meet all operating needs that may be reasonably anticipated. Since all possible cash demands cannot be anticipated, the investment of Funds in deposits or instruments that are available on demand is recommended.
3) Return on Investments: SDCP’s deposit and investment portfolio shall be designed with the objective of attaining a market rate of return throughout the economic cycle while considering investment risk and liquidity constraints. The return on deposits and investments is of secondary importance compared to the safety and liquidity objectives described in Investment Objectives, Section (1)A and Investment Objectives, Section (2)B, above.
4) Standard of Care: SDCP will manage the Funds in accordance with the “Prudent Investor Standard” pursuant to California Government Code Section 53600.32 as follows:
“All governing bodies of local agencies or persons authorized to make investment decisions on behalf of those local agencies investing public funds are trustees and therefore fiduciaries subject to the prudent investor standard. When investing, reinvesting, purchasing, acquiring, exchanging, selling or managing public funds, a trustee shall act with care, skill, prudence and diligence under the circumstances then prevailing, that a prudent person acting in a like capacity and familiarity with those matters would use in the conduct of funds of a like character and with like aims, to safeguard the principal and maintain the liquidity needs of the agency. Within the limitations of this section and considering individual investments as part of an overall strategy, investments may be acquired as authorized by law.”
2 All further statutory references are to the California Government Code unless otherwise stated. 168
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Delegation of Authority
Pursuant to Section 53607, the Board has the authority to delegate the responsibility to manage SDCP’s funds to the Treasurer. The Treasurer has authority to appoint Deputy Treasurer(s) as the Treasurer deems necessary to carry out the duties in accordance with the Investment Policy.
SDCP may engage the services from one or more external investment advisers, who are registered under the Investment Advisers Act of 1940, to assist in the management of SDCP’s investment portfolio in a manner consistent with the SDCP’s Policy. External investment advisers may be granted discretion to purchase and sell investment securities in accordance with the investment objective set forth in this Policy.
Scope
This Investment Policy applies to all funds and investment under the direct authority of SDCP.
This Policy does not apply to the investment of bond proceeds, which would be governed by any applicable bond documents, and any other funds specifically exempted by SDCP’s the Board of Directors.
Acceptable Investment Types: To the extent possible, investments will align with SDCP’s mission, vision, value, and goals.
1. Deposits at Bank(s): Funds may be invested in non-interest-bearing depository accounts to meet SDCP’s operating and collateral needs and grant requirements. Funds not needed for these purposes may be invested in interest-bearing depository accounts or Federal Deposit Insurance Corporation (FDIC) insured certificates of deposit with maturities not to exceed five (5) years. Banks eligible to receive deposits will be federally or state chartered and will conform to Section 53635.2 which requires that banks “have received an overall rating of not less than ‘satisfactory’ in its most recent evaluation by the appropriate federal financial supervisory agency of its record of meeting the credit needs of California's communities, including low- and moderate-income neighborhoods, pursuant to Section 2906 of Title 12 of the United States Code.” As per Section 53652, banks must collateralize the deposits of public agencies in an amount equal to no less than 110% of as currently stated in the value of the deposits. The Treasurer will monitor the credit quality of eligible banks holding SDCP deposits that exceed FDIC insurance limits to ensure the safety of SDCP deposits. There are no limits on the dollar amount or percentage that SDCP may invest in collateralized bank deposits.
2. Local Agency Investment Fund (LAIF): Funds may be invested in the Local Agency Investment Fund established by the California State Treasurer for the benefit of local agencies. LAIF’s investments in instruments prohibited by or not specified in SDCP’s policy do not exclude the investment in LAIF itself from SDCP’s list of allowable investments, provided LAIF’s reports allow the Treasurer to adequately judge the risk inherent in LAIF’s portfolio.
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3. US Treasury Obligations: Funds may be invested in United States Treasury obligations with a term to maturity not exceeding five (5) years and subject to the limitations set forth in Sections 53601 et seq. and 53635 et seq.
4. Federal Agency Securities: Funds may be invested in Federal Agency Securities or Government-Sponsored Enterprise (GSE) obligations with a term to maturity not exceeding five (5) years and subject to the limitations set forth in Sections 53601 et seq. and 53635 et seq. No more than 20% of the total portfolio may be invested in callable agency securities and no more than 30% of the total portfolio may be invested in any single Agency/ GSE issuer.
5. Bankers’ Acceptances: Funds may be invested in Banker’s Acceptances provided that they are issued by institutions which have short-term debt obligations rated “A-1” or its equivalent orf better by at least one NRSRO (Nationally Recognized Statistical Rating Organization (NRSRO). Not more than 40% of the portfolio may be invested in Bankers’ Acceptances, and no more than 5% of the portfolio may be invested in any single issuer.
The maximum maturity shall not exceed 180 days.
6. Negotiable Certificates of Deposit: Funds may be invested in negotiable certificates of deposit in accordance with the requirements of Section 53601 and 53601.8, and subject to the following limitations:
A. Issued by an entity as defined in Section 53601(i); and B. No more than 30% of the total portfolio shall be invested in certificates of deposit, no more than 5% of the total portfolio may be invested in any single issuer, and the maximum maturity does not exceed 5 years.
7. Placement Service Deposits: Funds may be invested in deposits placed with a private sector entity that assists in the placement of deposits with eligible financial institutions located in the United States (Section 53601.8). No more than 30% of the total portfolio may be invested in a combination of qualifying placement service deposits. The full amount of principal and the interest that may be accrued during the maximum term of each deposit shall at all times be insured by federal deposit insurance. Under a provision sunsetting on January 1, 2031, no more than 50% of the portfolio may be invested in deposits through a placement service. The maximum maturity shall not exceed five (5) years.The maximum portfolio exposure to the deposits placed pursuant to this section shall be limited by Section 53601.8.
8. Money Market Funds: Funds may be invested in money market funds pursuant to Section 53601(l)(2) and subject to Section 53601(l)(4). No more than 20% of the portfolio may be invested in the shares of any one Money Market Fund. No more than 20% of the total portfolio may be invested in these securities.
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9. Commercial Paper: Funds may be invested in commercial paper of “prime” quality of the highest ranking or of the highest letter and number rating as provided for by an NRSRO.
The entity that issues the commercial paper must meet all of the following conditions in either paragraph A or paragraph B below:
A. The entity meets the following criteria: (i) is organized and operating in the United States as a general corporation, (ii) has total assets in excess of five hundred million dollars ($500,000,000), and (iii) has debt other than commercial paper, if any, that is rated in a rating category of “A” or its equivalent or higher by an NRSRO.
B. The entity meets the following criteria: (i) is organized within the United States as a special purpose corporation, trust, or limited liability company, (ii) has program-wide credit enhancements including, but not limited to, over collateralization, letters of credit, or surety bond, and (iii) has commercial paper that is rated “A-1” or higher, or the equivalent, by an NRSRO.
No more than 10% of the outstanding commercial paper of any single issuer. No more than 25% of SDCP’s investment assets under management may be invested in Commercial Paper. Under a provision sunsetting on January 1, 2026, no more than 40% of the total portfolio may be invested in Commercial Paper if SDCP’s investment assets under management are greater than $100,000,000. No more than 5% of the total portfolio may be invested in any single issuer. The maximum maturity does not exceed 270 days.
10. Medium Term Notes (MTN): The issuer is a corporation organized and operating within the United States or by depository institutions licensed by the United States or any state and operating within the United States. (Section 53601 et seq). The securities are rated in a rating category of “A” or its equivalent or better by at least one NRSRO. No more than 30% of the total portfolio may be invested in MTNs, no more than 5% of the total portfolio may be invested in any single issuer and the maximum maturity does not exceed five (5) years.
11. Pass Thru Securities: Asset-Backed, Mortgage-Backed, Mortgage Pass-Through Securities, and Collateralized Mortgage Obligations (Section 53601 et seq) from issuers not defined in sections 3 and 4 of the Acceptable Investment Types section of this Ppolicy, provided that,: tThe securities are rated in a rating category of “AA” or its equivalent or better by an NRSRO, no more than 20% of the total portfolio may be invested in these securities, no more than 5% of the total portfolio may be invested in any single Asset-Backed or Commercial Mortgage security issuer and the maximum maturity does not exceed five (5) years.
12. Municipal Securities: These include obligations of SDCP, the State of California and any local agency within the State of California ,(Section 53601). provided that,: tThe 171
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securities are rated in a rating category of “A” or its equivalent or better by at least one nationally recognized statistical rating organization (“NRSRO”)., no more than 5% of the total portfolio may be invested in any single issuer, no more than 30% of the total portfolio may be in Municipal Securities and the maximum maturity does not exceed five (5) years.
13. Municipal Securities:; (Registered treasury notes or bonds) of any of the other 49 states in addition to California, including bonds payable solely out of the revenues from a revenue-producing property owned, controlled, or operated by a state or by a department, board, agency, or authority of any of the other 49 states, in addition to California (Section 53601). The securities are rated in a rating category of “A” or its equivalent or better by at least one NRSRO, no more than 5% of the total portfolio may be invested in any single issuer, no more than 30% of the total portfolio may be in Municipal Securities and the maximum maturity does not exceed five (5) years.
14.Supranationals: Issues are US dollar denominated senior unsecured unsubordinated obligations issued or unconditionally guaranteed by the International Bank for Reconstruction and Development, International Finance Corporation, or Inter-American Development Bank. (Section 53601). The securities are rated in a rating category of “AA” or its equivalent or better by an NRSRO, no more than 30% of the total portfolio may be invested in these securities, no more than 10% of the total portfolio may be invested in any single issue and the maximum maturity does not exceed five (5) years.
15. Local Government Investment Pools (LGIPs): Shares of beneficial interest issued by a Joint Powers Authority (JPA) organized pursuant to California Government Code Section 6509.7 that invest in the securities and obligations authorized in subdivisions (a) to (r), inclusive. Each share shall represent an equal proportional interest in the underlying pool of securities owned by the JPA. To be eligible under this section, the JPA issuing the shares will have retained an investment adviser who is registered with the SEC (or exempt from registration), has assets under management in excess of five hundred million dollars ($500,000,000), and has not less than five years of experience investing in the securities and obligations authorized in subdivisions (a) to (q) of Government Code Section 53601, inclusive.
Prohibited Investment Types
Pursuant to Section 53601.6, SDCP shall not invest Funds in any security that could result in a zero-interest accrual, or less, if held to maturity. These prohibited investments include, but are not limited to, inverse floaters, range notes, or mortgage-derived interest-only strips. The purchase of foreign currency denominated securities is prohibited. The purchase of Crypto Asset Securities is prohibited. The purchase of a security with a forward settlement date exceeding 45 days from the time of the investment is prohibited. Trading securities for the sole purpose of 172
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speculating on the future direction of interest rates is prohibited. Purchasing or selling securities on margin is prohibited. The use of reverse repurchase agreements, securities lending or any other form of borrowing or leverage is prohibited. SDCP is prohibited from investing in any company or organization whose business do not align with SDCP’s mission, vision, value, and goals.
Investment Portfolio Management
The term to maturity of any Funds invested shall not exceed five (5) years pursuant to Section 53601. The Treasurer will allocate Funds among authorized investments consistent with the objectives and standards of care outlined in this Policy.
Collateralization
Certificates of Deposit (CDs). SDCP shall require any commercial bank or savings and loan association to deposit eligible securities with an agency of a depository approved by the State Banking Department to secure any uninsured portion of a Non-Negotiable Certificate of Deposit.
The value of eligible securities as defined pursuant to California Government Code, Section 53651, pledged against a Certificate of Deposit shall be equal to 150% of the face value of the CD if the securities are classified as mortgages and 110% of the face value of the CD for all other classes of security.
Bank Deposits. This is the process by which Aa bank or financial institution may pledges securities, or other deposits for the purpose of securing repayment of deposited funds. SDCP shall require any bank or financial institution to comply with the collateralization criteria defined in California Government Code, Section 53651.
Risk Management and Diversification
SDCP’s investment portfolio will be diversified to avoid incurring unreasonable and avoidable risks associated with concentrating investments in specific security types, maturity segment, or in individual financial institutions. No more than 5% of the investment portfolio shall be in securities of any one issuer except for U.S. Treasuries, U.S. Government Agency issues, Supranationals and investment pools such as LAIF, and money market funds.
A. Credit Risk: Credit risk, defined as the risk of loss due to failure of the insurer of a security, shall be mitigated by investing in those securities with an “A” or above rating and approved in thise Investment Policy and by diversifying the investment portfolio so that the failure of any one issuer would not unduly harm SDCP’s cash flow. 173
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B. Market Risk: Market risk or interest rate risk, defined as the risk of market value fluctuations due to overall changes in the general level of interest rates, shall be mitigated by implementing a short term and long-term investment strategies. It is explicitly recognized herein, however, that in a diversified portfolio, occasional measured losses are inevitable and must be considered within the context of overall investment return.
The duration of the portfolio will generally be approximately equal to the duration (typically, plus or minus 20%) of a Market Benchmark, an index selected by SDCP based on SDCP’s investment objectives, constraints and risk tolerances.
B. Credit Rating:
C. This Investment Policy sets forth minimum credit ratings for each type of security. These credit ratings apply to the initial purchase of a security and do not automatically force the sale of a security if the credit ratings of the security fall below the policy limits.
Minimum credit ratings:
1. For securities with maturities of 13 months or less, the rating must be in the highest short-term rating category (without regard to qualification of such rating symbol such as “+” or “- “) by at least one nationally recognized statistical rating organization (the “NRSRO”).
2. For securities with maturities greater than 13 months, the rating must be “A” or higher by at least one NRSRO.
The monitoring of credit ratings consists of the following procedures:
1. When a credit rating downgrade occurs which results in a rating below the minimum credit requirement, SDCP’s Finance Department or external investment adviser will analyze and evaluate the credit rating to determine whether to hold or sell the investment.
2. In the event a security in the Fund receives a credit rating downgrade which results in a rating below the minimum credit rating requirement, SDCP’s Treasurer will report the rating change to the Finance and Risk Management Committee in the monthly public report. In the same manner, the Finance and Risk Management Committee will be informed on the decision to hold or sell a downgraded security.
3. The Investment Officials or authorized employees involved in the investment process and external investment advisers shall meet at least quarterly to review and update the approved list of securities and establish credit criteria for each category of security. 174
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To ensure that the Fund maintains the highest overall credit rating with the contracted NRSRO, the asset allocation and portfolio holdings will be provided to the contracted NRSRO on a monthly basis.
Brokers
The Treasurer shall endeavor to complete investment transactions in accordance with Section 53601.5, with institutions eligible to transact investment business with SDCP, in accordance with Section 53601.5, includeing:
A. Institutions licensed by the state as a broker-dealer.
B. Institutions that are members of a federally regulated securities exchange.
C. Primary government dealers as designated by the Federal Reserve Bank and non-primary government dealers.
D. Nationally or state-chartered banks.
E. The Federal Reserve Bank.
F. Direct issuers of securities eligible for purchase.
Broker/dealers shall be approved by the Chief Executive Officer upon recommendation by the Treasurer. Selection of broker/dealers shall be based upon the following criteria: the reputation and financial strength of the company or financial institution, the reputation and expertise of the individuals employed, and pursuant to the requirements of Section 53601.5. The Treasurer shall require any selected broker, brokerage firm, dealer, or securities firm to affirm that it has not, within any 48-consecutive month period, made a political contribution to any member of the SDCP Board, or any candidate who may join the SDCP Board in an amount exceeding the limitations contained in Rule G-37 of the Municipal Securities Rulemaking Board, the Political Reform Act, including section 84308, or any applicable SDCP Policy, as amended from time to time. The selected broker or dealers shall be provided with and acknowledge receipt of this Policy.
Losses
Losses are acceptable on a sale before maturity and may be taken if required to meet the liquidity needs of SDCP or if the reinvestment proceeds will earn an income flow with a present value higher than the present value of the income flow that would have been generated by the original investment, considering any investment loss or foregoing interest on the original investment.
Delivery and Safekeeping
The delivery and safekeeping of all securities shall be made through a third-party custodian when practical and cost effective as determined by the Treasurer, or a duly appointed Deputy Treasurer, and in accordance with Section 53608.
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The Treasurer shall review all transaction confirmations for conformity with the original transaction and monitor for excessive trading.
Ethics and Conflict of Interest
The Investment Officials or authorized employees involved in the investment process, shall act as custodians of the public trust and will refrain from personal business activities that could conflict with proper execution of the investment program, or which could impair their ability to make impartial decisions. Investment Officials and any external investment advisers acknowledge that all direct SDCP investments are subject to public review and evaluation.
SDCP Investment Officials involved in the investment process shall refrain from personal business activity that could create a conflict of interest or the appearance of a conflict with proper execution of the investment program, or which could impair their ability to make impartial investment decisions.
SDCP Investment Officials shall disclose to General Counsel or designee (i) any material interests in financial institutions with which they conduct business, and (ii) disclose any personal investments with a direct, indirect or beneficial interest totaling $2,000 or more. Investment Officials shall refrain from undertaking any personal investment transactions with the same individual from the external investment adviser with whom business is conducted on behalf of SDCP.
Investment Officials, pursuant with all applicable laws, shall not accept honoraria, gifts, and gratuities from advisers, brokers, dealers, bankers, or other entity with whom SDCP conducts business.
Any external investment adviser contracted by SDCP will comply with Municipal Securities Rulemaking Board Rule G-37 and shall follow the Investment Adviser Fiduciary Standard established by the U.S. Securities and Exchange Commission.
Internal Controls
The Treasurer is responsible for establishing and maintaining an internal control structure designed to ensure that the assets of the entity are protected from loss, theft or misuse. The internal control structure shall be designed to provide reasonable assurance that these objectives are met.
Accordingly, the Treasurer shall establish and maintain internal controls that shall address the following points:
A. Control of Collusion: Collusion is a situation where two or more employees are working in conjunction to defraud their employer. To achieve a segregation of duties, individuals 176
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who authorize investment transactions shall not also record or reconcile said transactions.
B. Clear Delegation of Authority to Subordinate Staff Members: Subordinate staff members must have a clear understanding of their authority and responsibilities to avoid improper actions. Clear delegation of authority also preserves the internal control structure that is contingent on the various staff positions and their respective responsibilities.
C. Delivery-Versus-Payment (DVP): All investment transactions shall be conducted on a delivery-versus-payment basis.
D. Safekeeping and Custody: Securities purchased from any bank or dealer, including appropriate collateral (as defined by California Government Code), that are not insured by the FDIC, shall be placed with an independent third party for custodial safekeeping.
To protect against potential losses due to failure of individual securities dealers, and to enhance access to securities, interest payments and maturity proceeds, all cash and securities in SDCP’s portfolio shall be held in safekeeping in SDCP’s name by a third-party custodian, acting as agent for SDCP under the terms of a custody agreement executed by the bank and SDCP. All investment transactions will require a safekeeping receipt or acknowledgment generated from the trade. A monthly report will be received by SDCP from the custodian listing all securities held in safekeeping with current market data and other information. The only exceptions to the foregoing shall be depository accounts and securities purchases made with: (1) local government investment pools; (2) time certificates of deposit, (3) Local Agency Investment Fund, and (4) mutual funds and money market mutual funds, since these securities are not deliverable.
E. Avoidance of Physical Delivered Bearer Securities: Book entry securities are much easier to transfer and account for since actual delivery of a document never takes place.
Bearer securities must be properly safeguarded against loss or destruction. The potential for fraud and loss increases with such securities.
F. Written Confirmation of Telephone Wire Transfers: Due to the potential for error and improprieties arising from telephone transactions, all telephone transactions should be supported by written or electronic communications and approved by the appropriate person. SDCP will consider entering intoDevelopment of a Wire Transfer Agreement with the Lead Bank or Third-Party.
G. Audits: SDCP’s Funds shall be subject to a process of independent review by its external auditors. SDCP’s external auditors shall review the investment portfolio in connection with SDCP’s annual audit for compliance with the Policy pursuant to Section 27134. The results of the audit shall be reported to the Treasurer.
Reports
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A. Monthly: The Treasurer will perform a monthly review of the investment function.
Following the commencement of investment transactions, the Treasurer shall submit a monthly report of all investment transactions to the Finance and Risk Management Committee. Investment transactions are defined as the purchase, sale or exchange of securities.
B. Annually: The Treasurer will submit an annual report to the Finance and Risk Management Committee within 60 days of the end of a fiscal year providing the following:
• A list of individual securities by investment type, issuer, credit risk rating, CUSIP number, settlement date of purchase, date of maturity, par value and dollar amount invested on all securities, and the market value and source of the market value information;
• A statement that the portfolio is in compliance with this Policy and in accordance with Section 53646 or the manner in which the portfolio is not in compliance; and • A statement of SDCP’s ability to meet anticipated cash requirements for the upcoming 12 months.
• The Treasurer shall monitor and evaluate the portfolio’s performance relative to the chosen market benchmark(s), which will be included in the Treasurer’s annual report.
The Treasurer shall select an appropriate, readily available index to use as a market benchmark. Benchmarks may change over time based on changes in market conditions or cash flow requirements.
C. Annual Review: This Policy will be reviewed annually by the Treasurer. The Board is authorized to approve changes to this Policy following the review of proposed changes by the Finance Risk Management Committee.
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Glossary of Investment Terms
ASSET BACKED SECURITIES. Securities supported by pools of installment loans or leases or by pools of revolving lines of credit.
BANKERS’ ACCEPTANCES. A short-term, negotiable, unconditional, and time draft drawn on and accepted by a bank. It is typically used in trade to finance the purchase and sale of goods.
BENCHMARK. A comparison security or portfolio. A performance benchmark is a partial market index, which reflects the mix of securities allowed under a specific investment policy.
BROKER. A broker brings buyers and sellers together for a transaction for which the broker receives a commission. A broker does not sell securities from his own position.
CALLABLE. A callable security gives the issuer the option to call it from the investor prior to its maturity. The main cause of a call is a decline in interest rates. If interest rates decline, the issuer will likely call its current securities and reissue them at a lower rate of interest.
CERTIFICATE OF DEPOSIT (CD). A time deposit with a specific maturity evidenced by a certificate. Large denomination CDs may be marketable.
CERTIFICATE OF DEPOSIT ACCOUNT REGISTRY SYSTEM (CDARS). A private placement service that allows local agencies to purchase more than $250,000 in CDs from a single financial institution (must be a participating institution of CDARS) while still maintaining FDIC insurance coverage. CDARS is currently the only entity providing this service. CDARS facilitates the trading of deposits between the California institution and other participating institutions in amounts that are less than $250,000 each, so that FDIC coverage is maintained.
COLLATERAL. Securities or cash pledged by a borrower to secure repayment of a loan or repurchase agreement. Also, securities pledged by a financial institution to secure deposits of public monies.
COLLATERALIZED MORTGAGE OBLIGATIONS (CMO). Classes of bonds that redistribute the cash flows of mortgage securities (and whole loans) to create securities that have different levels of prepayment risk, as compared to the underlying mortgage securities.
COMMERCIAL PAPER. The short-term unsecured debt of corporations.
COUPON. The rate of return at which interest is paid on a bond.
CREDIT RISK. The risk that principal and/or interest on an investment will not be paid in a timely manner due to changes in the condition of the issuer. 179
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CRYPTO ASSET. Digital assets that use public ledgers over the internet to prove ownership.
They use cryptography, peer-to-peer networks and a distributed ledger technology (DLT) – such as blockchain – to create, verify and secure transactions.
CUSIP. Committee on Uniform Securities Identification Procedures. A CUSIP number identifies most financial instruments, including: stocks of all registered U.S. and Canadian companies, commercial paper, and U.S. government and municipal bonds.
DEALER. A dealer acts as a principal in security transactions, selling securities from and buying securities for his own position.
DELIVERY vs PAYMENT (DVP). A securities industry procedure whereby payment for a security must be made at the time the security is delivered to the purchaser’s agent.
DISCOUNT. The difference between the par value of a bond and the cost of the bond, when the cost is below par. Some short-term securities, such as T-bills and banker’s acceptances, are known as discount securities. They sell at a discount from par, and return the par value to the investor at maturity without additional interest. Other securities, which have fixed coupons, trade at a discount when the coupon rate is lower than the current market rate for securities of that maturity and/or quality.
DIVERSIFICATION. Dividing investment funds among a variety of investments to avoid excessive exposure to any one source of risk.
DURATION. The weighted average time to maturity of a bond where the weights are the present values of the future cash flows. Duration measures the price sensitivity of a bond to changes in interest rates. (See modified duration).
FEDERAL FUNDS RATE. The rate of interest charged by banks for short-term loans to other banks. The Federal Reserve Bank through open-market operations establishes it.
ISSUER. The entity identified as the counterparty or obligator related to a security trade.
INVERSE FLOATER. A bond or other type of debt whose coupon rate has an inverse relationship to a benchmark rate.
INVESTMENT OFFICIALS. This includes any applicable SDCP staff participating in the investment process; SDCP Treasurer; SDCP Deputy Treasurer(s); and SDCP Board of Directors.
LEVERAGE. Borrowing funds in order to invest in securities that have the potential to pay earnings at a rate higher than the cost of borrowing.
LIQUID. Term for securities that can be converted to cash quickly.
LIQUIDITY. The speed and ease with which an asset can be converted to cash. 180
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LOCAL AGENCY INVESTMENT FUND (LAIF). A voluntary investment fund open to government entities and certain non-profit organizations in California that is managed by the State Treasurer’s Office.
LOCAL GOVERNMENT INVESTMENT POOL. Investment pools that range from the State Treasurer’s Office Local Agency Investment Fund (LAIF) to county pools, to Joint Powers Authorities (JPAs). These funds are not subject to the same SEC rules applicable to money market mutual funds.
MARGIN. The difference between the market value of a security and the loan a broker makes using that security as collateral.
MARKET RISK. The risk that the value of securities will fluctuate with changes in overall market conditions or interest rates.
MARKET VALUE. The price at which a security can be traded.
MATURITY. The final date upon which the principal of a security becomes due and payable.
MEDIUM TERM NOTES. Unsecured, investment-grade senior debt securities of major corporations which are sold in relatively small amounts on either a continuous or an intermittent basis. MTNs are highly flexible debt instruments that can be structured to respond to market opportunities or to investor preferences.
MODIFIED DURATION. The percent change in price for a 100 basis point change in yields.
Modified duration is the best single measure of a portfolio’s or security’s exposure to market risk.
MONEY MARKET. The market in which short-term debt instruments (T-bills, discount notes, commercial paper, and banker’s acceptances) are issued and traded.
MORTGAGE BACK SECURITY. Debt obligations that represent claims to the cash flows from pools of mortgage loans, most commonly on residential property.
MORTGAGE-DERIVED INTEREST-ONLY STRIPS. A financial product created by separating the interest and principal payments of a mortgage-backed security.
MORTGAGE PASS-THROUGH SECURITIES. A securitized participation in the interest and principal cash flows from a specified pool of mortgages. Principal and interest payments made on the mortgages are passed through to the holder of the security.
MUNICIPAL SECURITIES. Securities issued by state and local agencies to finance capital and operating expenses.
MUTUAL FUND. An entity which pools the funds of investors and invests those funds in a set of securities which is specifically defined in the fund’s prospectus. Mutual funds can be invested in various types of domestic and/or international stocks, bonds, and money market 181
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instruments, as set forth in the individual fund’s prospectus. For most large, institutional investors, the costs associated with investing in mutual funds are higher than the investor can obtain through an individually managed portfolio.
NATIONALLY RECOGNIZED STATISTICAL RATING ORGANIZATION (NRSRO). A credit rating agency that the Securities and Exchange Commission in the United States uses for regulatory purposes. Credit rating agencies provide assessments of an investment's risk. The issuers of investments, especially debt securities, pay credit rating agencies to provide them with ratings. The three most prominent NRSROs are Fitch, S&P, and Moody's.
NEGOTIABLE CD. A short-term debt instrument that pays interest and is issued by a bank, savings or federal association, state or federal credit union, or state-licensed branch of a foreign bank. Negotiable CDs are traded in a secondary market and are payable upon order to the bearer or initial depositor (investor).
PREMIUM. The difference between the par value of a bond and the cost of the bond, when the cost is above par.
RANGE NOTES. A structured investment where the coupon is linked to the performance of a reference index
REPURCHASE AGREEMENT. Short-term purchases of securities with a simultaneous agreement to sell the securities back at a higher price. From the seller’s point of view, the same transaction is a reverse repurchase agreement.
SAFEKEEPING. A service to bank customers whereby securities are held by the bank in the customer’s name.
SUPRANATIONAL. A Supranational is a multi-national organization whereby member states transcend national boundaries or interests to share in the decision making to promote economic development in the member countries.
TOTAL RATE OF RETURN. A measure of a portfolio’s performance over time. It is the internal rate of return, which equates the beginning value of the portfolio with the ending value; it includes interest earnings, realized and unrealized gains, and losses in the portfolio.
U.S. TREASURY OBLIGATIONS. Securities issued by the U.S. Treasury and backed by the full faith and credit of the United States. Treasuries are considered to have no credit risk, and are the benchmark for interest rates on all other securities in the US and overseas. The Treasury issues both discounted securities and fixed coupon notes and bonds.
TREASURY BILLS. All securities issued with initial maturities of one year or less are issued as discounted instruments, and are called Treasury bills. The Treasury currently issues three- and six-month T-bills at regular weekly auctions. It also issues “cash management” bills as needed to smooth out cash flows.
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TREASURY NOTES. All securities issued with initial maturities of two to ten years are called Treasury notes, and pay interest semi-annually.
TREASURY BONDS. All securities issued with initial maturities greater than ten years are called Treasury bonds. Like Treasury notes, they pay interest semi-annually.
VOLATILITY. The rate at which security prices change with changes in general economic conditions or the general level of interest rates.
YIELD TO MATURITY. The annualized internal rate of return on an investment which equates the expected cash flows from the investment to its cost. 183
SAN DIEGO COMMUNITY POWER
Staff Report – Item 13
TO: Board of Directors
FROM: Maricela Hernandez, Clerk of the Board
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Adopt Resolution No. 2025-12, Approving Updates to San Diego Community Power’s (Community Power) Public Records Request Policy Pursuant to the California Public Records Act (CPRA) Recodification Act, Assembly Bill 473 (AB 473)
DATE: August 28, 2025
RECOMMENDATION:
Adopt Resolution No. 2025-12, approving updates to Community Power’s Public Records Request Policy (Policy).
BACKGROUND:
The Board of Directors adopted its first Public Records Request Policy on July 23, 2020.
In 2021, the legislature enacted the California Public Records Act (CPRA) Recodification Act, AB 473. This Act, effective January 1, 2023, renumbered and reorganized the PRA in a new Division 614 of the Government Code (GC), beginning at section 7920.005. AB 473 was not intended to substantially change the law relating to inspection or production of public records.
The new Policy encompasses changes to relevant GC sections and minimal clerical updates.
FISCAL IMPACT:
None
STRATEGIC PLAN:
This policy furthers the Strategic Planning goal of continuing to enhance policies to meet or exceed best practices.
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ATTACHMENTS:
A: Resolution No. 2025-12, Approving Update to Community Power’s Public Records Request Policy
Exhibit A: Public Records Request Policy – redlined
Exhibit B: Public Records Request Policy – clean version 185
ITEM 13
ATTACHMENT A
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RESOLUTION NO. 2025-12
A RESOLUTION OF THE BOARD OF DIRECTORS OF SAN
DIEGO COMMUNITY POWER, UPDATING ITS PUBLIC
RECORDS REQUESTS POLICY PURSUANT TO ASSEMBLY
BILL 473 (AB 473).
A. San Diego Community Power (Community Power) is a joint powers agency formed pursuant to the Joint Exercise of Powers Act (Cal. Gov. Code § 6500 et seq.), California Public Utilities Code § 366.2, and a Joint Powers Agreement effective on October 1, 2019, and amended and restated December 16, 2021 (JPA Agreement).
B. The California Public Records Act (the PRA) was enacted in 1968 to: (1) safeguard the accountability of government to the public; (2) promote maximum disclosure of the conduct of governmental operations; and (3) explicitly acknowledge the principle that secrecy is antithetical to a democratic system of “government of the people, by the people and for the people.
C. On July 23, 2020, the Board of Directors adopted its initial Public Records Request Policy.
D. In 2021, the legislature enacted the California Public Records Act (CPRA) Recodification Act, AB 473. This Act, effective January 1, 2023, renumbered and reorganized the PRA in a new Division 614 of the Government Code (GC), beginning at section 7920.005. AB 473 was not intended to substantially change the law relating to inspection or production of public records.
NOW, THEREFORE, BE IT RESOLVED by the Board of Directors of San Diego Community Power as follows:
Section 1. The Board of Directors wish to update Community Power’s Public Records Requests Policy, attached as an exhibit to this Resolution, with the new Government Code sections to comply with AB 473.
Section 2. This Resolution shall take effect immediately upon its adoption.
PASSED AND ADOPTED at a meeting of the Board of Directors of San Diego Community Power held on August 28, 2025.
AYES:
NOES:
ABSTAIN:
ABSENT:
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__________________________________________
, Chair
Board of Directors
San Diego Community Power
ATTEST: APPROVED AS TO FORM:
___________________________ ___________________________ Maricela Hernandez, MMC, CPMC Veera Tyagi, General Counsel Clerk of the Board/Board Secretary San Diego Community Power San Diego Community Power
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ITEM 13
EXHIBIT A
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San Diego Community Power
Public Records Request Policy
Purpose
This Public Records Request Policy (Policy) sets forth San Diego Community Power’s (Community Power) policies and procedures for handling requests to inspect and/or copy public records. This Policy is intended to comply with the California Public Records Act (PRA) (Gov. Code § 7920.0006250 et seq.) and all applicable laws pertaining to disclosure of public records. If any provision of this Policy conflicts with applicable state or federal law, the applicable law shall prevail.
Policy
1. Definitions
As used in this Policy, the following terms shall have the following meanings:
(a) "Person" means any natural person, corporation, partnership, limited liability company, firm, or association.
(b) "Public records" means any writing containing information relating to the conduct of Community PowerSDCP’s business prepared, owned, used, or retained by Community Power SDCP regardless of physical form or characteristics; provided, however, that such writings may be exempt from disclosure and/or deemed not to be “public records” pursuant to this Policy and the Public Records Act (Government Code § 7920.0006250 et seq.).
(c) "Requester" shall mean a person, or representative of a person, who has submitted a request for records to Community Power SDCP by mail, fax, e-mail, telephone or in person.
(d) " Community Power SDCP" means San Diego Community Power. (e) "Writing" means any handwriting, typewriting, printing, photostating, photographingying, photocopying, transmitting by electronic mail or facsimile, and every other means of recording upon any tangible thing, any form of communication or representation, including letters, words, pictures, sounds, or symbols, or combinations thereof, and any record thereby created, regardless of the manner in which the record has been stored.
2. Requests to Inspect and/or Make Copies
a. General. Disclosable public records of Community Power SDCP are open to inspection and copies of disclosable public records may be obtained by any person 190
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at all times during the normal business hours of Community Power SDCP offices in accordance with this Policy and the Public Records ActPRA (Government Code § 6250 7920.000 et seq.). All requests for records must be submitted to SDCP’s Community Power’s Clerk of the Board Secretary or his/ or hertheir designee. during normal business hours when of Community Power SDCP offices are open. (Gov. Code § 7922.525 and 7922.505,6253, subds (a), (e).). Any request for records and any responsive records may be subject to review by Community PowerSDCP’s legal General Counsel counsel prior to any inspection of the records or delivery of copies. Payment of fees is required before any copies are prepared and/or transmitted, as noted in Section 5 below.
c. Written Requests. Community Power SDCP encourages members of the public to submit requests in writing to Community Power SDCP offices, preferably using the Public Record Request Fform (PRRF) attached as Exhibit “A” to this Policy, and as may be amended from time to time, to reduce misunderstandings and allow Community Power SDCP staff to timely respond with greater efficiency. The applicable fees are set forth in Exhibit “B.” T he PRRF and applicable fees are also available online at https://sdcommunitypower.org/. SDCP staff will explain the public records request procedures, explain any applicable fees, and transmit Exhibits “A” and “B” to the requester.
b.
d.c.Oral Requests. Community Power SDCP will not deny a request solely because it is not submitted in writing. Oral requests for records (in person or by telephone) are encouraged to be directed to will only be accepted through the Community Power SDCP Clerk of the Board Secretary or his or /hertheir designee during normal business hours when SDCP offices are open. Community Power SDCP personnel in other departments who receive oral requests for records will should direct the requester to contact Community PowerSDCP’s Clerk of the Board Secretary or his or /hertheir designee. The Clerk of the Board Secretary or his or /hertheir designee will explain the records request procedure, describe applicable fees, and fill outcomplete a Public Records Request form to document the request (Exhibit “A”).
e.d.d. Requests Should Clearly Identify RecordsReasonably Describe an Identifiable Record or Records. The requester should specify the records to be inspected and/or copied with reasonably sufficient detail to enable staff to identify particular records. If the request seems ambiguous or unfocused, Community Power SDCP staff members will make a reasonable effort to obtain additional clarifying information from the requester that will help identify a record or records. Pursuant to Government Code Section 7922.6080, 7922.700- 7922.7256253.1, Community Power SDCP staff members shall do all of the following, to the extent reasonable under the circumstances:
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i. Assist the member of the publicrequester to identify records and information that are responsive to the request or to the purpose of the request, if stated;
ii. Describe the information technology and physical location in which the records exist; and
iii. Provide suggestions for overcoming any practical basis for denying access to the records or information sought.
3. Determination on Records Request; Time Extensions
Upon a request to inspect or copy records, Community Power SDCP staff shall, within ten (10) days from receipt of the request, determine whether the request, in whole or in part, seeks disclosable public records in the possession of Community PowerSDCP. Community Power SDCP staff members shall promptly notify the person making the requestrequester of Community PowerSDCP’s determination and the reasons for the determination. In unusual circumstances, the time limit for providing the determination on a records request may be extended by written notice to the person making the request, setting forth the reasons for the extension and the date on which a determination is expected to be provided. Any extension of time to make a determination will not last exceed more than fourteen (14) calendar days. A response to a written request for inspection or copies of public records that includes a determination that the request is denied, in whole or in part, shall be in writing and shall include the reason for the denial. As used in this Policy and pursuant to Government Code section 7922.5325 6253, subdivision (c), “unusual circumstances” means the following, but only to the extent reasonably necessary to the proper processing of the particular request:
(a) The need to search for and collect the requested records from field facilities or other establishments that are separate from the office processing the request. (b) The need to search for, collect, and appropriately examine a voluminous amount of separate and distinct records that are demanded in a single request. (c) The need for consultation, which shall be conducted with all practicable speed, with another agency having substantial interest in the determination of the request or among two or more components of SDCP Community Power having substantial subject matter interest therein.
(d) The need to compile data, to write programming language or a computer program, or to construct a computer report to extract data. 192
-4-
4. Records Exempt from Disclosure
Under the PRA, Certain certain records may be exempt from disclosure to the public by law. Exempt records include, but are not limited to, the following:
a. Preliminary drafts, notes, interagency, or intra-agency memoranda which are not retained by SDCP Community Power in the ordinary course of business, provided that the public interest in withholding such records clearly outweighs the public interest in disclosure. (Gov. Code § 7927.5006254, subd. (a).).) b. Records pertaining to pending litigation to which SDCP Community Power is a party, or to claims made pursuant to Division 3.6 (commencing with Section 810) of Title 1 of the Government Code, until such pending litigation or claim has been finally adjudicated or otherwise settled. (Gov. Code § 7927.2006254, subd. (b).).) c. Personnel, medical, or similar files, the disclosure of which would constitute an unwarranted invasion of personal privacy. (Gov. Code § 7927.7008.215-7928.225 6354, subd. (c).).
d. Geological and geophysical data, plant production data, and similar information relating to utility systems development, or market or crop reports, that are obtained in confidence from any person. (Gov. Code § 7924.3005,6254, subd. (e).).
e. The contents of real estate appraisals, engineering or feasibility estimates, and evaluations made for or by SDCP Community Power relative to the acquisition of property, or to prospective public supply and construction contracts, until all of the property has been acquired or all of the contract agreements are obtained; provided that the law of eminent domain shall not be affected by this provision. (Gov. Code § 7928.7056254, subd. (h).).
f. Records the disclosure of which is exempt or prohibited pursuant to federal or state law (e.g., attorney-client privilege under the California Evidence Code). (Gov.
Code § 7927.7056254, subd. (k).).
g. The name, credit history, utility usage data, home address, or telephone number of utility customers of SDCPCommunity Power, except that disclosure of name, utility usage data, and the home address of utility customers of SDCP Community Power shall be made available upon request as follows:
i. To an agent or authorized family member of the person to whom the information pertains.
ii. To an officer or employee of another governmental agency when necessary for the performance of its official duties.
193
-5-
iii. Upon court order or the request of a law enforcement agency relative to an ongoing investigation.
iv. Upon determination by SDCP Community Power that the utility customer who is the subject of the request has used utility services in a manner inconsistent with applicable local utility usage policies. v. Upon determination by Community Power SDCP that the utility customer who is the subject of the request is an elected or appointed official with authority to determine the utility usage policies of Community PowerSDCP, provided that the home address of an appointed official shall not be disclosed without his or her consent.
v.
vi. h. Upon determination by the local agency that the public interest in disclosure of the information clearly outweighs the public interest in nondisclosure. (Gov. Code § 7927.4106254.16.).
h. i. Computer software developed by a state or local agency is not itself a public record. (Gov. Code § 7922.585, subds. (a), (b)6254.9.). i. The records made, if any, of closed sessions, along with any confidential information that has been acquired by being present in a closed session, are not public records subject to inspection, to the extent permitted by the Ralph M. Brown Act and the Public Records Act. (Gov. Code §§ 54957.2, 54963.).
i.
j. Information security records (records that reveal vulnerabilities to, or otherwise increase the potential for an attack on, an information technology system of a public agency) (e.g., a “cyber attack”). (Gov. Code § 7929.215.6254.19.). j.
k. Social security numbers – State law requires local agencies to redact social security numbers from records before disclosing such records to the public. (Gov. Code § 6254.297922.200.).
k.
l. Records for which SDCP Community Power determines, based on the facts of the particular case, that the public interest served by not disclosing the record clearly outweighs the public interest served by disclosure of the record. (Gov. Code § 62557922.000, subd. (a).).
194
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The above-noted partial list of exemptions is subject to existing State and federal law, and any changes, additional exemptions, and/or provisions for not considering records as public records in the law are automatically incorporated into this Policy.
Any disclosable portion of a record that can be reasonably separated from portions of the record that are exempt by law shall be made available for inspection and/or copying after the exempt portions have been redacted.
m. Payment of Fees for Copies
SDCP Community Power shall charge fees for copies or certified copies of identifiable public records or information as set forth in Exhibit "B." Copies of requested records will be provided after payment of fees is received by Community PowerSDCP. Any person in attendance at an inspection of Community Power SDCP records may request a copy of any disclosable record being inspected. Upon payment of the applicable fees, Community PowerSDCP’s Clerk of the Board Secretary or his or /her designee will prepare copies of the requested records. If a large number of copies is requested after a records inspection, Community Power SDCP staff may require reasonable additional time to make the requested copies.
195
EXHIBIT "A"
PUBLIC RECORD REQUEST FORM
Date of Request:_____________________
In accordance with the California Public Records Act (Gov. Code § 7920.000 6250 et seq.), I am requesting to (check one):
inspect the following public records receive copies of the following public records Requests may be submitted to
[email protected]@sdcommunitypower.org or (858) 492-6005. [Please provide sufficient detail to assist in locating the public records you are seeking] Type of Record(s): ______________________________________________________________ Date or Date Range of Records:_Records:
____________________________________________________
Additional Information:
I understand that SDCP Community Power will respond to all Public Records Act requests in compliance with State law.
For copies of public records, I understand Community PowerSDCP’s copying fees will apply or statutory fees for copying may apply. I understand that I will be responsible for payment of all copying fees in advance of delivery of any requested copies. I also understand that Community Power SDCP has ten (10) days to determine if the request seeks disclosable records in Community PowerSDCP’s possession. In some instances, the time may be extended by written notice if additional time is required to search for and collect the requested information. If more than fifty (50) pages are requested, Community Power SDCP may require a deposit before making copies.
Name/Signature of Requester
(Optional):_____________________________________________ Address:
______
E-Mail:__________________________________________________________________ 196
Phone:__________________________________________________________________ 197
DRAFT
EXHIBIT "B"
PUBLIC RECORDS REQUEST
SCHEDULE OF SDCP COMMUNITY POWER COPYING FEES
Description Price
Black & White Copy Price per Page – Standard Letter Size (Size (8 1/2" x 11")
10¢ per page
Color Copy Price per Page – Standard Letter Size (Size (8 1/2" x 11")
25¢ per page
Copy charges for oversized or other documents/formats that must be outsourced for duplication/reproduction
Actual cost
Price for public records in electronic format, including DVD of public meetings, when requested in electronic format, shall be calculated by SDCP Community Power in accordance with
Government Code Section 7922.5756253.9, as it may be
amended from time to time.
Per Gov. Code
Section
7922.5756253.
9 Note : Payment is required in advance of delivery of any requested records.
All fees are in compliance with SDCP’s Community Power’s fee schedule and are subject to change as the fee schedule is updated.
198
ITEM 13
EXHIBIT B
199
BOARD POLICY
Policy Public Records Requests Original Adoption Date July 23, 2020 Approval Date August 28, 2025 Resolution No. 2025-12
PURPOSE:
This Public Records Request Policy (Policy) sets forth San Diego Community Power’s (Community Power) policies and procedures for handling requests to inspect and/or copy public records. This Policy is intended to comply with the California Public Records Act (PRA) (Gov. Code § 7920.000 et seq.) and all applicable laws pertaining to disclosure of public records. If any provision of this Policy conflicts with applicable state or federal law, the applicable law shall prevail.
POLICY:
1. Definitions
As used in this Policy, the following terms shall have the following meanings:
(a) "Person" means any natural person, corporation, partnership, limited liability company, firm, or association.
(b) "Public records" means any writing containing information relating to the conduct of Community Power’s business prepared, owned, used, or retained by Community Power regardless of physical form or characteristics; provided, however, that such writings may be exempt from disclosure and/or deemed not to be “public records” pursuant to this Policy and the Public Records Act.
(c) "Requester" shall mean a person, or representative of a person, who has submitted a request for records to Community Power by mail, fax, e-mail, telephone or in person.
(d) "Community Power " means San Diego Community Power. (e) "Writing" means any handwriting, typewriting, printing, photostating, photographing, photocopying, transmitting by electronic mail or facsimile, and every other means of recording upon any tangible thing, any form of communication or representation, including letters, words, pictures, sounds, or symbols, or combinations thereof, and any record thereby created, regardless of the manner in which the record has been stored.
2. Requests to Inspect and/or Make Copies
(a) General. Disclosable public records of Community Power are open to inspection and copies of disclosable public records may be obtained by any person at all times during the normal business hours of Community Power in accordance with this Policy and the PRA All requests for records must be submitted to Community Power’s Clerk of the Board or their designee. Any 200
request for records and any responsive records may be subject to review by Community Power’s General Counsel prior to any inspection of the records or delivery of copies. Payment of fees is required before any copies are prepared and/or transmitted, as noted in Section 5 below. (b) Written Requests. Community Power encourages members of the public to submit requests in writing to Community Power, preferably using the Public Record Request Form (PRRF) attached as Exhibit “A” to this Policy, and as may be amended from time to time, to reduce misunderstandings and allow Community Power staff to timely respond with greater efficiency.
The applicable fees are set forth in Exhibit “B.” The PRRF and applicable fees are also available online at https://sdcommunitypower.org/. (c) Oral Requests. Community Power will not deny a request solely because it is not submitted in writing. Oral requests for records (in person or by telephone) are encouraged to be directed to the Community Power Clerk of the Board or their designee during normal business hours. Community Power personnel in other departments who receive oral requests for records should direct the requester to contact Community Power’s Clerk of the Board or their designee. The Clerk of the Board or their designee will explain the records request procedure, describe applicable fees, and complete a Public Records Request form to document the request (Exhibit “A”).
(d) Requests Should Reasonably Describe an Identifiable Record or Records.
The requester should specify the records to be inspected and/or copied with reasonably sufficient detail to enable staff to identify particular records. If the request seems ambiguous or unfocused, Community Power staff will make a reasonable effort to obtain additional clarifying information from the requester that will help identify a record or records. Pursuant to Government Code Section 7922.600, Community Power shall do all of the following, to the extent reasonable under the circumstances:
i. Assist requester to identify records and information that are responsive to the request or to the purpose of the request, if stated; ii. Describe the information technology and physical location in which the records exist; and
iii. Provide suggestions for overcoming any practical basis for denying access to the records or information sought.
3. Determination on Records Request; Time Extensions
Upon a request to inspect or copy records, Community Power shall, within ten (10) days from receipt of the request, determine whether the request, in whole or in part, seeks disclosable public records in the possession of Community Power.
Community Power shall promptly notify the requester of Community Power’s 201
determination and the reasons for the determination. In unusual circumstances, the time limit for providing the determination on a records request may be extended by written notice to the person making the request, setting forth the reasons for the extension and the date on which a determination is expected to be provided. Any extension of time to make a determination will not exceed more than fourteen (14) calendar days. A response to a written request for inspection or copies of public records that includes a determination that the request is denied, in whole or in part, shall be in writing and shall include the reason for the denial. As used in this Policy and pursuant to Government Code section 7922.535, “unusual circumstances” means the following, but only to the extent reasonably necessary to the proper processing of the particular request:
(a) The need to search for and collect the requested records from field facilities or other establishments that are separate from the office processing the request.
(b) The need to search for, collect, and appropriately examine a voluminous amount of separate and distinct records that are demanded in a single request.
(c) The need for consultation, which shall be conducted with all practicable speed, with another agency having substantial interest in the determination of the request or among two or more components of Community Power having substantial subject matter interest therein.
(d) The need to compile data, to write programming language or a computer program, or to construct a computer report to extract data.
4. Records Exempt from Disclosure
Under the PRA, certain records may be exempt from disclosure to the public.
Exempt records include, but are not limited to, the following:
(a) Preliminary drafts, notes, interagency, or intra-agency memoranda which are not retained by Community Power in the ordinary course of business, provided that the public interest in withholding such records clearly outweighs the public interest in disclosure. (Gov. Code § 7927.500.) (b) Records pertaining to pending litigation to which Community Power is a party, or to claims made pursuant to Division 3.6 (commencing with Section 810) of Title 1 of the Government Code, until such pending litigation or claim has been finally adjudicated or otherwise settled. (Gov. Code § 7927.200.) (c) Personnel, medical, or similar files, the disclosure of which would constitute an unwarranted invasion of personal privacy (Gov. Code § 7927.700) (d) Geological and geophysical data, plant production data, and similar information relating to utility systems development, or market or crop 202
reports, that are obtained in confidence from any person (Gov. Code § 7924.300).
(e) The contents of real estate appraisals, engineering or feasibility estimates, and evaluations made for or by Community Power relative to the acquisition of property, or to prospective public supply and construction contracts, until all of the property has been acquired or all of the contract agreements are obtained; provided that the law of eminent domain shall not be affected by this provision (Gov. Code § 7928.705).
(f) Records the disclosure of which is exempt or prohibited pursuant to federal or state law (e.g., attorney-client privilege under the California Evidence Code) (Gov. Code § 7927.705).
(g) The name, credit history, utility usage data, home address, or telephone number of utility customers of Community Power, except that disclosure of name, utility usage data, and the home address of utility customers of Community Power shall be made available upon request as follows:
i. To an agent or authorized family member of the person to whom the information pertains.
ii. To an officer or employee of another governmental agency when necessary for the performance of its official duties.
iii. Upon court order or the request of a law enforcement agency relative to an ongoing investigation.
iv. Upon determination by Community Power that the utility customer who is the subject of the request has used utility services in a manner inconsistent with applicable local utility usage policies. v. Upon determination by Community Power that the utility customer who is the subject of the request is an elected or appointed official with authority to determine the utility usage policies of Community Power, provided that the home address of an appointed official shall not be disclosed without his or her consent.
vi. Upon determination by the local agency that the public interest in disclosure of the information clearly outweighs the public interest in nondisclosure (Gov. Code § 7927.410).
(h) Computer software developed by a state or local agency is not itself a public record (Gov. Code § 7922.585).
(i) The records made, if any, of closed sessions, along with any confidential information that has been acquired by being present in a closed session, are not public records subject to inspection, to the extent permitted by the Ralph M. Brown Act and the Public Records Act (Gov. Code §§ 54957.2, 54963).
203
(j) Information security records (records that reveal vulnerabilities to, or otherwise increase the potential for an attack on, an information technology system of a public agency) (e.g., a “cyber attack”) (Gov. Code § 7929.215). (k) Social security numbers – State law requires local agencies to redact social security numbers from records before disclosing such records to the public (Gov. Code § 7922.200).
(l) Records for which Community Power determines, based on the facts of the particular case, that the public interest served by not disclosing the record clearly outweighs the public interest served by disclosure of the record (Gov. Code § 7922.000).
The above-noted partial list of exemptions is subject to existing State and federal law, and any changes, additional exemptions, and/or provisions for not considering records as public records in the law are automatically incorporated into this Policy.
Any disclosable portion of a record that can be reasonably separated from portions of the record that are exempt by law shall be made available for inspection and/or copying after the exempt portions have been redacted.
5. Payment of Fees for Copies
Community Power shall charge fees for copies or certified copies of identifiable public records or information as set forth in Exhibit "B." Copies of requested records will be provided after payment of fees is received by Community Power. Any person in attendance at an inspection of Community Power records may request a copy of any disclosable record being inspected. Upon payment of the applicable fees, Community Power’s Clerk of the Board or his/her designee will prepare copies of the requested records. If a large number of copies is requested after a records inspection, Community Power staff may require reasonable additional time to make the requested copies.
Prior Versions:
Date Action Resolution No. Policy No.
July 23, 2020 Adoption N/A 2020-05
204
EXHIBIT "A"
PUBLIC RECORD REQUEST FORM
Date of Request:_____________________
In accordance with the California Public Records Act (Gov. Code § 7920.000 et seq.), I am requesting to (check one):
¨ inspect the following public records ¨ receive copies of the following public records Requests may be submitted to [email protected]. [Please provide sufficient detail to assist in locating the public records you are seeking] Type of Record(s):
______________________________________________________________ Date or Date Range of Records:
____________________________________________________
Additional Information:
I understand that Community Power will respond to all Public Records Act requests in compliance with State law.
For copies of public records, I understand Community Power’s copying fees will apply or statutory fees for copying may apply. I understand that I will be responsible for payment of all copying fees in advance of delivery of any requested copies. I also understand that Community Power has ten (10) days to determine if the request seeks disclosable records in Community Power’s possession. In some instances, the time may be extended by written notice if additional time is required to search for and collect the requested information. If more than fifty (50) pages are requested, Community Power may require a deposit before making copies.
Name of Requester:______________________________________________________ Address: ______________________________________________________________ E-Mail:________________________________________________________________ Phone:________________________________________________________________ 205
EXHIBIT "B"
PUBLIC RECORDS REQUEST
SCHEDULE OF COMMUNITY POWER COPYING FEES
Description Price
Black & White Copy Price per Page – Standard Letter
Size (8 1/2" x 11")
10¢ per page
Color Copy Price per Page – Standard Letter Size (8
1/2" x 11")
25¢ per page
Copy charges for oversized or other
documents/formats that must be outsourced for
duplication/reproduction
Actual cost
Price for public records in electronic format, including DVD of public meetings, when requested in electronic
format, shall be calculated by Community Power in
accordance with Government Code Section 7922.575,
as it may be amended from time to time.
Per Gov.
Code
Section
7922.575
Note: Payment is required in advance of delivery of any requested records.
All fees are in compliance with Community Power’s fee schedule and are subject to change as the fee schedule is updated.
206
SAN DIEGO COMMUNITY POWER
Staff Report – Item 14
TO: Board of Directors
FROM: Veera Tyagi, General Counsel
SUBJECT: Election of Officer(s) for the Remainder of Calendar Year 2025 DATE: August 28, 2025
RECOMMENDATION:
Declare the office of the Chair vacant and elect a Chair and, if necessary, a Vice Chair for the remainder of the 2025 calendar year.
BACKGROUND:
Section 5.2 of Community Power’s Joint Powers Agreement (JPA) and Article IV of Community Power’s Bylaws provide that the Board of Directors will annually elect a Chair and Vice Chair from among its members during the first meeting of each calendar year.
The JPA further provides that if the position of Chair or Vice Chair becomes vacant during the term for specified reasons that include a change in representation from a member agency, the Board shall declare the position vacant and make a new selection.
Former Chair Aguirre was elected to serve as a member of the Board of Supervisors effective July 22, 2025, resigning the Director position representing the City of Imperial Beach. Therefore, the position of Chair is vacant and a new Chair needs to be selected.
In the event the Vice Chair is elected as the Chair, a new election will also need to be made for the position of Vice Chair. The position(s) will serve until the first meeting of calendar year 2026. There is no limit on the number of terms the Chair or Vice Chair may serve.
FISCAL IMPACT:
None
STRATEGIC PLAN:
Not Applicable
ATTACHMENTS:
None
207
SAN DIEGO COMMUNITY POWER
Staff Report – Item 15
______________________________________________________________________ TO: Board of Directors
FROM: Chandra Pugh, Senior Director of People Operations and Administrative Services
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Adoption of Resolution No. 2025-10, Requesting CalPERS to Authorize the Division Vote of Community Power Employees to Participate in Social Security, and Upon Receiving Authorization, Authorize Community Power to Conduct the Division Vote
DATE: August 28, 2025
______________________________________________________________________ RECOMMENDATION:
Adoption of Resolution No. 2025-10, requesting CalPERS to authorize the division vote of Community Power employees to participate in Social Security and for Community Power to conduct the division vote upon receiving said authorization.
BACKGROUND:
Community Power and employees have been contributing to Social Security since the agency’s inception. In 2021, a 401(a) plan was established to which Community Power contributes an amount equal to 10% of the employee’s salary for the employee’s benefit.
To continue Social Security participation, Community Power needs a Section 218 Agreement with the Social Security Administration (SSA) in order to cover former, present, and future employees. In California, the Section 218 Agreement is administered through CalPERS. Community Power is working closely with CalPERS to put a Section 218 Agreement in place.
ANALYSIS AND DISCUSSION:
To establish a Section 218 Agreement covering Community Power employees, a division vote will be conducted in which current employees can opt in or opt out of Social Security at that time.
• “Opt in” means the employee stays in Social Security – status quo • “Opt out” means the employee will no longer participate in Social Security 208
Former employees and future employees will be opted into Social Security as long as at least one employee opts in. To initiate the process, CalPERS requires Board adoption of Resolution No. 2025-10, which requests CalPERS to authorize the division vote and upon receiving authorization, authorizing Community Power to conduct the vote after providing proper notice to eligible employees. After Board adoption of the resolution, eligible employees will be provided at least 90 days’ notice for the vote.
FISCAL IMPACT:
One-time fee: There is a one-time fee of $650 to establish the Section 218 Agreement.
Annual Fee: An annual fee will also apply, which may vary each fiscal year based on the number of employees reported to CALPERS but is expected to be approximately $200 per year.
COMMITTEE REVIEW:
This item was presented to the Finance and Risk Management Committee at their August 21 meeting. Committee members recommend Board adoption of Resolution No. 2025-10 Requesting CalPERS to Authorize the Division Vote of Community Power Employees to Participate in Social Security and Upon Receiving Authorization, Authorize Community Power to Conduct the Division Vote.
STRATEGIC PLAN:
Not Applicable.
ATTACHMENTS:
A: Resolution No. 2025-10 Requesting CalPERS to Authorize the Division Vote of Community Power Employees to Participate in Social Security and Upon Receiving Authorization, Authorize Community Power to Conduct the Division Vote 209
ITEM 15
ATTACHMENT A
210
RESOLUTION NO. 2025-10
A RESOLUTION OF THE BOARD OF DIRECTORS OF SAN DIEGO
COMMUNITY POWER, ESTABLISHING A "DEEMED" RETIREMENT
SYSTEM PURSUANT TO SECTION 218(D)(6) OF THE FEDERAL SOCIAL
SECURITY ACT COMPOSED OF POSITIONS OF MEMBERS OF THE SAN
DIEGO COMMUNITY POWER MONEY PURCHASE PLAN BY EMPOWER
RETIREMENT HEREINAFTER DESIGNATED AS "PRESENT
RETIREMENT SYSTEM."
WHEREAS, the San Diego Community Power hereinafter designated as "Public Agency", desires to establish a "deemed" retirement system pursuant to Section 218(d)(6) of the Federal Social Security Act composed of positions of members of the San Diego Community Power Money Purchase Plan by Empower Retirement hereinafter designated as "Present Retirement System", desiring coverage, and to include services performed by individuals employed by the Public Agency in positions covered by said "deemed" retirement system, as members of a coverage group established by Section 218(d)(4) of said Act, in the California State Social Security Agreement of March 9, 1951, providing for the coverage of public employees under the insurance system established by said Act as amended; and
WHEREAS, State and Federal law and regulations require, as a condition of such coverage, that a division be authorized by the Board of Administration, Public Employees' Retirement System; and
WHEREAS, it is necessary that the "Public Agency" now designate any services which it desires to exclude from coverage with respect to such coverage group under said insurance system; and
WHEREAS, it is necessary for the Public Agency to set forth the modification, if any, of the benefits and contributions under the Present Retirement System that may result from coverage under the said insurance system with respect to such coverage group;
NOW, THEREFORE, BE IT RESOLVED, that the Board of Administration, Public Employees' Retirement System, be and hereby is requested to authorize the foregoing division; and
BE IT FURTHER RESOLVED, that upon receipt of authorization from the Board of Administration a division shall be conducted in accordance with the requirements of Section 218(d) of the Social Security Act, and applicable State and Federal laws and regulations; that each eligible member of the Present Retirement System at the time of the division shall be furnished a form to permit the member to elect whether or not his services should be excluded from or included under the said California State Social Security Agreement as 211
hereinbefore provided; with such coverage effective as to services performed on and after January 1, 2021; and
BE IT FURTHER RESOLVED, that the following services with respect to said coverage group of the Public Agency shall be excluded from coverage under said agreement:
1. All services excluded from coverage under the agreement by Section 218 of the Social Security Act; and
2. Services excluded by option of the Public Agency (Check a. or b.; fill in part b if checked):
a. No optional exclusions desired.
b. Service performed:
BE IT FURTHER RESOLVED, that with respect to the said coverage group the benefits and contributions of the Present Retirement System shall not be modified in any way; and
BE IT FURTHER RESOLVED, that notice of the division shall be given to members of the Present System not less than ninety days prior to the date of the division; provided, however, that notice shall be given to employees becoming members of the Present Retirement System after the date of such notice up to and including the date of the division on the date on which they attain membership in the system; and that San Diego Community Power is hereby designated and appointed to conduct such division on behalf of the Public Agency in accordance with law, regulations, and this resolution, including the fixing of the date and the giving of proper notice thereof to members of the Present Retirement System and to all such eligible employees; and 212
BE IT FURTHER RESOLVED, that the Public Agency will pay and reimburse the State at such time and in such amounts as may be determined by the State the approximate cost of any and all work and services relating to such division.
PASSED, APPROVED AND ADOPTED at a meeting of the Board of Directors of San Diego Community Power held on August 28, 2025, with the following vote.
AYES:
NOES:
ABSTAINED:
ABSENT:
_____________________________
, Chair
Board of Directors
San Diego Community Power
ATTEST: APPROVED AS TO FORM:
________________________________ ______________________________ Maricela Hernandez, MMC, CPMC Veera Tyagi, General Counsel Clerk of the Board/Secretary San Diego Community Power
San Diego Community Power
CERTIFICATION
I, Maricela Hernandez, Secretary of the San Diego Community Power Board of Directors, State of California, do hereby certify the foregoing to be a full, true, and correct copy of Resolution No. 2025-__ adopted by the San Diego Community Power Board of Directors of the San Diego Community Power at the regular meeting held on the 28th day of August, 2025, as the same appears of record in my office.
Signature
Secretary, San Diego Community Power Board of
Directors
Title
Date
213
SAN DIEGO COMMUNITY POWER
Staff Report – Item 16
______________________________________________________________________ TO: Board of Directors
FROM: Veera Tyagi, General Counsel
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Adopt Resolution No. 2025-11 Establishing and Approving a Claims Procedures Policy
DATE: August 28, 2025
______________________________________________________________________ RECOMMENDATION:
Adopt Resolution No. 2025-11, establishing and approving a Claims Procedures Policy.
BACKGROUND:
The California Government Claims Act (the “Act”) specifies the process and time for bringing claims against public entities as a prerequisite to filing a lawsuit. (Govt. Code Sections 900 et seq.) Most claims are governed by the Act, which means a claimant must first present the claim to Community Power in a manner and within the time period set forth in the Act before it can file a lawsuit against Community Power. However, there are some claims that are specifically exempted or are not otherwise governed by any other statute or regulation. This means that for those types of claims, a plaintiff may directly file a lawsuit against Community Power without the prerequisite of first filing a claim against Community Power. Examples of such claims are claims by the State or other public agencies against Community Power, employee claims for wages, benefits, or other expenses or allowances, and claims under the Revenue and Taxation Code or other statute for the refund, rebate, exemption, cancellation, amendment, modification or adjustment of any tax, assessment, fee, penalties, costs or charges. The Act, however, authorizes a local public agency to adopt a policy that would govern claims that are specifically exempted under the Act or are not otherwise governed by any other statute or regulation. (Government Code Section 935.)
ANALYSIS AND DISCUSSION:
Staff recommends that the Board adopt the attached Resolution that would establish a Claims Procedures Policy (“Policy”). The Policy would: (1) require claims that are specifically exempted by the Act or are not otherwise governed by statute or regulation be presented in the same manner and within the same time period as contained in the 214
Act, (2) require that all claims must be presented pursuant to the Policy as a prerequisite to any lawsuit against Community Power or its employees acting within the course and scope of their employment, (3) require that claims and application for late claims be presented to the Clerk of the Board, and (4) authorize the Chief Executive Officer and General Counsel to take all appropriate and necessary actions to process claims against Community Power, including rejecting insufficient claims, returning untimely claims, action on applications for leave to present late claims and, subject to their settlement authority (if applicable), approving or rejecting claims.
There are no current claims or circumstance that require the enactment of this Policy, but it is being presented as a matter of good governance and as a cautionary measure so that Community Power can have the same opportunity to timely investigate, settle meritorious claims prior to the filing lawsuit (if appropriate), or to make appropriate fiscal planning decisions for those claims specifically exempted by the Act or are not otherwise governed by any other statute or regulation, as it would for those claims that are governed by the Act.
FISCAL IMPACT:
N/A
STRATEGIC PLAN:
Continue to enhance and implement financial controls and policies to meet or exceed best practices - including contracting, risk management, and procurement.
ATTACHMENTS:
Attachment A – Resolution No. 2025-11 Establishing and Approving a Claims Procedures Policy Pursuant to Government Code Section 935
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ITEM 16
ATTACHMENT A
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RESOLUTION NO. 2025-11
A RESOLUTION OF THE BOARD OF DIRECTORS OF SAN DIEGO
COMMUNITY POWER, ESTABLISHING AND APPROVING A CLAIMS
PROCEDURES POLICY PURSUANT TO GOVERNMENT CODE
SECTION 935.
A. San Diego Community Power (Community Power) is a joint powers agency formed pursuant to the Joint Exercise of Powers Act (Cal. Gov. Code § 6500 et seq.), California Public Utilities Code § 366.2, and a Joint Powers Agreement effective on October 1, 2019, and amended and restated December 16, 2021 (JPA Agreement); and
B. The Government Claims Act (Government Code Section 900 et seq.) (hereinafter “Act”) sets forth the general procedures for the presentation of claims as a prerequisite to commencing any action for money or damages against local public entities; and
C. The Act excepts certain claims against local public entities from the presentation procedures of the Act; and
D. The Act also specifies that local public entities may adopt a procedure for claims excepted under the Act and which are not governed by any other statutes or regulations; and
E. All claims for money or damages against Community Power or its employees acting within the course and scope of their employment, which are not otherwise governed by the Act or any other state statute or regulation, may be governed by a regulation adopted in accordance with Government Code section 935; and F. The Board of Directors now desires to adopt a procedure to govern the presentation requirements of those excepted claims to establish a claims procedures pursuant to Government Code Section 935.
NOW, THEREFORE, BE IT RESOLVED by the Board of Directors of San Diego Community Power as follows:
Section 1. The Board of Directors hereby approves and adopts a Claims Procedures Policy, as provided in Exhibit A, attached hereto and incorporated herein.
Section 2. If any provision of this resolution, the attached policy, or the application thereof to any person or circumstance is held invalid, such invalidity shall not affect other provisions or applications of the resolution or policy which can be given effect without the invalid provision or application, and to this end the provisions of this resolution and the policy are severable. The Board of Directors hereby declares that it would have adopted 217
this resolution and the attached policy irrespective of the invalidity of any particular portion thereof.
Section 3. This resolution shall take effect immediately upon its adoption.
PASSED AND ADOPTED at a meeting of the Board of Directors of San Diego Community Power held on August 28, 2025.
AYES:
NOES:
ABSTAIN:
ABSENT:
__________________________________________
, Chair
Board of Directors
San Diego Community Power
ATTEST: APPROVED AS TO FORM:
___________________________ ___________________________ Maricela Hernandez, MMC, CPMC Veera Tyagi, General Counsel Clerk of the Board/Board Secretary San Diego Community Power San Diego Community Power
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ITEM 16
EXHIBIT A
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BOARD POLICY
Policy Claims Procedure Original Adoption Date August 28, 2025 Approval Date August 28, 2025 Resolution No. 2025-11
Claims Procedures Policy
PURPOSE:
The purpose of this Claims Procedures Policy (“Policy”) is to establish the requirements for the presentation of claims for money or damages not otherwise governed by statute or regulation against San Diego Community Power (“Community Power”) or its employees acting within the scope and course of their employment, pursuant to Section 935 of the Government Code.
POLICY:
1. The requirements of this Policy and the procedures contained in the Government Claims Act (commencing in Government Code Section 900 et seq.) shall apply to claims exempted from the Act by Section 905 of the Government Code and any claims not otherwise governed by statute or regulation.
2. All claims must be presented pursuant to this Policy as a prerequisite to any lawsuit or legal action against Community Power or its employees acting within the scope and course of their employment.
3. Claims shall be presented to Community Power’s Clerk of the Board in a form prepared by Community Power. Applications for leave to present a late claim shall also be presented to the Clerk of the Board. Claims and applications for leave to present a late claim may be presented to the Clerk of the Board electronically in a manner prescribed by Community Power.
4. The Chief Executive Officer and General Counsel and their designees are authorized to take all appropriate and necessary actions to process claims against Community Power. These actions shall include, but are not limited to, rejecting insufficient claims, returning untimely claims, acting on applications for leave to present late claims, and subject to their settlement authority, approving or rejecting claims.
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SAN DIEGO COMMUNITY POWER
Staff Report – Item 17
______________________________________________________________________ TO: Board of Directors
FROM: Dr. Eric Washington, Chief Financial Officer
Tim Manglicmot, Director of Finance
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Adoption of Resolution No. 2025-09, Approving a Disposal of Surplus Property Policy
DATE: August 28, 2025
______________________________________________________________________ RECOMMENDATION:
Adoption of Resolution No. 2025-09, approving a Disposal of Surplus Property Policy.
BACKGROUND:
On October 1, 2019, the Founding Members of San Diego Community Power (Community Power) adopted the Joint Powers Agreement (JPA) which was amended and restated on December 16, 2021.
Section 3.2.12 of the JPA specifies that the Community Power Board of Directors (Board) may at its discretion adopt rules, regulations, policies, bylaws and procedures governing the operation of Community Power.
Further, Section 4.5.5 of the JPA states that one of the general purposes of the Board is to set policy.
ANALYSIS AND DISCUSSION:
An analysis of policies identified the need to adopt a policy governing the disposal of surplus property. Surplus property is defined broadly as all furniture, equipment, or other tangible assets owned by Community Power that is determined by the Chief Executive Officer (CEO) to be obsolete, damaged, or no longer useable by Community Power.
Under the proposed policy, the Chief Executive Officer (CEO) shall review an annual list of surplus property and ensure its disposal in accordance with this policy. Disposal of property valued at $25,000 or more at the time of surplus will be approved by the Board of Directors. Property valued below $25,000 will be disposed on the approval of the CEO, 221
and property considered de minimis in value, which is defined as below $500, can be disposed without any formal process.
The methods of disposal may include auction, direct donation, recycling, or as regular waste. All disposal of individual Surplus Property that is not of de minimis value must be recorded and reported to the Board. Any proceeds from the disposition of the Surplus Property are required to be deposited into Community Power’s operating budget.
FISCAL IMPACT:
N/A
COMMITTEE REVIEW:
This item was presented to the Finance and Risk Management Committee at their August 21 meeting. Committee members recommended Board adoption of Resolution No. 2025- 09, approving Disposal of Surplus Property Policy.
STRATEGIC PLAN:
This policy furthers the Strategic Planning goal of continuing to enhance financial controls and policies to meet or exceed best practices, including contracting, risk management, and procurement.
ATTACHMENTS:
Attachment A: Resolution No. 2025-09, approving Disposal of Surplus Property Policy Exhibit A: Community Power Disposal of Surplus Property Policy 222
ITEM 17
ATTACHMENT A
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RESOLUTION NO. 2025-09
A RESOLUTION OF THE BOARD OF DIRECTORS OF SAN DIEGO
COMMUNITY POWER (COMMUNITY POWER), ESTABLISHING
PROCEDURES FOR DISPOSAL OF SURPLUS PROPERTY
OWNED BY COMMUNITY POWER.
A. San Diego Community Power (Community Power) is a joint powers agency formed pursuant to the Joint Exercise of Powers Act (Cal. Gov. Code § 6500 et seq.), California Public Utilities Code § 366.2, and a Joint Powers Agreement effective on October 1, 2019, and amended and restated December 16, 2021 (JPA Agreement).
B. Pursuant to Section 3.2, Specific Powers, of the JPA Agreement, specific powers of Community Power shall include, but not be limited to, each of the following powers, which may be exercised at the discretion of the Board:
3.2.4, the Board may acquire property for electric generation/interconnection purposes by eminent domain, or otherwise, except as limited under Section 6508 of the Act and Sections 3.6 and 4.12.3 of this Agreement, and to hold or dispose of any property; provided, however, SDCP shall not exercise the power of eminent domain within the jurisdiction of a Party over its objection.
C. Surplus Property is defined as all furniture, equipment or other tangible assets owned by Community Power that is determined by the Chief Executive Officer to be obsolete, damaged, or no longer usable by Community Power.
D. On an annual basis, Community Power shall review and inventory all property and equipment to compile a listing of property, for presentation to the CEO, as Surplus Property. The CEO will review the listing of Surplus Property and ensure the disposal of the Surplus Property in accordance with this Policy.
NOW, THEREFORE, BE IT RESOLVED, by the Board of Directors of Community Power as follows:
Section 1. The Board of Directors of Community Power wishes to establish a Disposal of Surplus Property Policy attached as an exhibit to this Resolution.
Section 2. This resolution shall take effect immediately upon its adoption. 224
PASSED AND ADOPTED at a meeting of the Board of Directors of San Diego Community Power held on August 28, 2025.
AYES:
NOES:
ABSTAIN:
ABSENT:
__________________________________________
,Chair
Board of Directors
San Diego Community Power
ATTEST: APPROVED AS TO FORM:
___________________________ ___________________________ Maricela Hernandez, MMC, CPMC Veera Tyagi, General Counsel Clerk of the Board/Board Secretary San Diego Community Power San Diego Community Power
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ITEM 17
EXHIBIT A
226
BOARD POLICY
Policy Disposal of Surplus Property Original Adoption Date August 28, 2025 Approval Date August 28, 2025 Resolution No. 2025-009
PURPOSE AND SCOPE:
This policy establishes the requirements for disposal of Surplus Property owned by San Diego Community Power (“Community Power”).
DEFINITIONS:
Surplus Property is defined as all furniture, equipment, or other tangible assets owned by Community Power that is determined by the Chief Executive Officer (CEO) to be obsolete, damaged, or no longer useable by Community Power.
POLICY STATEMENT:
On an annual basis, Community Power shall review and inventory all property and equipment to compile a listing of property, for presentation to the CEO, as Surplus Property. The CEO will review the listing of Surplus Property and ensure the disposal of the Surplus Property in accordance with this Policy.
CATEGORIES OF SURPLUS PROPERTY:
1. Property Valued at $25,000 or more. For Surplus Property that is a capital asset and has, individually, an estimated market value exceeding $25,000 or more at the time of surplus, disposal of such property must be approved by the Board of Directors of Community Power. Upon approval, the CEO may dispose of such property from the methods listed below, taking into consideration the type of property, condition of the property, and circumstances under which disposal is deemed necessary, provided that the CEO shall, within a reasonable period of time, provide a report back to the Board regarding such disposal at a regular meeting.
2. Property Valued Under $25,000. The CEO will determine how to dispose of individual Surplus Property with an estimated market value of less than $25,000 at the time of surplus, from the methods listed below, taking into consideration the type of property, condition of the property, and circumstances under which disposal is deemed necessary. To the extent any Surplus Property is not capitalized by Community Power accounting, then such Surplus Property shall be presumed to fall within this category. The CEO shall, within a reasonable period of time, provide a report to the Board regarding such disposal at a regular meeting. 227
3. Property of De Minimis Value. For property of de minimis value, Community Power staff shall be able to recycle or discard such property from time to time if Community Power staff deems such property to be obsolete, damaged, or no longer useable by Community Power. For purposes of this Policy, “property of de minimis value” means any individual property with value of less than $500 such as used office supplies or kitchen supplies.
METHODS TO DISPOSE OF SURPLUS PROPERTY:
1. Auction. Sale by auction or direct solicitation of bids.
2. Direct Donation. Donation of Surplus Property directly to any California public institution, including but not limited to, public libraries, school districts, or interested 501(c)(3) charities.
3. Certain Electronic Equipment. Surplus electronic equipment such as hard drives and other recordable media (rewritable and non-rewritable) will not be included in any auction, direct donation, or other routine means of disposing of equipment (e.g., E-waste recycling, etc.) without proper sanitization. a. All hard drives and other rewriteable media shall be sanitized according to US Department of Defense (“DoD”) data sanitization standard (DoD 5220.22-M).
b. Community Power IT staff will physically destroy, or make arrangements for the physical destruction of, any rewritable and non-rewriteable media such as CDs, DVDs, and USB Drives.
4. E-waste Recycling. Computers, monitors, DVD players, fax machines, and other types of electronic products may be E-waste recycled.
5. Other Recycling. If the Surplus Property cannot be reused by a third party, it should be recycled, if possible. If the Surplus Property cannot be reused or recycled, then it shall be discarded (see also Property of De Minimis Value section above).
DOCUMENTATION AND PROCEEDS FROM THE SALE OF SURPLUS PROPERTY:
1. Documentation. For the disposal of all property that is not of de minimis value, Community Power staff will indicate on a Disposal of Surplus Property form that said item has been deemed Surplus Property and will include, at a minimum, the description of disposition method, date of the disposition, and any proceeds from said 228
disposition. This form and related supporting documents should be submitted to the Finance Department for the timely updating of property inventory and accounting records.
2. Proceeds. The proceeds from the sale of any Surplus Property will be deposited into the Community Power Operating Fund and accounted for in accordance with Generally Accepted Accounting Principles.
Prior Versions:
N/A
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SAN DIEGO COMMUNITY POWER
Staff Report – Item 18
TO: Board of Directors
FROM: Gordon Samuel, Chief Commercial Officer
Andrea Torres, Director of Origination
VIA: Karin Burns, Chief Executive Officer
SUBJECT: Approve Renewable Power Purchase Agreement with IP Darden IV, LLC
DATE: August 28, 2025
RECOMMENDATION:
Approve the proposed Renewable Power Purchase Agreement (“PPA”) for a 91.48 MW solar and 91.48 MW, 4-hour battery energy storage facility, with IP Darden IV, LLC, for a term of up to 12 years, in substantially final form and authorize the Chief Executive Officer to execute the PPA.
BACKGROUND:
As San Diego Community Power (Community Power) strives to meet its environmental, financial, and regulatory compliance goals and requirements, long-term power purchase agreements (PPAs) of at least 10 years in duration are integral components of its energy supply portfolio. Long-term PPAs provide renewable generation facility developers with a certain revenue stream against which they can finance up-front capital requirements, so each long-term PPA that Community Power signs with a developing facility will underpin a new, incremental renewable energy project, while locking in renewable energy supply and capacity for Community Power’s portfolio.
Moreover, the California Renewable Portfolio Standard (RPS), as modified in 2015 by Senate Bill 350, requires that Community Power provide 65% of its RPS-required renewable energy from contracts of at least ten years in length. Finally, in D.21-06-025, the California Public Utilities Commission (CPUC) required each Load Serving Entity (LSE) in California to make long-term purchase commitments for resource adequacy from new, incremental generation facilities that will achieve commercial operation during 2023 through 2026.
The proposed PPA is for capacity and renewable energy benefits from a 91.48 MW solar and 91.48 MW, 4-hour battery energy storage facility (referred to as “Darden IV” or “Project”) with IP Darden IV, LLC, a subsidiary of Intersect Power. The PPA originated from an offer Community Power received in 2024 via its 2024 All-Source Request for 230
Offers (RFO). Community Power engaged with Intersect Power after shortlisting the project and has reached terms mutually agreeable to both parties.
ANALYSIS AND DISCUSSION:
Staff negotiated the attached PPA for the purchase of renewable energy and resource adequacy from the Darden IV project, which is a solar-plus-battery-storage project to be developed, constructed, and operated in Fresno, California by Intersect Power.
Darden IV is part of a larger 1,1,48 MW Darden Facility developed by Intersect Power.
Community Power’s portion of the project will have a guaranteed capacity of 91.48 MW of solar production and 91.48 MW of battery storage capacity. Below is additional information regarding Intersect Power, the project and the PPA.
Background on Intersect Power:
• Founded in 2016 Intersect Power has an operating portfolio of 2.2 GW solar PV and 2.4 GWh of battery storage. 1.7 GW of PV and 1.4 GWh of storage are successfully operating in California
• Intersect Power is funded by investments from TPG Rise Climate, Climate Adaptive Infrastructure, and Greenbelt Capital Partners, with plans to raise additional equity in the near future.
• Intersect Power’s supply chain strategy focuses heavily on securing a high percentage of domestic content via ethical supply chains. The strategy supports reinvestment in the domestic energy transition economy and mitigates supply chain related risks and delays for projects
Project Overview:
• Project: 91.48 MW solar PV, 91.48 MW/365.92 MWh lithium-ion battery energy system.
• Project location: Fresno County, California, which is the only Community Power PPA located in Northern California. This provides locational diversity to our portfolio, which is important from an energy market perspective to mitigate the locational effects of grid congestion and operational risks. • Contract term: Up to 12 years
• Expected annual energy production: approximately 265,000 MWhs • Guaranteed energy production: 85% of projected annual deliveries • Pricing:
• Solar – Fixed energy price applicable to the full term of the PPA (with no allowances for price adjustments due to the loss of tax credits or tariff impacts).
• BESS – Fixed capacity price adjusted for availability and verified capacity (with no allowances for price adjustments due to the loss of tax credits or tariff impacts).
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• Community Power would receive financial compensation in the event of seller’s failure to successfully achieve certain development milestones as well as seller’s failure to meet the guaranteed energy production from the solar facility and failure to meet guaranteed efficiency from the storage facility once the project is operational.
• In addition to tariff and tax credit protections in the PPA, the Project is materially derisked compared to other project offerings out in the market because the Project has:
• Secured deliverability from CAISO to ensure the Project can provide resource adequacy
• Secured its conditional use permit
• Secured its interconnection agreement
Workforce Development:
• Intersect Power will execute a 5-craft Project Labor Agreement (PLA), requiring the Project’s engineering procurement and construction contractor to utilize all-union labor for the Project. • The larger Darden project will employ approximately 1,600 construction jobs and 14 permanent jobs.
Community Benefits:
• Intersect Power will contribute $100,000 to Community Power’s Community Benefits Fund.
• Over the next decade, Intersect Power will invest over $2 million in western Fresno County community initiatives (the local community to the Project) as part of the Darden Clean Energy Project’s Community Benefits Plan. Focused on education and economic opportunity, transportation, air quality, housing, and healthy foods, this plan was shaped through research, local input, and a thorough resource assessment. The Intersect Power team will meet with partner organizations annually to plan for the upcoming year, receive feedback and reporting on the prior year’s programming, and to discuss opportunities for expanded involvement by Intersect Power employees, including participation in local volunteer projects.
COMMITTEE REVIEW:
Key terms of this PPA were reviewed with the Energy Contract Working Group (ECWG) in June and August of 2025, and the ECWG recommended to move forward with such terms.
232
FISCAL IMPACT:
The competitive energy and capacity pricing of the PPA are confidential, but the long-term purchase of renewable energy and capacity will provide Community Power with significant value and cost certainty over the term of this PPA.
STRATEGIC PLAN:
This project ties to two of the strategic plan goals for the Power Services team:
1. Develop a clean energy portfolio with renewable content of 100% no later than 2035, with interim targets of 75% by 2027 and 85% by 2030; and
2. Prudently manage the power portfolio to minimize risk and customer costs ATTACHMENTS:
A: Renewable Power Purchase Agreement with IP Darden IV, LLC (redacted version for commercially sensitive information)
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ARTICLE 1 DEFINITIONS ....................................................................................................... 1
1.1 Contract Definitions ............................................................................................... 1
1.2 Rules of Interpretation ......................................................................................... 31 ARTICLE 2 TERM; CONDITIONS PRECEDENT.............................................................. 32
2.1 Contract Term ...................................................................................................... 32
2.2 Commercial Operation; Conditions Precedent .................................................... 32
2.3 Development; Construction; Progress Reports .................................................... 34
2.4 Remedial Action Plan .......................................................................................... 34
2.5 Pre-Commercial Operation Actions ..................................................................... 35
2.7 Delivery Term Update ......................................................................................... 35 ARTICLE 3 PURCHASE AND SALE .................................................................................... 36
3.1 Purchase and Sale of Product ............................................................................... 36
3.2 Sale of Green Attributes ....................................................................................... 36
3.3 Imbalance Energy ................................................................................................ 36
3.4 Ownership of Renewable Energy Incentives ....................................................... 37
3.5 Future Environmental Attributes ......................................................................... 37
3.6 Test Energy .......................................................................................................... 37
3.7 Capacity Attributes .............................................................................................. 38
3.8 Resource Adequacy Failure ................................................................................. 38
3.9 CEC Certification and Verification ..................................................................... 39
3.10 Ancillary Services ................................................................................................ 39
3.11 California Renewables Portfolio Standard ........................................................... 39
3.12 Compliance Expenditure Cap .............................................................................. 40
3.13 Project Configuration ........................................................................................... 42
3.14 Buyer’s Re-Sale of Product ................................................................................. 42 ARTICLE 4 OBLIGATIONS AND DELIVERIES................................................................ 43
4.1 Delivery................................................................................................................ 43
4.2 Title and Risk of Loss .......................................................................................... 43
4.3 Interconnection .................................................................................................... 43
4.4 Forecasting ........................................................................................................... 44
4.5 Dispatch Down/Curtailment ................................................................................ 45
4.6 Energy Management ............................................................................................ 46
4.7 Storage Availability Notices ................................................................................ 49
4.8 Outages ................................................................................................................ 50
4.9 Guaranteed Energy Production ............................................................................ 51
4.10 Storage Availability and Efficiency Rate ............................................................ 52
4.11 Storage Capacity Tests ......................................................................................... 52
4.12 Testing Costs and Revenues ................................................................................ 53
4.13 WREGIS .............................................................................................................. 54
4.14 Green-E Certification ........................................................................................... 55 ARTICLE 5 TAXES .................................................................................................................. 56 238
5.1 Allocation of Taxes and Charges ......................................................................... 56
5.2 Cooperation .......................................................................................................... 56 ARTICLE 6 OPERATION AND MAINTENANCE OF THE FACILITY ......................... 56
6.1 Operation and Maintenance of the Facility .......................................................... 56
6.2 Dispatch ............................................................................................................... 57
6.3 Storage Facility Unavailability to Receive Dispatch Notices .............................. 57
6.4 Maintenance of Health and Safety ....................................................................... 57
6.5 Storage Facility Rebalancing ............................................................................... 58
6.6 Shared Facilities ................................................................................................... 58 ARTICLE 7 METERING ......................................................................................................... 58
7.1 Metering ............................................................................................................... 58
7.2 Meter Verification ................................................................................................ 59 ARTICLE 8 INVOICING AND PAYMENT; CREDIT ........................................................ 59
8.1 Invoicing .............................................................................................................. 59
8.2 Payment................................................................................................................ 60
8.3 Books and Records .............................................................................................. 60
8.4 Invoice Adjustments ............................................................................................ 60
8.5 Billing Disputes ................................................................................................... 61
8.6 Netting of Payments ............................................................................................. 61
8.7 Seller’s Development Security ............................................................................ 61
8.8 Seller’s Performance Security .............................................................................. 62
8.9 First Priority Security Interest in Cash or Cash Equivalent Collateral ................ 62
8.10 Provision of Financial Statements ........................................................................ 63 ARTICLE 9 NOTICES ............................................................................................................. 63
9.1 Addresses for the Delivery of Notices ................................................................. 63
9.2 Acceptable Means of Delivering Notice .............................................................. 63 ARTICLE 10 FORCE MAJEURE........................................................................................... 64
10.1 Definition ............................................................................................................. 64
10.2 No Liability If a Force Majeure Event Occurs .................................................... 65
10.3 Notice of Force Majeure Event ............................................................................ 65
10.4 Termination Following Force Majeure Event ...................................................... 66 ARTICLE 11 DEFAULTS; REMEDIES; TERMINATION ................................................ 66
11.1 Events of Default ................................................................................................. 66
11.2 Remedies; Declaration of Early Termination Date .............................................. 69
11.3 Damage Payment; Termination Payment ............................................................ 70
11.4 Notice of Payment of Termination Payment or Damage Payment ...................... 71
11.5 Disputes With Respect to Termination Payment or Damage Payment ............... 71
11.6 Seller Pre-COD Liability Limitations .................................................................. 71
11.7 Limitation on Seller’s Ability to Make or Agree to Third-Party Sales from the Facility after Early Termination Date ............................................................ 71
11.8 Rights And Remedies Are Cumulative ................................................................ 72 239
11.9 Mitigation ............................................................................................................. 72 ARTICLE 12 LIMITATION OF LIABILITY AND EXCLUSION OF
WARRANTIES .................................................................................................. 72
12.1 No Consequential Damages ................................................................................. 72
12.2 Waiver and Exclusion of Other Damages ............................................................ 72 ARTICLE 13 REPRESENTATIONS AND WARRANTIES; AUTHORITY ..................... 74
13.1 Seller’s Representations and Warranties ............................................................. 74
13.2 Seller’s Covenants ............................................................................................... 74
13.3 Buyer’s Representations and Warranties ............................................................. 74
13.4 General Covenants ............................................................................................... 75
13.5 Prevailing Wage ................................................................................................... 76
13.6 Workforce Development and Supplier Diversity ................................................ 76
13.7 Community Benefits ............................................................................................ 76 ARTICLE 14 ASSIGNMENT .................................................................................................. 76
14.1 General Prohibition on Assignments ................................................................... 76
14.2 Collateral Assignment .......................................................................................... 77
14.3 Permitted Assignment by Seller ........................................................................... 77
14.4 Portfolio Financing .............................................................................................. 78
14.5 Permitted Assignment by Buyer .......................................................................... 78 ARTICLE 15 DISPUTE RESOLUTION ................................................................................ 78
15.1 Governing Law; Venue ........................................................................................ 78
15.2 Dispute Resolution ............................................................................................... 79
15.3 Attorneys’ Fees .................................................................................................... 79 ARTICLE 16 INDEMNIFICATION ....................................................................................... 79
16.1 Indemnification .................................................................................................... 79
16.2 Claims .................................................................................................................. 80 ARTICLE 17 INSURANCE...................................................................................................... 80
17.1 Insurance .............................................................................................................. 80 ARTICLE 18 CONFIDENTIAL INFORMATION ............................................................... 82
18.1 Definition of Confidential Information ................................................................ 82
18.2 Duty to Maintain Confidentiality ......................................................................... 82
18.3 Requested Confidential Information .................................................................... 83
18.4 Irreparable Injury; Remedies ............................................................................... 83
18.5 Further Permitted Disclosure ............................................................................... 83
18.6 Press Releases ...................................................................................................... 84 ARTICLE 19 MISCELLANEOUS .......................................................................................... 84
19.1 Entire Agreement; Integration; Exhibits .............................................................. 84
19.2 Amendments ........................................................................................................ 84
19.3 No Waiver ............................................................................................................ 84
19.4 No Agency, Partnership, Joint Venture or Lease ................................................. 84 240
19.5 Severability .......................................................................................................... 85
19.6 Mobile-Sierra ....................................................................................................... 85
19.7 Counterparts ......................................................................................................... 85
19.8 Electronic Delivery .............................................................................................. 85
19.9 Binding Effect ...................................................................................................... 85
19.10 No Recourse to Members of Buyer ..................................................................... 85
19.11 Forward Contract ................................................................................................. 86
19.12 Further Assurances............................................................................................... 86
19.13 Change in Electric Market Design ....................................................................... 86
19.14 Service Contract ................................................................................................... 86
EXHIBITS
EXHIBIT A FACILITY DESCRIPTION
EXHIBIT B MAJOR PROJECT DEVELOPMENT MILESTONES AND
COMMERCIAL OPERATION
EXHIBIT C COMPENSATION
EXHIBIT D SCHEDULING COORDINATOR RESPONSIBILITIES
EXHIBIT E PROGRESS REPORTING FORM
EXHIBIT F-1 FORM OF AVERAGE EXPECTED ENERGY REPORT
EXHIBIT F-2 FORM OF AVAILABLE GENERATING CAPACITY FORECAST
EXHIBIT G GUARANTEED ENERGY PRODUCTION DAMAGES CALCULATION
EXHIBIT H FORM OF COMMERCIAL OPERATION DATE CERTIFICATE
EXHIBIT I FORM OF INSTALLED CAPACITY AND EFFICIENCY RATE TEST
CERTIFICATE
EXHIBIT J FORM OF CONSTRUCTION START DATE CERTIFICATE
EXHIBIT K FORM OF LETTER OF CREDIT
EXHIBIT L FACILITY OPERATIONS DATA
EXHIBIT M FORM OF REPLACEMENT RA NOTICE
EXHIBIT N NOTICES
EXHIBIT O STORAGE CAPACITY TESTS
EXHIBIT P MONTHLY STORAGE AVAILABILITY CALCULATION
EXHIBIT Q OPERATING RESTRICTIONS
EXHIBIT R METERING DIAGRAM
EXHIBIT S WORKFORCE DEVELOPMENT
EXHIBIT T FORM OF LIMITED ASSIGNMENT AGREEMENT
APPENDIX 1 ASSIGNED RIGHTS AND OBLIGATIONS
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APPENDIX 2 ASSIGNMENT APPENDIX - [A][B][C]
APPENDIX 3 MSCG NOTICE INFORMATION
APPENDIX 4 COPY OF PPA
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RENEWABLE POWER PURCHASE AGREEMENT
This Renewable Power Purchase Agreement (“Agreement”) is entered into as of August ___, 2025 (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, permit, 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
DEFINITIONS1
1.1 Contract Definitions. The following terms, when used herein with initial capitalization, shall have the meanings set forth below:
“AC” means alternating current.
“Accepted Compliance Costs” has the meaning set forth in Section 3.12(e). “Adjusted Energy Production” has the meaning set forth in Exhibit G. “Administrative NQC Reduction” means a reduction in the maximum achievable Net Qualifying Capacity of the Storage Facility able to be shown for each hour of the Resource Duration, that is beyond the reasonable control of and without the fault and negligence of Seller, and for the avoidance of doubt, is not due to any adjustments made by Seller to operations or performance of the Storage Facility, due to a reduction that has been generally applied to resources materially similar to the Storage Facility, in terms of type, market and operational characteristics (including those characteristics specified in the CPUC Master Resource Database), including any 1 NTD: Agreement remains subject to all cross-references and definitions being checked. 243
methodology that incorporates fleet averages or other average outage rates or any changes with respect to storage duration requirements or the elimination of Net Qualifying Capacity altogether (including as a result of being replaced with a successor value for measuring the qualifying capacity of the Storage Facility).
“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”, “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, with respect to Seller, “Affiliates” shall mean Ultimate Parent and its subsidiaries; provided, however, that the term “Affiliate,” when used with respect to Seller shall not include any direct or indirect tax equity investor.
“Agreement” has the meaning set forth in the Preamble and includes the Cover Sheet and any Exhibits, schedules and any written supplements hereto. “Ambient Conditions” means the ambient temperature, relative humidity, solar irradiance, air mass and wind speed at the site.
“Ancillary Services” means all ancillary services associated with the Installed Capacity of the Facility, including spinning reserve, non-spinning reserve, regulation up, regulation down, as each is defined in the CAISO Tariff and any other ancillary services added to this Agreement in accordance with Section 3.10, in each case that the Facility is, at the relevant time, actually physically capable of providing consistent with the Interconnection Agreement, Operating Restrictions, Prudent Operating Practice, and the requirements and limitations set forth in this Agreement.
“Approved Forecast Vendor” means any of (a) the CAISO or (b) any other vendor reasonably acceptable to both Buyer and Seller for the purposes of providing or verifying the forecasts under Section 4.4.
“Automated Dispatches” has the meaning set forth in Section 6.1(c). 244
“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” or “AA” has the meaning set forth in Exhibit P. “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 Generating Capacity” means the capacity of the Generating Facility, expressed in whole MWs, that is mechanically available to generate Energy. “Available Storage Capacity” means the Effective Storage Capacity, expressed in 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.
“Bid” has the meaning as set forth in the CAISO Tariff. “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. Pacific Prevailing Time (PPT).
“Buyer” means San Diego Community Power, a California joint powers authority. “Buyer Bid Curtailment” means the occurrence of both of the following:
(a) the CAISO provides notice to a Party or the Scheduling Coordinator for the Facility, requiring the Party to deliver less Generating Facility Energy than the full amount of Energy forecasted in accordance with Section 4.4 to be produced from the Generating Facility for a period of time;
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Generating Facility Energy, Charging Energy, and Discharging Energy delivered to or from the Delivery Point.
“CAISO Certification” means the certification and testing requirements for a storage unit set forth in the CAISO Tariff that are applicable to the Storage Facility, including certification and testing for all applicable Ancillary Services, PMAX, and PMIN. “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 Storage Facility, whether through ADS, AGC or any successor communication protocol, communicating an Ancillary Service Award (as defined in the CAISO Tariff) or directing the Storage 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 Metered Entity” has the meaning set forth in the CAISO Tariff. “CAISO Operating Order” means the Operating Instruction or Dispatch Instruction 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. “Capacity Attribute” means any current or future defined characteristic, certificate, tag, credit, or accounting construct associated with the amount of power that the Storage Facility can charge, discharge, or deliver to the Delivery Point at a particular moment and that can be purchased and sold under CAISO or CPUC market rules, including Resource Adequacy Benefits. “Capacity Damages” has the meaning set forth in Exhibit B. “Capacity Test” or “CT” means any test or retest of the capacity of the Storage Facility to establish the Efficiency Rate, Installed Storage Capacity, and/or Effective Storage Capacity, as applicable, conducted in accordance with the testing procedures, requirements and protocols set forth in Section 4.11 and Exhibit O.
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“CEC” means the California Energy Commission, or any successor agency performing similar statutory functions.
“CEC Certification and Verification” means that the CEC has certified (or, with respect to periods before the date that is following the Commercial Operation Date, that the CEC has pre-certified) that the Generating Facility is an Eligible Renewable Energy Resource for purposes of the California Renewables Portfolio Standard and that all Generating Facility Energy delivered to the Delivery Point qualifies as generation from an Eligible Renewable Energy Resource.
“CEC Precertification” means that the CEC has issued a precertification for the Generating Facility indicating that the planned operations of the Generating Facility would comply with applicable CEC requirements for CEC Certification and Verification. “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, at least 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 at least 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 cash equity or tax equity provider and any trustee or agent or similar representative thereof acting on their behalf) or assignee or transferee thereof shall be excluded from the total outstanding equity interests in Seller.
“Change in Law” means the enactment, adoption, promulgation, modification, suspension, repeal, or judicial determination, after the Effective Date, by any Governmental Authority of any Law, including a change in interpretation or enforcement of any existing Law. “Charging Energy” means the Energy delivered to the Storage Facility pursuant to a Charging Notice, as measured at the Storage Facility Metering Point by the Storage Facility Meter, as such meter readings are adjusted in a manner approved by the CAISO for any applicable Electrical Losses and Station Use. Subject to Section 4.6(j), all Charging Energy shall be used solely to charge the Storage Facility.
“Charging Notice” means the operating instruction, and any subsequent updates, given by Buyer, Buyer’s SC or the CAISO to the Storage Facility, directing the Storage Facility to charge at a specific MW rate for a specified period of time or to a specified Stored Energy Level; provided, 248
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“Contract Price” has the meaning set forth on the Cover Sheet. The Contract Price is each of the Renewable Rate and the Storage Rate.
“Contract Term” has the meaning set forth in Section 2.1. “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. “Costs” means, with respect to the Non-Defaulting Party, brokerage fees, commissions, breakage, 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 or financed its obligations or entering into new arrangements which replace this Agreement, and all reasonable attorneys’ fees and expenses incurred by the Non-Defaulting Party in connection with terminating this Agreement.
“Cover Sheet” means the cover sheet to this Agreement, which is incorporated into this Agreement.
“CPM Soft Offer Cap” has the meaning set forth in the CAISO Tariff. “CPUC” means the California Public Utilities Commission or any successor agency performing similar statutory functions.
“CPUC Master Resource Database” means the CPUC database of generation, energy storage and other resources qualified to provide Resource Adequacy capacity to load serving entities.
“CPUC System RA Penalty” means the system RAR penalties assessed against load-serving entities by the CPUC for Resource Adequacy Requirement deficiencies that are not replaced or cured, as established 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, which is expected to be updated annually, or any replacement or successor documentation established by the CPUC Energy Division to reflect Resource Adequacy Requirement penalties that are established by the CPUC and assessed against load-serving entities for Resource Adequacy Requirement deficiencies. “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, Fitch or Moody’s. If ratings by S&P, Fitch and Moody’s are not equivalent, the lower rating shall apply. “CRS” has the meaning set forth in Section 4.14.
“Cure Plan” has the meaning set forth in Section 11.1(b)(vi). 250
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Period, as measured at the Storage Facility Metering Point by the Storage Facility Meter, as such meter readings are adjusted in a manner approved by the CAISO for Station Use and Electrical Losses to the Delivery Point.
“Discharging Notice” means the operating instruction, and any subsequent updates, given by Buyer, Buyer’s SC or the CAISO to the Storage Facility, directing the Storage Facility to discharge Discharging Energy at a specific MW rate for a specified period of time or to a specified Stored Energy Level; provided, any such operating instruction or updates shall be in accordance with the Operating Restrictions and the CAISO Tariff. Any Discharging Notice shall not constitute a Buyer Bid Curtailment, Buyer Curtailment Order or Curtailment Order. 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, instructing the Storage Facility to charge or discharge Energy at a specific MWh rate, for a specified period of time, and/or to a specified Stored Energy Level; provided, any such operating instruction or updates shall be in accordance with the Operating Restrictions and the CAISO Tariff. “Early Termination Date” has the meaning set forth in Section 11.2(a). “Effective Date” has the meaning set forth in the Preamble. “Effective Storage Capacity” means the lesser of (a) PMAX, and (b) the maximum dependable operating capacity of the Storage Facility to discharge Energy for the number of hours of continuous discharge corresponding to the Resource Duration, as measured in MW AC at the Delivery Point (i.e., measured at the Storage Facility Meter and adjusted for Electrical Losses to the Delivery Point to the extent such Electrical Losses are not already reflected in the Facility Meter measurements) as determined pursuant to the most recent Storage Capacity Test (including the Commercial Operation Storage Capacity Test, as evidenced by a certificate substantially in the form attached as Exhibit I-2 hereto), in either case (a) or (b) up to but not in excess of (i) the Guaranteed Storage Capacity (with respect to a Commercial Operation Storage Capacity Test) or (ii) the Installed Storage Capacity (with respect to any other Storage Capacity Test). “Efficiency Rate” means the measured round-trip efficiency rate of the Storage Facility, expressed as a percentage, calculated pursuant to a Storage Capacity Test and which for a given calendar month shall be prorated as necessary if more than one Efficiency Rate applies during such calendar month.
“Electrical Losses” means, subject to meeting any applicable CAISO requirements and in accordance with Section 7.1, all transmission or transformation losses (a) between the Generating Facility Metering Point and the Delivery Point associated with delivery of Generating Facility Energy, (b) between the Storage Facility Metering Point and the Delivery Point associated with delivery of Discharging Energy, and (c) between the Delivery Point and the Storage Facility 253
Metering Point associated with delivery of Charging Energy. If any amounts included within the definitions of “Electrical Losses” and “Station Use” hereunder are duplicative, then for all relevant calculations hereunder it is intended that such amounts shall not be double counted or otherwise duplicated.
“Eligible Renewable Energy Resource” or “ERR” has the meaning set forth in California Public Utilities Code Section 399.12(e) and California Public Resources Code Section 25741(a), as either code provision is amended or supplemented from time to time. “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 alternating current electrical energy measured in MWh. “Energy In” has the meaning set forth in Part II.A of Exhibit O. “Energy Out” has the meaning set forth in Part II.A of Exhibit O. “Energy Management System” or “EMS” means the Facility’s energy management system.
“Energy Supply Bid” has the meaning set forth in the CAISO Tariff. “Environmental Costs” means all costs incurred in connection with (i) acquiring and maintaining all environmental permits and licenses for the Facility, (ii) 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, and all operation and maintenance costs for the pollution mitigation or control equipment, (iv) permit maintenance fees and emission fees as applicable including all Emission Reduction Credits or Marketable Emission Trading Credits required by any applicable environmental laws, rules, regulations, and permits to operate the Facility, (vi) the use, release, disposal and clean-up of Hazardous Substances at the Site, and (vi) the decontamination or remediation, on or off the Site, necessitated by the use, storage or release of such Hazardous Substances on the Site. “Event of Default” has the meaning set forth in Section 11.1. “Excess MWh” has the meaning set forth in Exhibit C.
“Excused Event” has the meaning set forth in Exhibit P. 254
“Expected Commercial Operation Date” is the date set forth on the Cover Sheet by which Seller reasonably expects to achieve Commercial Operation “Expected Energy” means the quantity of Generating Facility Energy that Seller expects to be able to deliver to Buyer during each Contract Year or other time period in the quantity specified on the Cover Sheet, which amount shall be adjusted proportionately to the reduction from Guaranteed Generating Capacity to Installed Generating Capacity pursuant to Section 5(a) of Exhibit B, if applicable.
“Facility” means the combined Generating Facility and the Storage Facility. “Facility Energy” means the sum of Generating Facility Energy and Discharging Energy during any Settlement Interval or Settlement Period, net of Electrical Losses and Station Use. If any adjustments for Electrical Losses and Station Use included within the definitions of “Generating Facility Energy” and “Facility Energy” hereunder are duplicative, then for all relevant calculations hereunder it is intended that such amounts shall not be double counted or otherwise duplicated.
“FERC” means the Federal Energy Regulatory Commission, or any successor government agency.
“Financial Close” means Seller or one of its Affiliates has obtained debt, equity financing and/or sale of Tax Credit commitments from one or more Lenders sufficient to construct the Facility, including such financing commitments from Seller's owner(s). “Fitch” means Fitch Ratings Ltd., or its successor.
“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. “Forced Facility Outage” means an unexpected failure of one or more components of the Facility that prevents Seller from generating Energy or making Facility Energy available at the Delivery Point and that is not the result of a Force Majeure Event. “Forecasting Penalty” means for each hour in which Seller does not provide the forecast required in Section 4.4(e) and Buyer incurs a loss resulting from its scheduling activities in such hour with respect to Generating Facility Energy, the product of (a) the absolute difference (if any) between (i) the Expected Energy for such hour (which, for the avoidance of doubt, assumes no Charging Energy or Discharging Energy in such hour) set forth in the Day-Ahead Forecast (or the Monthly Delivery Forecast to the extent no Day-Ahead Forecast was delivered to Buyer, or the annual delivery forecast to the extent no Day-Ahead Forecast or Monthly Delivery Forecast was delivered to Buyer), and (ii) the actual Energy produced by the Generating Facility (absent any 255
Charging Energy and Discharging Energy), multiplied by (b) the absolute value of the Real-Time Price in such hour.
“Full Capacity Deliverability Status” has the meaning set forth in the CAISO Tariff. “Future Environmental Attributes” shall mean any and all generation attributes that become recognized under applicable Law after the Effective Date other than Green Attributes or Renewable Energy Incentives 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 generation of electrical energy by the Generating Facility and its displacement of conventional energy generation. Future Environmental Attributes do not include
Renewable Energy Incentives, investment tax credits or production tax credits associated with the construction or operation of the Facility, or other financial incentives in the form of credits, reductions, or allowances associated with the Facility that are applicable to a state or federal income taxation obligation.
“Gains” means, with respect to any Non-Defaulting 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, which economic benefit (if any) shall be deemed the gain (if any) to such Non-Defaulting Party represented by, (a) if Buyer is the Non-Defaulting Party, the positive difference between the present value of the payments required to be made by Buyer during the remaining Contract Term of this Agreement and the present value of the payments that would be required to be made by Buyer under any transaction(s) replacing this Agreement, and (b) if Seller is the Non-Defaulting Party, the positive difference between the present value of the payments that would be required to be made to, or that would otherwise be received by, Seller under any transaction(s) replacing this Agreement and the present value of the payments required to be made to Seller during the remaining Contract Term of this Agreement. Factors used in determining the economic benefit to a Non-Defaulting 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., SP-15), all of which should be calculated for the remaining Contract Term, and include the value of Green Attributes and Capacity Attributes. “Generating Facility” means the solar photovoltaic generating 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 Generating Facility Energy to the Delivery Point; provided, that the “Generating Facility” does not include the Storage Facility or the Shared Facilities.
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“Generating Facility Energy” means all Energy that is delivered from the Generating Facility to the Delivery Point as measured at the Generating Facility Metering Point by the Generating Facility Meter, as such meter readings are adjusted in a manner approved by the CAISO for Station Use and Electrical Losses to the Delivery Point. “Generating Facility Meter” means the CAISO Approved Meter, along with a 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 Generating Facility Energy delivered to the Generating Facility Metering Point for the purpose of invoicing in accordance with Section 8.1. The Generating Facility may contain multiple measurement devices that will make up the Generating Facility Meter, and, unless otherwise indicated, references to the Generating Facility Meter shall mean all such measurement devices and the aggregated data of all such measurement devices, taken together. “Generating Facility Metering Point” means the location or locations of the Generating Facility Meter shown on Exhibit R.
“GEP Damages” has the meaning set forth in Section 4.9. “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 and CPUC; provided, however, that “Governmental Authority” shall not in any event include any Party. “Green Attributes” means any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation from the Generating Facility and its displacement of conventional energy generation. Green Attributes include but are not limited to Renewable Energy Credits, as well as: (a) any avoided emissions of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO) and other pollutants; (b) any avoided emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to the actual or potential threat of altering the Earth’s climate by trapping heat in the atmosphere; (c) the reporting rights to these avoided emissions, such as Green Tag Reporting Rights. Green Tags are accumulated on a MWh basis and one Green Tag represents the Green Attributes associated with one (1) MWh of Generating Facility Energy. Green Attributes do not include (i) any energy, capacity, reliability or other power attributes from the Facility, (ii) Tax Credits associated with the construction or operation of the Facility and other financial incentives in the form of credits, reductions, or allowances associated with the Facility that are applicable to a state or federal income taxation obligation, or any Renewable Energy Incentives, (iii) fuel-related subsidies or “tipping fees” that may be paid to Seller to accept certain fuels, or local subsidies received by the generator for the destruction of particular preexisting pollutants or the promotion of local environmental benefits, or (iv) Emission Reduction Credits encumbered or used by the Facility for compliance with local, state, or federal operating or air quality permits. 257
Green Attributes under the preceding definition are limited to Green Attributes that exist under applicable Law as of the Effective Date.
“Green Tag Reporting Rights” means the right of a purchaser of renewable energy to report ownership of accumulated “green tags” in compliance with and to the extent permitted by applicable Law and include, without limitation, rights under Section 1605(b) of the Energy Policy Act of 1992, and any present or future federal, state or local certification program or emissions trading program, including pursuant to the WREGIS Operating Rules. “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 Contract Capacity” means the sum of the Guaranteed Generating Capacity and the Guaranteed Storage Capacity.
“Guaranteed Efficiency Rate” means the minimum guaranteed Efficiency Rate of the Storage Facility throughout the Delivery Term, as set forth on the Cover Sheet. “Guaranteed Energy Production” means an amount of Adjusted Energy Production, as measured in MWh, equal to of the total Expected Energy (as set forth on the Cover Sheet) for the applicable Performance Measurement Period. “Guaranteed Generating Capacity” means the generating capacity of the Generating Facility, as measured in MW AC at the Delivery Point, (i.e., measured at the Generating Facility Meter and adjusted for Electrical Losses to the Delivery Point), that Seller commits to install pursuant to this Agreement, as set forth on the Cover Sheet. “Guaranteed Storage Availability” means the minimum guaranteed Monthly Storage Availability of the Storage Facility in each month of the Delivery Term, as set forth on the Cover Sheet.
“Guaranteed Storage Capacity” means maximum dependable operating capability of the Storage Facility to discharge Energy, as measured in MW AC at the Delivery Point (i.e., measured at the Storage Facility Meter and adjusted for Electrical Losses and Station Use to the Delivery Point), for the number of hours of continuous discharge corresponding to the Resource Duration, that Seller commits to install pursuant to this Agreement, as set forth on the Cover Sheet. “Guaranteed Storage RA Amount” means, for any Showing Month, the amount of Qualifying Capacity, expressed in MW, of the Storage Facility, minus Administrative NQC Reduction, that can be shown for each hour of the Resource Duration in the applicable Showing Month.
“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 258
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, Discharging Energy, or Generating Facility Energy, as applicable, deviates from the amount of Scheduled Energy. “Imbalance Reserves” has the meaning set forth in the CAISO Tariff. “Indemnifiable Loss(es)” has the meaning set forth in Section 16.1(a). “Indemnified Party” has the meaning set forth in Section 16.1(a). “Indemnifying Party” has the meaning set forth in Section 16.1(a). “Initial Synchronization” means the commencement of Trial Operations (as defined in the CAISO Tariff).
“Installed Capacity” means the sum of (a) the Installed Generating Capacity and (b) the Installed Storage Capacity.
“Installed Generating Capacity” means the actual generating capacity of the Generating Facility, as measured in MW AC at the Delivery Point (i.e., measured at the Generating Facility Meter and adjusted for Electrical Losses to the Delivery Point), that achieves Commercial Operation (up to but not in excess of the Guaranteed Generating Capacity), adjusted for the on the date of the performance test, and as evidenced by a certificate substantially in the form attached as Exhibit I hereto, as such capacity may be adjusted pursuant to Section 5(a) of Exhibit B.
“Installed Storage Capacity” means the lesser of (a) PMAX, and (b) the maximum dependable operating capability of the Storage Facility to discharge Energy for the number of continuous discharge corresponding to the Resource Duration, as measured in MW AC at the Delivery Point (i.e., measured at the Storage Facility Meter and adjusted for Electrical Losses to the Delivery Point), that achieves Commercial Operation, adjusted for ambient conditions on the date of the performance test, and as evidenced by a certificate substantially in the form attached as Exhibit I hereto, as such capacity may be adjusted pursuant to Section 5(b) of Exhibit B, but, subject to Section 4.15, in either case (a) or (b) up to but not in excess of the Guaranteed Storage Capacity.
“Inter-SC Trade” or “IST” has the meaning set forth in the CAISO Tariff. “Interconnection Agreement” means the interconnection agreement(s) entered into by Seller or Seller’s Affiliate pursuant to which the Facility will be interconnected with the Transmission System, providing for interconnection capacity available or allocable to the Facility 259
at the Interconnection Point that is no less than the Dedicated Interconnection Capacity, 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” means the point at which Interconnection Facilities interconnect with the Transmission System pursuant to the Interconnection Agreement, which point is identified in Exhibit A.
“Interest Rate” has the meaning set forth in Section 8.2. “Interim Deliverability Status” or “IDS” has the meaning set forth in the CAISO Tariff. “Investment Grade Credit Rating” means a Credit Rating of BBB- or higher by S&P or Fitch or Baa3 or higher by Moody’s.
“ITC” means the investment tax credit established pursuant to Section 48 or Section 48E of the United States Internal Revenue Code of 1986, as amended. “Joint Powers Act” means the Joint Exercise of Powers Act of the State of California (California Government Code Section 6500 et seq.).
“Joint Powers Agreement” means that certain Joint Powers Agreement dated October 1, 2019, as amended from time to time, under which Buyer is organized as a Joint Powers Authority in accordance with the Joint Powers Act.
“Law” means any applicable law, statute, rule, regulation, decision, writ, order, decree or judgment, permit, guidance or directive having the force of law or any interpretation or implementation thereof, promulgated or issued by a Governmental Authority. “Lender” means, collectively, any Person (a) providing senior or subordinated development, construction, interim, letter of credit, back leverage or long-term debt, equity or tax equity, tax credit or cash 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 Person 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 260
cost of any of the foregoing obligations and/or (c) participating in a lease financing (including a sale leaseback, pass-through lease 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 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, in a form substantially similar to the letter of credit set forth in Exhibit K.
“Licensed Professional Engineer” means an independent, professional engineer selected by Seller and reasonably acceptable to Buyer, licensed in the State of California. “Limited Assignee” has the meaning set forth in Section 14.4. “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. “Locational Marginal Price” or “LMP” has the meaning set forth in the CAISO Tariff. “Losses” means, with respect to the Non-Defaulting 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, which economic loss (if any) shall be deemed to be the loss (if any) to such Party represented by (a) if Buyer is the Non-Defaulting Party, the positive difference between the present value of the payments that would be required to be made by Buyer under any transaction(s) replacing this Agreement and the present value of the payments required to be made by Buyer during the remaining Contract Term of this Agreement and (b) if Seller is the Non-Defaulting Party, the positive difference between the present value of the payments required to be made to Seller during the remaining Contract Term of this Agreement and the present value of the payments that would be required to be made to, or that would otherwise be received by, Seller under any transaction(s) replacing this Agreement. Factors used in determining economic loss to a Party may include 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., SP-15), all of which should be calculated for the remaining Contract Term and must include the value of Green Attributes, Capacity Attributes, and Renewable Energy Incentives. “Lost Output” means the amount of Generating Facility Energy, expressed in MWh, that the Generating Facility would have produced and delivered to the Delivery Point, but that is not produced by the Generating Facility due to Force Majeure Events, Curtailment Periods, System 261
Emergencies, or Buyer Default. The Lost Output shall be calculated in the same manner as Deemed Delivered Energy is calculated in accordance with the definition thereof. “LSE” means Load Serving Entities.
“Major Equipment” means the Facility’s main power transformers, high voltage circuit breakers, battery energy storage system, modules, trackers, invertors, medium voltage transformers.
“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. “Maximum Charging Capacity” means the maximum power output level, in MW, at which the Storage Facility can be charged, as specified in Exhibit Q. “Maximum Discharging Capacity” means the maximum power output level, in MW, at which the Storage Facility can be discharged, as specified in Exhibit Q. “Maximum Hourly RA Capacity” means, for any Showing Month, the highest hourly quantity of Qualifying Capacity for the Generating Facility in such Showing Month. “Maximum State of Charge” means the maximum State of Charge to which the Storage Facility may be charged, as set forth in Exhibit Q.
“Maximum Stored Energy Level” means the maximum Stored Energy Level the Storage Facility is capable of achieving, expressed in MWh, as set forth in Exhibit Q. “Meter Service Agreement” means “Meter Service Agreement for CAISO Metered Entities” or “Meter Service Agreement for Scheduling Coordinators”, as applicable, as each are defined in the CAISO Tariff.
“Milestones” means the development activities for significant permitting, interconnection, financing and construction milestones set forth on the Cover Sheet. “Minimum Efficiency Rate” means the percentage specified on the Cover Sheet. 262
“Minimum State of Charge” means the minimum State of Charge to which the Storage Facility may be discharged, as set forth in Exhibit Q.
“Minimum Stored Energy Level” means the minimum Stored Energy Level the Storage Facility is capable of achieving, expressed in MWh, as set forth in Exhibit Q. “Monthly Delivery Forecast” has the meaning set forth in Section 4.4(b). “Monthly Product Payment” means the payment required to be made by Buyer to Seller each month of the Delivery Term as compensation for delivered Product, as calculated in accordance with Exhibit C.
“Monthly Storage Availability” has the meaning set forth in Exhibit P. “Monthly Storage Availability Capacity Report” has the meaning set forth in Section 4.7(a).
“Moody’s” means Moody’s Investors Service, Inc, or its successors. “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.
“Negative LMP” means, in any Settlement Period or Settlement Interval, whether in the Day-Ahead Market or Real-Time Market, the LMP at the Facility’s PNode is less than Zero dollars ($0).
“Negative LMP Costs” has the meaning set forth in Exhibit C. “NERC” means the North American Electric Reliability Corporation or any successor entity performing similar functions.
“Net Qualifying Capacity” has the meaning set forth in the CAISO Tariff. “Network Upgrades” means collectively Delivery Network Upgrades and Reliability Network Upgrades.
“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).
“Off-Peak Hour” means any hour that is not an On-Peak Hour. 263
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“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 Content Category 1” or “PCC1” means any Renewable Energy Credit associated with the generation of electricity from an Eligible Renewable Energy Resource consisting of the portfolio content set forth in California Public Utilities Code Section 399.16(b)(1), as may be amended from time to time or as further defined or supplemented by Law.
“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.
“Prevailing Wage Requirement” has the meaning set forth in Section 13.4. “Product” has the meaning set forth on the Cover Sheet. “Progress Report” means a progress report including the items set forth in Exhibit E. “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 utility industry and independent power producers during the relevant time period with respect to grid-interconnected, utility-scale generating facilities with integrated storage in the Western United States, or (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 generating facilities with integrated storage in the Western United States. Prudent Operating Practice includes 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. 265
“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 Deadline Date”
“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 3.8(b). “RA Guarantee Date” means .
“RA Shortfall” has the meaning set forth in Section 3.8(b). “RA Shortfall Amount” means, for a given Showing Month, any Storage RA Shortfall. “RA Shortfall Month” means, for purposes of calculating an RA Deficiency Amount under Section 3.8(b), any Showing Month during the Delivery Term, commencing with the Showing Month that contains the RA Guarantee Date, during which there is a Storage RA Shortfall.
“RA Substitute Capacity” has the meaning set forth in the CAISO Tariff. “Ramp Rate” means the ability of the Storage Facility to change between power output levels, expressed in MWAC/min.
“Real-Time Forecast” means any Notice of any change to the Available Generating Capacity or hourly expected Energy delivered by or on behalf of Seller pursuant to Section 4.4(d). “Real-Time Market” has the meaning set forth in the CAISO Tariff. “Real-Time Price” means the Resource-Specific Settlement Interval LMP as defined in the CAISO Tariff. If there is more than one applicable Real-Time Price for the same period of time, Real-Time Price shall mean the price associated with the smallest time interval. “Receiving Party” has the meaning set forth in Section 18.2. “Recurring Certificate Transfers” has the meaning set forth in Section 4.13(a). “Reliability Network Upgrades” has the meaning set forth in the CAISO Tariff. “Remedial Action Plan” has the meaning set forth in Section 2.4. 266
“Renewable Energy Credit” has the meaning set forth in California Public Utilities Code Section 399.12(h), as may be amended from time to time or as further defined or supplemented by Law.
“Renewable Energy Incentives” means: (a) all federal, state, or local Tax Credits or other Tax benefits (including cash grants) associated with the construction, ownership, or production of Product from the Facility (including credits under Sections 38, 45, 46, 45Y, 48, and 48E of the Internal Revenue Code of 1986, as amended); (b) any federal, state, or local grants, subsidies or other like benefits relating in any way to ownership or operation of the Facility; and (c) any other form of benefit or incentive relating in any way to the Facility that is not a Green Attribute or a Future Environmental Attribute.
“Renewable Rate” has the meaning set forth on the Cover Sheet. “Replacement Energy” has the meaning set forth in Exhibit G. “Replacement Green Attributes” means Renewable Energy Credits of the same Portfolio Content Category (i.e., PCC1) as the Green Attributes portion of the Product and of the same year of production as the Renewable Energy Credits that would have been generated by the Generating Facility.
“Replacement Product” has the meaning set forth in Exhibit G. “Replacement RA” means Resource Adequacy Benefits from a Resource Adequacy Resource that are equivalent in all respects to those that would have been provided by the Storage Facility, as applicable, with respect to the applicable Showing Month in which a RA Deficiency Amount is due to Buyer, including, the same Slice-of-Day (as defined in the Resource Adequacy Rulings) generation profile and related characteristics, any successor criteria applicable to the Storage Facility, and as applicable, any Flexible RAR and Local RAR unless Buyer consents, such consent not to be unreasonably withheld, conditioned or delayed, to accept Replacement RA from another facility that provides non-equivalent Resource Adequacy Benefits. “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 a Governmental Authority, including the Resource Adequacy Rulings, or the CAISO Tariff, and shall include RAR, Flexible RAR, and Local RAR and any successor criteria applicable to the Facility, including any Resource Duration attributes. “Resource Adequacy Plan” 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.
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“Resource Adequacy Resource” has the meaning set forth in the CAISO Tariff. “Resource Adequacy Rulings” means any applicable CPUC ruling or decision related to resource adequacy, or any other resource adequacy Law, 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. “Resource Duration” means the number of continuous hours of discharge set forth on the Cover Sheet.
“S&P” means the Standard & Poor’s Financial Services, LLC (a subsidiary of S&P Global, Inc.) or its successor.
“SC Metered Entity” has the meaning of a “Scheduling Coordinator Metered Entity” as defined in the CAISO Tariff.
“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, Discharging Energy, or Generating Facility Energy, as applicable, that clears under the applicable CAISO market based on the final Day-Ahead Schedule, FMM Schedule (as defined in the CAISO Tariff), or any other financially binding Schedule, 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. Consistent with Exhibit D, Buyer or an agent of Buyer will be the Scheduling Coordinator for the Facility as set forth in the Cover Sheet. “Security Interest” has the meaning set forth in Section 8.9. “Self-Schedule” has the meaning set forth in the CAISO Tariff. “Seller” has the meaning set forth on the Cover Sheet.
“Seller Initiated Test” has the meaning set forth in Section 4.11(c). “Seller’s WREGIS Account” has the meaning set forth in Section 4.13(a). 268
“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 unless such damages are part of a Party’s Gains, Losses or Costs as those terms are explicitly defined herein. “Settlement Interval” has the meaning set forth in the CAISO Tariff. “Settlement Period” has the meaning set forth in the CAISO Tariff. “Settlement Quality Meter Data” 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 Charging Energy and Discharging Energy to and from the Delivery Point to the Facility (which is excluded from Shared Facilities), including the Interconnection Agreement itself, that are used in common with third parties.
“Showing Month” shall be the calendar month of the Delivery Term 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” 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 Darden Project Boundaries described in Exhibit A shall be subject to Buyer’s approval of such updates in its reasonable discretion.
“Site Control” means that, for the Contract Term, Seller (or, prior to the Delivery Term, Seller or 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. “SP-15” means the Existing Zone Generation Trading Hub for Existing Zone region SP15 as set forth in the CAISO Tariff.
“SQMD Plan” has the meaning set forth in the CAISO Tariff. “State of Charge” or “SOC” means the ratio of (a) the Stored Energy Level of the Storage Facility to (b) the Effective Storage Capacity multiplied by the Resource Duration, expressed as a percentage.
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ive number, the Storage RA Shortfall shall be deemed to be zero MW for such Showing Month.
“Storage Rate” has the meaning set forth on the Cover Sheet. “Storage System Manufacturer” means Tesla, Inc.
“Stored Energy Level” means, at a particular time, the amount of Energy in the Storage 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. “Subsequent Capacity Test” has the meaning set forth in Section 4.11(c). “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. “Tangible Net Worth” means the tangible assets (for example, not including intangibles such as goodwill and rights to patents or royalties) that remain after deducting liabilities as determined in accordance with generally accepted accounting principles. “Tax” or “Taxes” means all U.S. federal, state and local and any foreign taxes, levies, assessments, surcharges, duties and any other fees or charges in the nature of taxes 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, or other taxes, and including any interest, penalty, or addition imposed by any Governmental Authority with respect thereto, whether disputed or not.
“Tax Credits” means (a) the ITC and any other state, local or federal production tax credit, depreciation benefit, tax deduction, or investment tax credit or other Tax benefits specific to the production of renewable energy or investments in renewable energy facilities and/or energy storage facilities and (b) any refundable credit, grant, or other cash payment in lieu of an incentive described in clause (a).
“Terminated Transaction” has the meaning set forth in Section 11.2(a). “Termination Payment” has the meaning set forth in Section 11.3(b). 271
“Test Energy” means Generating Facility Energy delivered (a) commencing on the later of (i) the first date that the CAISO informs Seller in writing that Seller may deliver Generating Facility Energy to the CAISO and (ii) the first date that the Transmission Provider informs Seller in writing that Seller has conditional or temporary permission to parallel and (b) ending upon the occurrence of the Commercial Operation Date.
“Test Energy Rate” has the meaning set forth in Section 3.6. “Third-Party Transaction” has the meaning set forth in Section 14.6(c). “Throughput” means, at any point in time during any day or Contract Year, as applicable, the total cumulative amount of Discharging Energy from the Storage Facility at such point in time during such day or Contract Year, as applicable (expressed in MWh). “Trading Day” has the meaning set forth in the CAISO Tariff. “Transmission Provider” means any entity or entities transmitting or transporting the Facility Energy, Charging Energy and Discharging Energy, as applicable on behalf of Seller or Buyer to or from the Delivery Point, but excluding Seller or any Seller’s Affiliate responsible for operating any gen-tie line to any point of interconnection to a Transmission Provider’s transmission system or distribution system. For purposes of this Agreement, the Transmission Provider is set forth in Exhibit A.
“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.
“Ultimate Parent” means Intersect Power, 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.
“Variable Energy Resource” or “VER” has the meaning set forth in the CAISO Tariff. “WREGIS” means the Western Renewable Energy Generation Information System or any successor renewable energy tracking program.
“WREGIS Certificate Deficit” has the meaning set forth in Section 4.13(e). “WREGIS Certificates” has the same meaning as “Certificate” as defined by WREGIS in the WREGIS Operating Rules and are designated as eligible for complying with the California Renewables Portfolio Standard.
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“WREGIS Operating Rules” means those operating rules and requirements adopted by WREGIS as of October 2022, as subsequently amended, supplemented or replaced (in whole or in part) from time to time.
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 means 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” (and its variants) 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;
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(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 (the “Contract Term”); provided, however, that subject to Buyer’s obligations in Section 3.6, 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) 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 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. Any rejection of Seller’s request for confirmation of Commercial Operation shall be in writing with reasonable detail and include the specific unsatisfied conditions precedent. If Buyer fails to respond to Seller’s Notice within such five (5) Business Day period, Buyer will be deemed to have approved Seller’s request for confirmation of Commercial Operation. Upon Buyer’s approval (or deemed approval) of Seller’s achievement of Commercial Operation, Buyer shall provide Seller with written acknowledgement of the Commercial Operation Date.
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(a) Seller has 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) A Participating Generator Agreement and a Meter Service Agreement between Seller and CAISO have been executed and delivered and are in full force and effect, and a copy of each such agreement has been delivered to Buyer; (c) 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 has been delivered to Buyer;
(d) All applicable regulatory authorizations, approvals and permits for the operation of the Facility have been obtained and shall be in full force and effect 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, and Seller has delivered to Buyer an attestation certificate from an officer of Seller certifying to the satisfaction of this condition; (e) Seller has Site Control;
(f) Seller has obtained CAISO Certification for the Facility, and a copy of the CAISO Certification has been delivered to Buyer;
(g) Seller has obtained all Network Upgrades to enable a designation of Full Capacity Deliverability Status or Interim Deliverability Status for the full Contract Capacity by the Commercial Operation Date;
(h) Seller has received CEC Precertification of the Generating Facility (and reasonably expects to receive final CEC Certification and Verification for the Generating Facility in no more than days from the Commercial Operation Date); (i) Seller (with the reasonable participation of Buyer) shall have completed all applicable WREGIS registration requirements, including the completion and submittal of all applicable registration forms and supporting documentation, which may include applicable Interconnection Agreements, informational surveys related to the Generating Facility, qualified reporting entity service agreements, and other appropriate documentation required to effect Generating Facility registration with WREGIS and to enable Renewable Energy Credit transfers related to the Generating Facility within the WREGIS system; (j) The Facility has successfully completed all testing required by Prudent Operating Practice or any requirement of Law to commence operations of the Facility; (k) Insurance requirements for the Facility have been met, with evidence provided in writing to Buyer, in accordance with Section 17.1; 275
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Product, Buyer shall pay Seller an amount equal to
(the “Test Energy Rate”). For the avoidance of
doubt, the conditions precedent in Section 2.2 are not applicable to the Parties’ obligations under this Section 3.6.
3.7 Capacity Attributes. Seller shall request Full Capacity Deliverability Status or Interim Deliverability Status for the Guaranteed Storage Capacity in the CAISO generator interconnection process in order to achieve the First Showing Month on a Full Capacity Deliverability Status or Interim Deliverability Status basis in the amount of the Guaranteed Storage Capacity by the RA Guaranteed Date. As between Buyer and Seller, Seller shall be responsible for the cost and installation of any Reliability Network Upgrades and/or Delivery Network Upgrades associated with obtaining such Full Capacity Deliverability Status or Interim Deliverability Status. (a) Throughout the Delivery Term, Seller grants, pledges, assigns and otherwise commits to Buyer all available Capacity Attributes from the Storage Facility, as well as any available charging sufficiency attributes from the Generating Facility to facilitate such Capacity Attributes.
(b) Throughout the Delivery Term, Seller shall maintain eligibility for Full Capacity Deliverability Status or Interim Deliverability Status for the Storage Facility from the CAISO and shall perform all actions necessary to ensure that the Facility qualifies to provide Resource Adequacy Benefits to Buyer. Throughout the Delivery Term, Seller hereby covenants and agrees to transfer all available Resource Adequacy Benefits from the Storage 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. (d) If Seller anticipates it will have an RA Deficiency Amount in any month of the Delivery Term, Seller may provide Replacement RA up to the anticipated RA Shortfall Amount as an alternative to paying RA Deficiency Amounts. Any Replacement RA capacity shall be communicated by Seller to Buyer with Replacement RA product information in a written notice substantially in the form of Exhibit M at least seventy-five (75) days before the applicable Showing Month.
3.8 Resource Adequacy Failure.
(a) RA Deficiency Determination. For each RA Shortfall Month, Seller shall either (i) provide replacement Resource Adequacy Benefits, or (ii) pay to Buyer the RA Deficiency Amount as liquidated damages, in each case, as the Buyer’s sole remedy and Seller’s sole liability for the Capacity Attributes 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 sum of (i) the product of (A) the RA Shortfall Amount, and (B) the CPUC System RA Penalty, 280
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(b) The term “commercially reasonable efforts” as used in this Section 3.11 means efforts consistent with and subject to Section 3.12. The term “Project” as used in Section
3.11(a) means the Generating Facility.
(c) Transfer of Renewable Energy Credits. Seller and, if applicable, its successors, represents and warrants that throughout the Delivery Term of this Agreement the Renewable Energy Credits transferred to Buyer conform to the definition and attributes required for compliance with the California Renewables Portfolio Standard, as set forth in California Public Utilities Commission Decision 08-08-028, and as may be modified by subsequent decision of the California Public Utilities Commission or by subsequent legislation. To the extent a change in law occurs after execution of this Agreement that causes this representation and warranty to be materially false or misleading, it shall not be an Event of Default if Seller has used commercially reasonable efforts to comply with such change in law. [STC REC-1]. (d) Tracking of RECs in WREGIS. Seller warrants that all necessary steps to allow the Renewable Energy Credits transferred to Buyer to be tracked in Western Renewable Energy Generation Information System will be taken prior to the first delivery under the contract. [STC REC-2].
(e) The term “the contract” as used in Section 3.11(d) means this Agreement.
3.12 Compliance Expenditure Cap.
(a) Subject to other provisions of this Section 3.12, the Parties acknowledge that an essential purpose of this Agreement is to provide renewable generation to Buyer that meets the requirements of the California Renewables Portfolio Standard and to provide Resource Adequacy Benefits to Buyer that comply with the Resource Adequacy Rulings. The Parties further acknowledge that Governmental Authorities, including the CEC, CPUC, CAISO and WREGIS, may undertake actions to implement Changes in Law. Seller agrees to use commercially reasonable efforts subject to this Section 3.12 to cooperate with respect to any future changes to this Agreement needed to satisfy requirements of Governmental Authorities associated with Changes in Law to maximize benefits to Buyer, including: (i) the modification of the description of Green Attributes and/or Capacity Attributes as may be required, including updating the Agreement to reflect any mandatory contractual language required by Governmental Authorities; (ii) submission of any reports, data, or other information required by Governmental Authorities; or (iii) all other commercially reasonable actions that may be required to ensure that this Agreement or the Generating Facility is eligible as an ERR and for other benefits under the California Renewables Portfolio Standard; provided, Seller shall have no obligation to modify this Agreement or the Facility (or operation thereof), or take other actions not required under this Agreement, if such modifications or actions would materially adversely affect, or could reasonably be expected to have or result in a material adverse effect on, any of Seller's rights, benefits, risks and/or obligations under or arising from this Agreement. (b) If a Change in Law occurring after the Effective Date has increased or is reasonably expected to increase Seller’s known or reasonably expected costs to (i) (A) cause the Generating Facility, the Energy generated by the Generating Facility, or the associated Green 282
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Seller shall be liable to Buyer for the amounts Seller would have owed Buyer under this Agreement if Buyer had not resold the Product.
ARTICLE 4
OBLIGATIONS AND DELIVERIES
4.1 Delivery.
(a) Energy. Subject to the provisions of this Agreement, commencing on the Commercial Operation Date and continuing 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 each case unless otherwise contemplated 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 Facility Energy to the Delivery Point, including without limitation, Station Use, Electrical Losses, and 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, liabilities and penalties, if any, imposed in connection with the (i) delivery of Charging Energy to the Delivery Point and (ii) delivery of Facility Energy at and after the Delivery Point, including without limitation transmission costs and transmission line losses and imbalance charges, except as otherwise set forth in this Agreement. The Facility Energy and Charging Energy will be scheduled to the CAISO by Buyer (or Buyer’s designated Scheduling Coordinator) in accordance with Exhibit D.
(b) Green Attributes. All Green Attributes associated with Test Energy and the Generating Facility Energy are exclusively dedicated to and vested in Buyer. Seller represents and warrants that Seller holds the rights to all Green Attributes from the Generating Facility, Seller has not sold such Green Attributes to any other person or entity, and Seller agrees to convey and hereby conveys all such Green Attributes to Buyer as included in the delivery of the Product from the Generating Facility.
4.2 Title and Risk of Loss.
(a) Energy. Title to and risk of loss related to the Facility Energy, shall pass and transfer from Seller to Buyer at the Delivery Point. Seller warrants that all Product delivered to Buyer is free and clear of all liens, security interests, claims and encumbrances of any kind. (b) Green Attributes. Title to and risk of loss related to the Green Attributes shall pass and transfer from Seller to Buyer upon the transfer of such Green Attributes in accordance with WREGIS.
4.3 Interconnection. Seller shall be responsible for all costs and charges associated with Interconnection Facilities and Network Upgrades necessitated by the interconnection of the Facility. Seller shall ensure that throughout the Delivery Term (a) the Facility will have an Interconnection Agreement providing for interconnection capacity available or allocable to the Facility that is no less than the Dedicated Interconnection Capacity and (b) Seller shall have sufficient interconnection capacity and rights under such Interconnection Agreement to 285
interconnect the Facility with the CAISO-controlled grid, to fulfill Seller’s obligations under the Agreement, including with respect to Resource Adequacy, and to allow Buyer to instruct dispatch of the Facility in accordance with the CAISO Tariff. Seller shall hold Buyer harmless from any penalties, imbalance energy charges, or other costs from CAISO or under the Agreement resulting from Seller’s inability to provide the foregoing interconnection capacity.
4.4 Forecasting. Seller shall provide the forecasts described below at its sole expense and in a format reasonably acceptable to Buyer (or Buyer’s designee). Seller shall use reasonable efforts to provide forecasts that are accurate and, to the extent not inconsistent with the requirements of this Agreement, shall prepare such forecasts, or cause such forecasts to be prepared, in accordance with Prudent Operating Practices. (a) Annual Forecast of Energy. No less than forty-five (45) days before (i) the first day of the first Contract Year of the Delivery Term and (ii) the beginning of each calendar year for every subsequent Contract Year during the Delivery Term, Seller shall provide to Buyer and the SC (if applicable) a non-binding forecast of each month’s average-day Expected Energy, by hour, for the following calendar year in a form substantially similar to the table found in Exhibit F-1, or in such other form as reasonably requested by Buyer. (b) Monthly Forecast of Energy and Available Generating Capacity. 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 Buyer’s SC (if applicable) a non-binding forecast of the hourly expected Energy and Available Generating Capacity for each day of the following month in a form substantially similar to the table found in Exhibit F-2, or in such other form as reasonably requested by Buyer. (“Monthly Delivery Forecast”).
(c) Day-Ahead Forecast. By 5:30 AM Pacific Prevailing Time on the Business Day immediately preceding the date of delivery, or as otherwise specified by Buyer consistent with Prudent Operating Practice, Seller shall provide Buyer with a non-binding forecast of (i) Available Generating Capacity, and (ii) hourly Expected Energy, in each case, for each hour of the immediately succeeding day (“Day-Ahead Forecast”). A Day-Ahead Forecast provided in a day prior to any non-Business Day(s) shall include non-binding forecasts for the immediate day, each succeeding non-Business Day and the next Business Day. Each Day-Ahead Forecast shall clearly identify, for each hour, Seller’s best estimate of (i) the Available Generating Capacity, and (ii) the hourly Expected Energy. These Day-Ahead Forecasts shall be sent to Buyer’s SC. If Seller fails to provide Buyer with a Day-Ahead Forecast as required herein for any period, then for such unscheduled delivery period only Buyer shall rely on any Real-Time Forecast provided in accordance with Section 4.4(d) or the Monthly Delivery Forecast or Buyer’s best estimate based on information reasonably available to Buyer.
(d) Real-Time Forecasts. During the Delivery Term, Seller shall notify Buyer and the SC (if applicable) of any changes from the Day-Ahead Forecast via a direct data feed to Buyer’s SC (such feed to be provided by Seller at Seller’s expense) of one (1) MW or more in (i) Available Generating Capacity, and (ii) hourly Expected Energy, in each case, whether due to Forced Facility Outage, Force Majeure or other cause, as soon as reasonably possible, but no later 286
than one (1) hour prior to the deadline for submitting Schedules to the CAISO in accordance with the rules for participation in the Real-Time Market. If the Available Generating Capacity or hourly expected Energy changes by at least one (1) MW as of a time that is less than one (1) hour prior to the Real-Time Market deadline, but before such deadline, then Seller must notify Buyer and the SC (if applicable) as soon as reasonably possible. Such Real-Time Forecasts of Energy shall be provided by an Approved Forecast Vendor and shall contain information regarding the beginning date and time of the event resulting in the change in Available Generating Capacity or hourly Expected Energy, as applicable, the expected end date and time of such event, and any other information required by the CAISO or reasonably requested by Buyer. These Real-Time Forecasts shall be communicated in a method reasonably acceptable to Buyer; provided that Buyer specifies the method no later than five (5) Business Days prior to the effective date of such requirement. In the event Buyer fails to provide Notice of an acceptable method for communications under this Section 4.4(d), then Seller shall send such communications by telephone and e-mail to Buyer. (e) Forced Facility Outages. Notwithstanding anything to the contrary herein, Seller shall use commercially reasonable efforts to notify Buyer’s SC of Forced Facility Outages within ten (10) minutes from the commencement of the Forced Facility Outage, but no later than the time periods required by the CAISO Tariff and the CAISO’s outage management rules and Seller shall keep Buyer informed of any developments that will affect either the duration of the Forced Facility Outage or the availability of the Facility during or after the end of the Forced Facility Outage.
(f) Forecasting Penalties. Subject to a Force Majeure Event, in the event Seller does not in a given hour provide the notice required in Section 4.4(e) and Buyer incurs a loss or penalty resulting from its scheduling activities with respect to Generating Facility Energy during such hour due to the failure of Seller to provide such notice, Seller shall be responsible for a Forecasting Penalty for each such hour. Settlement of Forecasting Penalties shall occur as set forth in Article 8 of this Agreement.
(g) CAISO Tariff Requirements. To the extent such obligations are applicable to the Facility, Seller will comply with all applicable obligations for Variable Energy Resources under the CAISO Tariff and the Eligible Intermittent Resource Protocol (as such terms are defined in the CAISO Tariff), including providing appropriate operational data and meteorological data, and will fully cooperate with Buyer, Buyer’s SC, and CAISO, in providing all data, information, and authorizations required thereunder.
4.5 Dispatch Down/Curtailment.
(a) General. Seller agrees to reduce the amount of Generating Facility Energy produced by the Generating Facility, by the amount and for the period set forth in any Curtailment Order, Buyer Curtailment Order, or notice received from CAISO in respect of a Buyer Bid Curtailment; provided, Seller is not required to reduce such amount to the extent it is inconsistent with the limitations of the Generating Facility or Operating Restrictions. (b) Buyer Curtailment. Buyer shall have the right to order Seller to curtail deliveries of Generating Facility Energy through Buyer Curtailment Orders, provided that Buyer 287
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(a) Charging Generally. Upon receipt of a valid Charging Notice, Seller shall take all commercially reasonable action necessary to deliver the Charging Energy to the Storage 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 Storage 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. During the Delivery Term, Buyer shall have the right to instruct Seller to charge the Storage Facility seven (7) days per week and twenty-four (24) hours per day (including holidays), by providing Charging Notices to Seller electronically; provided, Buyer’s right to issue Charging Notices is subject to the availability of the Facility and the requirements and limitations set forth in this Agreement, including the Operating Restrictions.
Each Charging Notice issued in accordance with this Agreement will be effective unless and until such Charging Notice is modified with an updated Charging Notice. Seller shall comply with all Charging Notices, subject to the requirements and limitations set forth in this Agreement, including the Operating Restrictions.
(c) No Unauthorized Charging. Seller shall not charge the Storage Facility during the Delivery Term other than pursuant to a valid Charging Notice (it being understood that Seller may reject or adjust a Charging Notice in order to maintain compliance with the Operating Restrictions), or in connection with a Seller Initiated Test (including Facility maintenance or a Storage Capacity Test), or pursuant to a notice from the CAISO, the Transmission Provider, or any other Governmental Authority. If, during the Delivery Term, Seller (i) charges the Storage Facility to a Stored Energy Level greater than the Stored Energy Level provided for in the Charging Notice, or (ii) charges the Storage Facility in violation of the first sentence of this Section 4.6(c), then (A) Seller shall be responsible for all Energy costs associated with such charging of the Storage Facility, (B) Buyer shall not be required to pay for the charging of such Energy (i.e., Charging Energy), and (C) Buyer shall be entitled to discharge such Energy and entitled to all of the benefits (including Storage Product) associated with such discharge. (d) Discharging Notices. During the Delivery Term, Buyer shall have the right to instruct the discharge of the Storage Facility seven (7) days per week and twenty-four (24) hours per day (including holidays), by submitting Schedules or offers to the CAISO and providing Discharging Notices to Seller electronically, subject to the requirements and limitations set forth in this Agreement, including the Operating Restrictions. Seller shall comply with all Discharging Notices, subject to the requirements and limitations set forth in this Agreement. Each Discharging Notice issued in accordance with this Agreement will be effective unless and until Buyer, Buyer’s SC, or the CAISO modifies such Discharging Notice by providing Seller with an updated Discharging Notice.
(e) No Unauthorized Discharging. Seller shall not discharge the Storage Facility during the Delivery Term other than pursuant to a valid Discharging Notice (it being understood that Seller may reject or adjust a Discharging Notice in order to maintain compliance with the Operating Restrictions), or in connection with a Seller Initiated Test (including Facility maintenance or a Storage Capacity Test), or pursuant to a notice from CAISO, the Transmission 289
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SC, and Seller shall have no liability under this Agreement for violation of this Section 4.6 or any Charging Notices or Discharging Notice if and to the extent such violation is caused by Seller’s compliance with any such CAISO Dispatch.
(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 provided in clause (iii)) is supplied by the applicable utility’s retail service if necessary to avoid any such costs, penalties or charges.
4.7 Storage Availability Notices.
(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 Storage Capacity for each day of the following month in a form as reasonably requested by Buyer (“Monthly Storage Availability Capacity Report”). (b) During the Delivery Term, no later than
in accordance with CAISO scheduling
practices, Seller shall provide Buyer and the SC (if applicable) with an hourly schedule of the Available Storage Capacity that the Storage Facility is expected to have for each hour of such schedule day (the “Storage Availability Notice”). Seller shall provide Storage Availability Notices (including updated Storage Availability Notices) in 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) as soon as practicable with an updated Monthly Storage Capacity Availability Forecast and Storage Availability Notice, as applicable, if the Available Storage Capacity of the Storage Facility changes or is expected to change after Buyer’s receipt of a Monthly Storage Capacity Availability Forecast or Storage Availability Notice. Seller shall accommodate Buyer’s reasonable requests for changes in the time of delivery of Storage Availability Notices.
(d) If (i) Seller provides a revised Storage Availability Notice by 5:00 a.m. of the morning Buyer schedules or bids the Storage Facility in the Day-Ahead Market indicating the 291
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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).
(c) Any testing of the Storage Facility requested by Buyer after the Commercial Operation Storage Capacity Tests, and all required annual tests pursuant to Section B (“Subsequent Capacity Tests”) in Exhibit O, shall be deemed Buyer-instructed dispatches of the Facility (“Buyer Dispatched Test”). Any test of the Storage 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 Storage Capacity immediately prior to such Capacity Test is below of the Installed Storage Capacity, any Capacity Test conducted if the Efficiency Rate immediately prior to such Capacity Test is below the Minimum Efficiency Rate, and 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 Storage 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”. For all Seller Initiated Tests, Seller shall (i) be liable for all CAISO costs and charges for associated Charging Energy, and (ii) be entitled to any CAISO revenues associated with Discharging Energy.
The Facility shall be deemed unavailable during any Seller Initiated Test For any Buyer Dispatched Test, Buyer shall (x) pay for all CAISO costs and charges for associated Charging Energy, and (y) be entitled to any CAISO revenues associated with associated Discharging Energy. Any Buyer Dispatched Test shall be deemed an Excused Event for the purposes of calculating the Monthly Capacity Availability. (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.
4.12 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.
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(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 4.11(c) and 4.12(a) and (b), all other costs of any testing of the Facility shall be borne by Seller.
4.13 WREGIS. Seller shall, at its sole expense, take all actions and execute all documents or instruments necessary to ensure that all WREGIS Certificates associated with all Renewable Energy Credits corresponding to all Generating Facility Energy are issued and tracked for purposes of satisfying the requirements of the California Renewables Portfolio Standard and transferred in a timely manner to Buyer for Buyer’s sole benefit. Seller shall transfer the Renewable Energy Credits to Buyer, it being acknowledged that Seller may not be able under WREGIS rules to complete all WREGIS registration requirements prior to the Commercial Operation Date. Seller shall comply with all Laws, including the WREGIS Operating Rules, regarding the certification and transfer of such WREGIS Certificates to Buyer and Buyer shall be given sole title to all such WREGIS Certificates.
(a) Prior to the Commercial Operation Date, Seller shall register the Facility with WREGIS and establish an account with WREGIS (“Seller’s WREGIS Account”), which Seller shall maintain until the end of the Delivery Term. Seller shall transfer the WREGIS Certificates using “Recurring Certificate Transfers” (as described in the WREGIS Operating Rules) from Seller’s WREGIS Account to the WREGIS account(s) of Buyer or the account(s) of a designee that Buyer identifies by Notice to Seller (“Buyer’s WREGIS Account”). Seller shall be responsible for all expenses associated with registering the Generating Facility with WREGIS, establishing and maintaining Seller’s WREGIS Account, paying WREGIS Certificate issuance and transfer fees, and transferring WREGIS Certificates from Seller’s WREGIS Account to Buyer’s WREGIS Account. Buyer shall be responsible for all expenses associated with establishing and maintaining Buyer’s WREGIS Account.
(b) Seller shall cause Recurring Certificate Transfers to occur on a monthly basis in accordance with the certification procedure established by the WREGIS Operating Rules.
Since WREGIS Certificates will only be created for whole MWh amounts of Facility Energy generated, any fractional MWh amounts (i.e., kWh) will be carried forward until sufficient generation is accumulated for the creation of a WREGIS Certificate. (c) Seller shall, at its sole expense, ensure that the WREGIS Certificates for a given calendar month correspond with the Generating Facility Energy for such calendar month as evidenced by the Generating Facility’s metered data.
(d) Due to the ninety (90) day delay in the creation of WREGIS Certificates relative to the timing of invoice payment under Section 8.2, Buyer shall make an invoice payment for a given month in accordance with Section 8.2 before the WREGIS Certificates for such month are formally transferred to Buyer in accordance with the WREGIS Operating Rules and this Section 3. Notwithstanding this delay, Buyer shall have all right and title to all such WREGIS Certificates upon payment to Seller in accordance with Section 8.2. 296
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(c) 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.
(d) 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 6.1(d) shall be provided to Buyer within fifteen (15) days of Buyer’s request.
(e) Seller shall maintain accurate records with respect to all Capacity Tests. (f) 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.
6.2 Dispatch. Buyer shall have the right to instruct the dispatch of the Storage Facility seven (7) days per week and twenty-four (24) hours per day (including holidays), by providing Dispatch Notices, subject to availability of the Storage Facility and 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.
6.3 Storage Facility Unavailability to Receive Dispatch Notices. To the extent the Facility is unable to receive or respond to Dispatch Notices through Automated Dispatches during any Settlement Interval or Settlement Period, then as an exclusive remedy, the time period corresponding to such Settlement Interval or Settlement Period shall be deemed unavailable for purposes of calculating the Monthly Capacity Availability except to the extent that the Storage Facility is unable to receive or respond to Dispatch Notices due to (i) any circumstances at the high-voltage side of the Delivery Point or beyond that point, or (ii) an Excused Event.
6.4 Maintenance of Health and Safety. Seller shall take commercially 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, commercially reasonable action to prevent such damage or injury and shall give prompt Notice to Buyer’s emergency contact identified on Exhibit N of such condition. Such action may include, to the extent reasonably necessary, disconnecting and removing all or a portion of the Facility, or suspending the supply of Energy or Discharging Energy to the Delivery Point. 299
6.5 Storage Facility Rebalancing. Seller shall have the right to charge and discharge the Facility to rebalance the levels of stored energy in the Storage Facility inverters as Seller deems reasonably necessary following outages, derates, or other events affecting the operation of the Facility (“Storage Facility Rebalancing”); provided that, (a) Seller shall provide prior Notice to Buyer of any Storage Facility Rebalancing, (b) Seller shall restore the Storage Facility to the Stored Energy level that existed immediately prior to such Storage Facility Rebalancing, (c) Seller shall schedule all Storage Facility Rebalancing during Off-Peak Hours and in coordination with Buyer and Buyer’s Scheduling Coordinator, (d) Seller shall be responsible and reimburse Buyer for all net CAISO costs incurred by Buyer related to a Storage Facility Rebalancing, and (e) for avoidance of doubt, the number of hours or partial hours during which Seller performs a Storage Facility Rebalancing shall be deemed to be unavailable for the purpose of calculating the Monthly Storage Availability in accordance with Exhibit P.
6.6 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 (a) shall permit Seller to perform or satisfy, and shall not purport to limit, Seller’s obligations hereunder, including providing interconnection capacity for the Facility’s sole use in an amount not less than the Dedicated Interconnection Capacity, (b) shall not prohibit separate metering and a separate CAISO Resource ID for each of the Generating Facility and the Storage Facility, (c) shall not prohibit Seller from excluding any other generating or energy storage facilities not included in the Facility (but using Shared Facilities) from the Facility’s CAISO Resource IDs; and (d) shall provide that any curtailment of the full capacity of Shared Facilities that is ordered by Transmission Provider that Seller and its Affiliates have discretion to allocate across generating or energy storage facilities using the Shared Facilities shall not be allocated to the Facility more than its pro rata portion of the total capacity of all generating or energy storage facilities using the Shared Facilities. Seller shall not, and shall not permit any Affiliate to, allocate to other parties a share of the total interconnection capacity under the Interconnection Agreement in excess of an amount equal to the total interconnection capacity under the Interconnection Agreement minus the Dedicated Interconnection Capacity.
ARTICLE 7
METERING
7.1 Metering. The Facility shall have a separate CAISO Resource ID for the Generating Facility, the Storage Facility, and any other generating or energy storage facilities not included in the Facility (but using Shared Facilities). Seller shall measure the amount of Generating Facility Energy using the Generating Facility Meter. Seller shall measure the Charging Energy and the Discharging Energy using the Storage Facility Meter. All meters will be operated pursuant to applicable CAISO-approved calculation methodologies and maintained at Seller’s cost. If Seller elects for the Facility, or only the Storage Facility, as applicable, to be a SC Metered Entity, then all Generating Facility Meters, or all Storage Facility Meters, as applicable, will be programmed, operated and maintained pursuant to the applicable CAISO-approved SQMD Plan for the 300
Generating Facility, or only the Storage Facility, as applicable, at Seller’s cost (including, for avoidance of doubt, reimbursement to Buyer of reasonable, documented and customary costs owed by Buyer to its Scheduling Coordinator for submitting SQMD Plan meter data to the CAISO), throughout the period to which the SQMD Plan applies. Seller shall provide to Buyer a copy of any CAISO-approved SQMD Plan and any modifications thereto and notice of any termination or withdrawal thereof. Buyer shall cause its Scheduling Coordinator to cooperate reasonably with Seller and Seller’s third-party contractor as necessary for the submission of Settlement Quality Meter Data to the CAISO. Subject to meeting any applicable CAISO requirements, the Generating Facility Meter and Storage Facility Meter shall be programmed to adjust for Electrical Losses and Station Use, as applicable, from such meters to the Delivery Point in a manner subject to Buyer’s prior written approval, not to be unreasonably withheld. Seller shall separately meter all Station Use. Metering shall be consistent with the Metering Diagram set forth as Exhibit R, a final version of which shall be provided to Buyer at least thirty (30) days before the Commercial Operation Date. Each Generating Facility Meter and Storage Facility Meter shall be kept under seal, such seals to be broken only when the 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 meter data to Buyer in a form reasonably acceptable to Buyer, and consents to Buyer obtaining from CAISO the CAISO meter data directly relating to the Facility and all inspection, testing and calibration data and reports, to the extent such meter data and related meters are not the subject of a CAISO-approved SQMD Plan for the Generating Facility, or only the Storage Facility, as applicable. Seller and Buyer, or Buyer’s Scheduling Coordinator, shall cooperate to allow both Parties to retrieve the meter reads from the CAISO Market Results Interface – Settlements (MRI-S) website (or its successor) or directly from the CAISO meter(s) at the Facility, to the extent such meter data and related meters are not the subject of a CAISO-approved SQMD Plan for the Generating Facility, or only the Storage Facility, as applicable.
7.2 Meter Verification. Seller shall test the Generating Facility Meter and Storage Facility Meter at least annually and more frequently than annually if Buyer or Seller reasonably believe there may be a meter malfunction. 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 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 meter inaccuracy commenced (if such evidence exists such date will be used to adjust prior invoices), then the invoices covering the period of time since the last meter test shall be adjusted for the amount of the inaccuracy on the assumption that the inaccuracy persisted during one-half of such period so long as such adjustments are accepted by CAISO and WREGIS; provided, such period may not exceed twelve (12) months.
ARTICLE 8
INVOICING AND PAYMENT; CREDIT
8.1 Invoicing. Seller shall use commercially reasonable efforts to deliver an invoice to Buyer within Business Days after the end of the prior monthly delivery period. Each invoice shall (a) include records of metered data, including (i) CAISO metering and transaction data sufficient to document and verify the amount of Product delivered by the Facility for any 301
Settlement Period during the preceding month, including the amount of Generating Facility Energy, Charging Energy, Discharging Energy, and Replacement RA delivered to Buyer (if any); (ii) Seller’s calculation of Deemed Delivered Energy, Lost Output, and Adjusted Energy Production; (iii) the LMP prices at the Delivery Point for each Settlement Period; and (iv) the Contract Price applicable to such Product and Seller’s calculation of the Monthly Product Payment due from Buyer, calculated in accordance with Exhibit C; (b) include any records, including invoices or settlement data from the CAISO, necessary to verify the accuracy of any amount; and (c) be in a format reasonably specified by Buyer, covering the services provided in the preceding month determined in accordance with the applicable provisions of this Agreement. Buyer shall, and shall cause its Scheduling Coordinator to, provide Seller with all reasonable access (including, in real time, to the maximum extent reasonably possible) to any records, including invoices or settlement data from the CAISO, forecast data and other information, all as may be necessary from time to time for Seller to prepare and verify the accuracy of all invoices. The invoice shall be delivered by electronic mail in accordance with Exhibit N.
8.2 Payment. Buyer shall make payment to Seller for Monthly Product Payments by wire transfer or ACH payment to the bank account provided on each monthly invoice. Buyer shall pay undisputed invoice amounts within thirty (30) days of Buyer’s receipt of Seller’s invoices; provided, if such due date falls on a weekend or legal holiday, such due date shall be the next Business Day. Payments made after the due date will be considered late and will bear interest on the unpaid balance. If the amount due is not paid on or before the due date or if any other payment that is due and owing from one Party to another is not paid on or before its applicable due date, a late payment charge shall be applied to the unpaid balance and shall be added to the next billing statement. Such late payment charge shall be calculated based on the 3-month prime rate (or any equivalent successor rate accepted by a majority of major financial institutions) published on the date of the invoice in The Wall Street Journal (or, if The Wall Street Journal is not published on that day, the next succeeding date of publication), plus two percent (2%) (the “Interest Rate”). If the due date occurs on a day that is not a Business Day, the late payment charge shall begin to accrue on the next succeeding Business Day.
8.3 Books and Records. To facilitate payment and verification, each Party shall maintain all books and records necessary for billing and payments, including copies of all invoices under this Agreement, for a period of at least five (5) years or as otherwise required by Law. Upon ten (10) Business Days’ Notice to the other Party, either Party shall be granted access to the accounting books and records within the possession or control of the other Party pertaining to all invoices generated pursuant to this Agreement. Seller acknowledges that in accordance with California Government Code Section 8546.7, Seller may be subject to audit by the California State Auditor with regard to Seller’s performance of this Agreement because the compensation under this Agreement exceeds Ten Thousand Dollars ($10,000).
8.4 Invoice Adjustments. Invoice adjustments shall be made if (a) there have been good faith inaccuracies in invoicing or payment that are not otherwise disputed under Section 8.5, (b) an adjustment to an amount previously invoiced or paid is required due to a correction of data by the CAISO, or pursuant to a Storage Capacity Test, or (c) there have been meter inaccuracies; provided, however, that there shall be no adjustments to prior invoices based upon meter 302
inaccuracies except to the extent that such meter adjustments are accepted by CAISO for revenue purposes. If the required adjustment is in favor of Buyer, Buyer’s next monthly payment shall be credited in an amount equal to the adjustment. If the required adjustment is in favor of Seller, Seller shall add the adjustment amount to Buyer’s next monthly invoice. Adjustments in favor of either Buyer or Seller shall bear interest, until settled in full, in accordance with Section 8.2, accruing from the date on which the adjusted amount should have been due.
8.5 Billing Disputes. A Party may, in good faith, dispute the correctness of any invoice or any adjustment to an invoice rendered under this Agreement, including any invoice for damages in accordance with Exhibit G, or adjust any invoice for any arithmetic or computational error within twelve (12) months of the date the invoice, or adjustment to an invoice, was rendered. In the event an invoice or portion thereof, or any other claim or adjustment arising hereunder, is disputed, payment of the undisputed portion of the invoice shall be required to be made when due.
Any invoice dispute or invoice adjustment shall be in writing and shall state the basis for the dispute or adjustment. Payment of the disputed amount shall not be required until the dispute is resolved. Upon resolution of the dispute, any required payment shall be made within five (5) Business Days of such resolution along with interest accrued at the Interest Rate from and including the original due date to but excluding the date paid. Inadvertent overpayments shall be returned via adjustments in accordance with Section 8.4. Any dispute with respect to an invoice is waived if the other Party is not notified in accordance with this Section 8.5 within twelve (12) months after the invoice is rendered or subsequently adjusted, except to the extent any misinformation was from a third party not affiliated with any Party and such third party corrects its information after the twelve-month period. If an invoice is not rendered within twelve (12) months after the close of the month during which performance occurred, the right to payment for such performance is waived.
8.6 Netting of Payments. The Parties hereby agree that they shall discharge mutual debts and payment obligations due and owing to each other on the same date through netting, in which case all amounts owed by each Party to the other Party for the purchase and sale of Product during the monthly billing period under this Agreement or otherwise arising out of this Agreement, including any related damages calculated pursuant to Exhibits B, C and G, interest, and payments or credits, shall be netted so that only the excess amount remaining due shall be paid by the Party who owes it.
8.7 Seller’s Development Security. To secure its obligations under this Agreement, Seller shall deliver Development Security to Buyer within thirty (30) days of the Effective Date.
Seller shall maintain the Development Security in full force and effect and Seller shall within five (5) Business Days after any draw thereon replenish the Development Security (subject to Section
11.6) in the event Buyer collects or draws down any portion of the Development Security for any reason permitted under this Agreement other than to satisfy a Damage Payment or a Termination Payment. Upon the earlier of (a) Seller’s delivery of the Performance Security, or (b) sixty (60) days after termination of this Agreement, Buyer shall return the Development Security to Seller, less the amounts drawn in accordance with this Agreement. If the Development Security is a Letter of Credit and the issuer of such Letter of Credit (i) fails to maintain the minimum Credit Rating specified in the definition of Letter of Credit, (ii) indicates its intent not to renew such Letter of 303
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Upon or any time after the occurrence and continuation of an Event of Default caused by Seller, an Early Termination Date resulting from an Event of Default caused by Seller, or an occasion provided for in this Agreement where Buyer is authorized to retain all or a portion of the Development Security or Performance Security, Buyer may do any one or more of the following (in each case subject to the final sentence of this Section 8.9):
(a) Exercise any of its rights and remedies with respect to the Development Security and Performance Security, including any such rights and remedies under Law then in effect;
(b) Draw on any outstanding Letter of Credit issued for its benefit and retain any cash held by Buyer as Development Security or Performance Security; and (c) Liquidate all Development Security or Performance Security (as applicable) then held by or for the benefit of Buyer free from any claim or right of any nature whatsoever of Seller, including any equity or right of purchase or redemption by Seller.
Buyer shall apply the proceeds of the collateral realized upon the exercise of any such rights or remedies to reduce Seller’s obligations under this Agreement (Seller remains liable for any amounts owing to Buyer after such application), subject to Buyer’s obligation to return any surplus proceeds remaining after these obligations are satisfied in full.
ARTICLE 9
NOTICES
9.1 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 N or at such other address or addresses as a Party may designate for itself from time to time by Notice hereunder.
9.2 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, three (3) Business Days following the date of the postmark on the envelope in which such Notice was deposited in the United States mail;
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(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) and if concurrently with the transmittal of such electronic communication the sending Party provides a copy of such electronic Notice by hand delivery or express courier, at the time indicated by the time stamp upon delivery; or
(d) if delivered in person, upon receipt by the receiving Party. Notwithstanding the foregoing, invoices sent pursuant to Section 8.1 and 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. In addition, for any Notice sent pursuant to (a), (b) or (d) above, the Party sending such Notice shall send a courtesy copy by email to the email address provided on Exhibit N on the same date as such Notice is being served, given or delivered.
ARTICLE 10
FORCE MAJEURE
10.1 Definition.
(a) “Force Majeure Event” means any act or event that delays or prevents a Party from timely performing all or a portion of its obligations under this Agreement or from complying with all or a portion of the conditions under this Agreement if such act or event, despite the exercise of commercially reasonable efforts, cannot be avoided by and is beyond the reasonable control (whether direct or indirect) of and without the fault or negligence of the Party relying thereon as justification for such delay, nonperformance, or noncompliance. (b) Without limiting the generality of the foregoing, so long as the following events, despite the exercise of reasonable efforts, cannot be avoided by, and are beyond the reasonable control (whether direct or indirect) of and without the fault or negligence of the Party relying thereon as justification for such delay, nonperformance or noncompliance, a Force Majeure Event may include an act of God or the elements, such as flooding, lightning, hurricanes, tornadoes, hail or ice storms; explosion; fire; volcanic eruption; flood; epidemic; pandemic; landslide; mudslide; sabotage; terrorism; earthquake; or other cataclysmic events; an act of public enemy; war; blockade; civil insurrection; riot; civil disturbance; or strikes or other labor difficulties caused or suffered by a Party or any third party except as set forth below. (c) Notwithstanding the foregoing, “Force Majeure Event” does not include (i) economic conditions or changes in Law that render a Party’s performance of this Agreement at the Contract Price unprofitable or otherwise uneconomic (including an increase in component or compliance costs for any reason, including foreign or domestic tariffs, Buyer’s ability to buy Product at a lower price, or Seller’s ability to sell the Product, or any component thereof, at a higher price, than under this Agreement); (ii) Seller’s inability to obtain permits or approvals of any type for the construction, operation, or maintenance of the Facility, except to the extent such 306
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remedies for which are set forth in Section 4.10(a) and Exhibit C; and (D) failure to maintain the Guaranteed Efficiency Rate that does not trigger the provisions of Section 11.1(b)(x), the exclusive remedies for which are set forth in Section 4.10(b) and Exhibit C), and such failure is not remedied within thirty (30) days after Notice thereof (or such longer additional period, not to exceed an additional ninety (90) days, if the Defaulting Party is unable to remedy such default within such initial thirty (30) day period despite exercising commercially reasonable efforts); (iv) such Party becomes Bankrupt;
(v) such Party assigns this Agreement or any of its rights hereunder other than in compliance with Article 14, if applicable; or (vi) such Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all the obligations of such Party under this Agreement to which it or its predecessor was a party by operation of Law or pursuant to an agreement reasonably satisfactory to the other Party. (b) with respect to Seller as the Defaulting Party, the occurrence of any of the following:
(i) if at any time, Seller delivers or attempts to deliver Energy to the Delivery Point for sale under this Agreement that was not generated or discharged by the Facility, other than Replacement Product;
(ii) the failure by Seller to achieve Commercial Operation on or before the Guaranteed Commercial Operation Date, as such date may be extended by Seller’s payment of Commercial Operation Delay Damages pursuant to Section 2(c) of Exhibit B and/or a Development Cure Period pursuant to Section 4 of Exhibit B; (iii) if not remedied within ten (10) days after Notice thereof, the failure by Seller to deliver a Remedial Action Plan within the timeframe set forth in Section 2.4; (iv) the failure by Seller to achieve Construction Start on or before the Guaranteed Construction Start Date, as such date may be extended by Seller’s payment of Construction Delay Damages pursuant to Section 1(b) of Exhibit B and/or a Development Cure Period pursuant to Section 4 of Exhibit B;
(v) Seller sells, assigns, or otherwise transfers, or commits to sell, assign, or otherwise transfer, the Product, or any portion thereof, during the Delivery Term to any party other than Buyer except as expressly permitted under this Agreement; (vi) if, in any consecutive six (6) month period after the Commercial Operation Date, the Adjusted
Energy Production amount (calculated in accordance with Exhibit G) for such period is not at least of the Expected Energy amount for such period, and Seller fails to (A) deliver 309
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Credit from a different issuer meeting the criteria set forth in the definition of Letter of Credit, in each case, in the amount required hereunder within ten (10) Business Days after Seller receives Notice of the occurrence of any of the following events:
(A) the issuer of the outstanding Letter of Credit shall fail to maintain a Credit Rating of at least A- by S&P or A3 by Moody’s; (B) the issuer of such Letter of Credit becomes Bankrupt; (C) the issuer of the outstanding Letter of Credit shall fail to comply with or perform its obligations under such Letter of Credit and such failure shall be continuing after the lapse of any applicable grace period permitted under such Letter of Credit;
(D) the issuer of the outstanding Letter of Credit shall fail to honor a properly documented request to draw on such Letter of Credit; (E) the issuer of the outstanding Letter of Credit shall disaffirm, disclaim, repudiate or reject, in whole or in part, or challenge the validity of, such Letter of Credit;
(F) such Letter of Credit fails or ceases to be in full force and effect at any time; or
(G) Seller shall fail to renew or cause the renewal of each outstanding Letter of Credit on a timely basis as provided in the relevant Letter of Credit and as provided in accordance with this Agreement, and in no event less than days prior to the expiration of the outstanding Letter of Credit.
11.2 Remedies; Declaration of Early Termination Date. If an Event of Default with respect to a Defaulting Party shall have occurred and be continuing, the other Party (“Non-Defaulting Party”) shall have the following rights:
(a) to send Notice, designating a day, no earlier than the day such Notice is deemed to be received and no later than twenty (20) days after such Notice is deemed to be received, as an early termination date of this Agreement (“Early Termination Date”) that terminates this Agreement (the “Terminated Transaction”) and ends the Delivery Term effective as of the Early Termination Date;
(b) to accelerate all amounts owing between the Parties, and to collect as liquidated damages (i) the Damage Payment (in the case of an Event of Default by Seller occurring before the Commercial Operation Date), or (ii) the Termination Payment, as applicable, calculated in accordance with Section 11.3 below (in the case of any other Event of Default by either Party); (c) to withhold any payments due to the Defaulting Party under this Agreement; 311
(d) to suspend performance; and
(e) to exercise any other right or remedy available at law or in equity, including specific performance, injunctive relief, except to the extent such remedies are expressly limited under this Agreement; provided, payment by the Defaulting Party of the Damage Payment or Termination Payment, as applicable, shall constitute liquidated damages and the Non-Defaulting Party’s sole and exclusive monetary remedy for any Terminated Transaction and the Event of Default related thereto.
11.3 Damage Payment; Termination Payment. If an Early Termination Date has been declared, the Non-Defaulting Party shall calculate, in a commercially reasonable manner, the Damage Payment or Termination Payment, as applicable, in accordance with this Section 11.3. (a) Damage Payment Prior to Commercial Operation Date. If the Early Termination Date occurs before the Commercial Operation Date, then the Damage Payment shall be calculated in accordance with this Section 11.3(a).
(i) If Seller is the Defaulting Party, then the Damage Payment shall be owed to Buyer and shall be a dollar amount that equals the entire amount of the Development Security plus, if the Development Security is
posted as cash, any interest accrued thereon. Buyer shall be entitled to immediately retain for its own benefit those funds held as Development Security and any interest accrued thereon if the Development Security is posted as cash, and any amount of Development Security that Seller has not yet posted with Buyer shall be immediately due and payable by Seller to Buyer. There will be no amounts owed to Seller. The Parties agree that Buyer’s damages in the event of an Early Termination Date prior to the Commercial Operation Date caused by Seller’s Event of Default would be difficult or impossible to determine and that the damages set forth in this Section
11.3(a)(i) are a reasonable approximation of Buyer’s harm or loss. (ii) If Buyer is the Defaulting Party, then a Damage Payment shall be owed to Seller and shall equal the aggregate of all Settlement Amounts plus any and all other amounts due to or from Seller (as of the Early Termination Date) netted into a single amount.
There will be no amount owed to Buyer. Seller shall calculate, in a commercially reasonable manner, a Settlement Amount for the Terminated Transaction as of the Early Termination Date.
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. The Settlement Amount shall not include consequential, incidental, punitive, exemplary, indirect or business interruption damages. Without prejudice to Seller’s duty to mitigate, Seller shall not have to enter into replacement transactions to establish a Settlement Amount. The Parties agree that Seller’s damages in the event of an Early Termination Date prior to the Commercial Operation Date caused by Buyer’s default would be difficult or impossible to determine and that the damages set forth in this Section 11.3(a)(ii) are a reasonable approximation of Seller’s harm or loss.
(b) Termination Payment. On or After the Commercial Operation Date. The payment owed by the Defaulting Party to the Non-Defaulting Party for a Terminated Transaction 312
occurring after the Commercial Operation Date (“Termination Payment”) shall be the aggregate of all Settlement Amounts plus any and all other amounts due to or from the Non-Defaulting Party (as of the Early Termination Date) netted into a single amount. The Non-Defaulting Party shall calculate, in a commercially reasonable manner, a Settlement Amount for the Terminated Transaction as of the Early Termination Date. 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.
The Settlement Amount shall not include consequential, incidental, punitive, exemplary, indirect or business interruption damages. Without prejudice to the Non-Defaulting Party’s duty to mitigate, the Non-Defaulting Party shall not have to enter into replacement transactions to establish a Settlement Amount. Each Party agrees and acknowledges that (i) the actual damages that the Non-Defaulting Party would incur in connection with a Terminated Transaction would be difficult or impossible to predict with certainty, (ii) the Termination Payment described in this Section
11.3(b) is a reasonable and appropriate approximation of such damages, and (iii) the Termination Payment described in this Section 11.3(b) is the exclusive remedy of the Non-Defaulting Party in connection with a Terminated Transaction but shall not otherwise act to limit any of the Non-Defaulting Party’s rights or remedies if the Non-Defaulting Party does not elect a Terminated Transaction as its remedy for an Event of Default by the Defaulting Party.
11.4 Notice of Payment of Termination Payment or Damage Payment. As soon as practicable after a Terminated Transaction, but in no event later than sixty (60) days after the Early Termination Date (or such longer additional period, not to exceed an additional sixty (60) days, if the Non-Defaulting Party is unable, despite using commercially reasonable efforts, to calculate the Termination Payment or Damage Payment, as applicable, within such initial sixty (60)-day period despite exercising commercially reasonable efforts), Notice shall be given by the Non-Defaulting Party to the Defaulting Party of the amount of the Damage Payment or Termination Payment, as applicable, and whether the Termination Payment or Damage Payment, as applicable, is due to or from the Non-Defaulting Party. The Notice shall include a written statement explaining in reasonable detail the calculation of such amount and the sources for such calculation. The Termination Payment or Damage Payment, as applicable, shall be made to or from the Non-Defaulting Party, as applicable, within ten (10) Business Days after such Notice is effective.
11.5 Disputes With Respect to Termination Payment or Damage Payment. If the Defaulting Party disputes the Non-Defaulting Party’s calculation of the Termination Payment or Damage Payment, as applicable, in whole or in part, the Defaulting Party shall, within five (5) Business Days of receipt of the Non-Defaulting Party’s calculation of the Termination Payment or Damage Payment, as applicable, provide to the Non-Defaulting Party a detailed written explanation of the basis for such dispute. Disputes regarding the Termination Payment or Damage Payment, as applicable shall be determined in accordance with Article 15. 313
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ARTICLE 13
REPRESENTATIONS AND WARRANTIES; AUTHORITY
13.1 Seller’s Representations and Warranties. As of the Effective Date, Seller represents and warrants as follows:
(a) Seller is a limited liability company, duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation, and is qualified to conduct business in the state of California and each jurisdiction where the failure to so qualify would have a material adverse effect on the business or financial condition of Seller. (b) Seller has the power and authority to enter into and perform this Agreement and is not prohibited from entering into this Agreement or discharging and performing all covenants and obligations on its part to be performed under and pursuant to this Agreement. The execution, delivery and performance of this Agreement by Seller has been duly authorized by all necessary limited liability company action on the part of Seller and does not and will not require the consent of any trustee or holder of any indebtedness or other obligation of Seller or any other party to any other agreement with Seller.
(c) The execution and delivery of this Agreement, consummation of the transactions contemplated herein, and fulfillment of and compliance by Seller with the provisions of this Agreement will not conflict with or constitute a breach of or a default under any Law presently in effect having applicability to Seller, subject to any permits that have not yet been obtained by Seller, the documents of formation of Seller or any outstanding trust indenture, deed of trust, mortgage, loan agreement or other evidence of indebtedness or any other agreement or instrument to which Seller is a party or by which any of its property is bound. (d) This Agreement has been duly executed and delivered by Seller. This Agreement is a legal, valid and binding obligation of Seller enforceable in accordance with its terms, except as limited by laws of general applicability limiting the enforcement of creditors’ rights or by the exercise of judicial discretion in accordance with general principles of equity.
13.2 Seller’s Covenants. Seller covenants that commencing on the Effective Date and continuing through the Contract Term:
(a) The Facility will be located in the State of California. (b) Seller shall maintain Site Control throughout the Delivery Term. (c) Seller is responsible for obtaining and maintaining all permits necessary to construct and operate the Facility and Seller will be the applicant on any CEQA documents, if applicable.
13.3 Buyer’s Representations and Warranties. As of the Effective Date, Buyer represents and warrants as follows:
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(a) Buyer is a joint powers authority and a validly existing community choice aggregator, duly organized, validly existing and in good standing under the laws of the State of California and the rules, regulations and orders of the California Public Utilities Commission, and is qualified to conduct business in each jurisdiction of the Joint Powers Agreement members. All Persons making up the governing body of Buyer are the elected or appointed incumbents in their positions and hold their positions in good standing in accordance with the Joint Powers Agreement and other Law.
(b) Buyer has the power and authority to enter into and perform this Agreement and is not prohibited from entering into this Agreement or discharging and performing all covenants and obligations on its part to be performed under and pursuant to this Agreement, except where such failure does not have a material adverse effect on Buyer’s performance under this Agreement. The execution, delivery and performance of this Agreement by Buyer has been duly authorized by all necessary action on the part of Buyer and does not and will not require the consent of any trustee or holder of any indebtedness or other obligation of Buyer or any other party to any other agreement with Buyer.
(c) The execution and delivery of this Agreement, consummation of the transactions contemplated herein, and fulfillment of and compliance by Buyer with the provisions of this Agreement will not conflict with or constitute a breach of or a default under any Law presently in effect having applicability to Buyer, the documents of formation of Buyer or any outstanding trust indenture, deed of trust, mortgage, loan agreement or other evidence of indebtedness or any other agreement or instrument to which Buyer is a party or by which any of its property is bound.
(d) This Agreement has been duly executed and delivered by Buyer. This Agreement is a legal, valid and binding obligation of Buyer enforceable in accordance with its terms, except as limited by laws of general applicability limiting the enforcement of creditors’ rights or by the exercise of judicial discretion in accordance with general principles of equity. (e) Buyer warrants and covenants that with respect to its contractual obligations under this Agreement, it will not claim and affirmatively waives immunity on the grounds of sovereignty or similar grounds with respect to itself or its revenues or assets from (1) suit, (2) jurisdiction of court (provided that such court is located within a venue permitted in Law and under the Agreement), (3) relief by way of injunction, order for specific performance or recovery of property, (4) attachment of assets, or (5) execution or enforcement of any judgment; provided, however, that nothing in this Agreement shall waive the obligations or rights set forth in the California Tort Claims Act (California Government Code Section 810 et seq.). (f) Buyer is a “local public entity” as defined in Section 900.4 of the California Government Code.
13.4 General Covenants. Each Party covenants that commencing on the Effective Date and continuing throughout the Contract Term:
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(a) It shall continue to be duly organized, validly existing and in good standing under the Laws of the jurisdiction of its formation and to be qualified to conduct business in California and each jurisdiction where the failure to so qualify would have a material adverse effect on its business or financial condition;
(b) It shall maintain (or obtain from time to time as required) all regulatory authorizations necessary for it to legally perform its obligations under this Agreement; and (c) It shall perform its obligations under this Agreement in compliance with all terms and conditions in its governing documents and in material compliance with any Law.
13.5 Prevailing Wage. Seller shall use commercially reasonable efforts to ensure that all employees hired by Seller, and its contractors and subcontractors, that will perform construction work or provide services at the Site related to construction of the Facility are paid wages at rates not less than those prevailing for workers performing similar work in the locality as provided by applicable Laws, if any (“Prevailing Wage Requirement”). Nothing herein shall require Seller, its contractors and subcontractors to comply with, or assume liability created by other inapplicable provisions of any applicable labor Laws. Buyer agrees that Seller’s obligations under this Section
13.5 will be satisfied upon the execution of a project labor agreement related to construction of the Facility.
13.6 Workforce Development and Supplier Diversity. Seller acknowledges that Buyer will, from time to time, request voluntary disclosure of Seller’s certification status with the CPUC Supplier Clearinghouse, and voluntary disclosure regarding Seller’s efforts to work with diverse business enterprises, including women, minority, disabled veteran, and lesbian, gay, bisexual, transgender and/or persons with disabilities business enterprises in a form similar to Exhibit S.
13.7 Community Benefits. Seller pledges to deliver a total of $100,000 to Buyer for community benefits, which amount shall be paid within the first (5) Contract Years, in five (5) equal installments, each payable within sixty (60) days of the commencement of the applicable Contract Year. Buyer may direct such amount to community benefits initiatives that directly benefit stakeholders in Buyer’s service area. Buyer shall have sole discretion to determine which initiatives will be funded and will provide Seller notice describing the initiatives Buyer intends to fund. Notwithstanding anything to the contrary in this Section 13.6, Buyer will not make any public statement about the Facility, this Agreement, Seller, or Seller’s Affiliates in connection with any community benefits initiatives funded with Seller’s community benefits funds paid through this Section 13.6 without the prior written consent of Seller.
ARTICLE 14
ASSIGNMENT
14.1 General Prohibition on Assignments. Except as provided below in this Article 14, neither Party may assign this Agreement or its rights or obligations under this Agreement without the prior written consent of the other Party, which consent shall not be unreasonably withheld, conditioned or delayed. Any Change of Control of Seller (whether voluntary or by 318
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(b) For avoidance of doubt, although “agreement” is not capitalized in Section
15.1(a), the parties intend for “agreement” to mean this Agreement, and for “party” and “parties” to refer to the Party and Parties as set forth in the preamble to this Agreement. (c) 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 of the State of California sitting in the County of San Diego.
15.2 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, informally and inexpensively. If the Parties are unable to resolve a dispute arising hereunder within the earlier of either thirty (30) days of initiating such discussions, or within forty (40) days after Notice of the dispute, the Parties shall submit the dispute to mediation prior to seeking any and all remedies available to them at Law in or equity. The Parties will cooperate in selecting a qualified neutral mediator selected from a panel of neutrals and in scheduling the time and place of the mediation as soon as reasonably possible, but in no event later than thirty (30) days after the request for mediation is made. The Parties agree to participate in the mediation in good faith and to share the costs of the mediation, including the mediator’s fee, equally, but such shared costs shall not include each Party’s own attorneys’ fees and costs, which shall be borne solely by such Party. If the mediation is unsuccessful, then either Party may seek any and all remedies available to it at law or in equity, subject to the limitations set forth in this Agreement.
15.3 Attorneys’ Fees. In any proceeding brought to enforce this Agreement or because of the breach by any Party of any covenant or condition herein contained, the prevailing Party shall be entitled to reasonable attorneys’ fees (including reasonably allocated fees of in-house counsel) in addition to court costs and any and all other costs recoverable in said action.
ARTICLE 16
INDEMNIFICATION
16.1 Indemnification.
(a) Each Party (the “Indemnifying Party”) agrees to indemnify, defend and hold harmless the other Party and its Affiliates, directors, officers, employees and agents (collectively, the “Indemnified Party”) from and against all third-party claims, demands, losses, liabilities, penalties, and expenses (including reasonable attorneys’ fees) (i) for personal injury or death to Persons and damage to the property of any third party to the extent arising out of, resulting from, or caused by the negligent or willful misconduct of the Indemnifying Party, its Affiliates, its directors, officers, employees, or agents, or (ii) for third-party claims resulting from the Indemnifying Party’s breach (including inaccuracy of any representation of warranty made hereunder), performance or non-performance of its obligations under this Agreement (“Indemnifiable Losses”).
(b) Notwithstanding any other provision of this Agreement, Seller shall indemnify, defend, and hold harmless Buyer’s Indemnified Parties, from any claim, liability, loss, 321
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requirement applicable to the Receiving Party, or (b) in order to enforce this Agreement; provided, each Party shall, to the extent practicable, use reasonable efforts to prevent or limit the disclosure.
The Parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, this confidentiality obligation. The Parties agree and acknowledge that nothing in this Section 18.2 prohibits a Party from disclosing any one or more of the commercial terms of a transaction (other than the name of the other Party unless otherwise agreed to in writing by the Parties) to any industry price source for the purpose of aggregating and reporting such information in the form of a published energy price index.
(b) The Parties acknowledge and agree that the Agreement and any transactions entered into in connection herewith are subject to the requirements of the California Public Records Act (California Government Code Section 7920 et seq.). In order to designate information as confidential, the Disclosing Party must clearly stamp and identify the specific portion of the material designated with the word “Confidential.” The Parties agree not to over-designate material as Confidential Information. Over-designation includes stamping whole agreements, entire pages or series of pages as “Confidential” that clearly contain information that is not Confidential Information.
18.3 Requested Confidential Information. Upon request or demand of any third person or entity not a Party hereto to Buyer pursuant to the California Public Records Act for production, inspection and/or copying of Confidential Information (“Requested Confidential Information”), Buyer shall as soon as practical notify Seller in writing via email that such request has been made. Seller shall be solely responsible for taking at its sole expense whatever legal steps are necessary to prevent release of the Requested Confidential Information to the third party by Buyer. If Seller takes no such action after receiving the foregoing notice from Buyer, Buyer shall, at its discretion, be permitted to comply with the third party’s request or demand and is not required to defend against it. If Seller does take or attempt to take such action, Buyer shall provide timely and reasonable cooperation to Seller, if requested by Seller, and Seller agrees to indemnify and hold harmless Buyer and Buyer’s Indemnified Parties from any claims, liability, award of attorneys’ fees, or damages, and to defend any action, claim or lawsuit brought against any of Buyer or Buyer’s Indemnified Parties for Buyer’s refusal to disclose any Requested Confidential Information.
18.4 Irreparable Injury; Remedies. Receiving Party acknowledges that its obligations hereunder are necessary and reasonable in order to protect Disclosing Party and the business of Disclosing Party, and expressly acknowledges that monetary damages would be inadequate to compensate Disclosing Party for any breach or threatened breach by Receiving Party of any covenants and agreements set forth herein. Accordingly, Receiving Party acknowledges that any such breach or threatened breach will cause irreparable injury to Disclosing Party and that, in addition to any other remedies that may be available, in law, in equity or otherwise, Disclosing Party will be entitled to obtain injunctive relief against the threatened breach of this Agreement or the continuation of any such breach, without the necessity of proving actual damages.
18.5 Further Permitted Disclosure. Notwithstanding anything to the contrary in this Article 18, Confidential Information may be disclosed by the Receiving Party to any of its agents, consultants, contractors, trustees, or actual or potential financing parties (including, in the case of 325
Seller, its Lender(s)) or investors or purchasers (including tax credit buyers), so long as such Person to whom Confidential Information is disclosed agrees in writing to be bound by confidentiality provisions that are no less stringent than those in this Article 18 to the same extent as if it were a Party. Seller shall provide written notice to Buyer of any disclosure of Confidential Information pursuant to this Section 18.4, including the identity of the party receiving such Confidential Information.
18.6 Press Releases. Neither Party shall issue (or cause its Affiliates to issue) a press release regarding the transactions contemplated by this Agreement unless both Parties have agreed upon the contents of any such press release. A Party’s consent shall not be unreasonably withheld, conditioned or delayed.
ARTICLE 19
MISCELLANEOUS
19.1 Entire Agreement; Integration; Exhibits. This Agreement, together with the Cover Sheet and Exhibits attached hereto constitutes the entire agreement and understanding between Seller and Buyer 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. In the event of a conflict between the provisions of this Agreement and those of the Cover Sheet or any Exhibit, the provisions of first the Cover Sheet, and then this Agreement shall prevail, and such Exhibit shall be corrected accordingly. 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.
19.2 Amendments. This Agreement may only be amended, modified or supplemented by an instrument in writing executed by duly authorized representatives of Seller and Buyer; provided, that, for the avoidance of doubt, this Agreement may not be amended by electronic mail communications.
19.3 No Waiver. Waiver by a Party of any default by the other Party shall not be construed as a waiver of any other default.
19.4 No Agency, Partnership, Joint Venture or Lease. Seller and the agents and employees of Seller shall, in the performance of this Agreement, act in an independent capacity and not as officers or employees or agents of Buyer. Under this Agreement, Seller and Buyer intend to act as energy seller and energy purchaser, respectively, and do not intend to be treated as, and shall not act as, partners in, co-venturers in or lessor/lessee with respect to the Facility or any business related to the Facility. This Agreement shall not impart any rights enforceable by any third party (other than a permitted successor or assignee bound to this Agreement) or, to the extent set forth herein, any Lender and/or Indemnified Party.
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19.5 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.
19.6 Mobile-Sierra. Notwithstanding any other provision of this Agreement, neither Party shall seek, nor shall they support any third party seeking, to prospectively or retroactively revise the rates, terms or conditions of service of this Agreement through application or complaint to FERC pursuant to the provisions of Section 205, 206 or 306 of the Federal Power Act, or any other provisions of the Federal Power Act, absent prior written agreement of the Parties. Further, absent the prior written agreement in writing by both Parties, the standard of review for changes to the rates, terms or conditions of service of this Agreement proposed by a Party shall be the “public interest” application of the “just and reasonable” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) and clarified by Morgan Stanley Capital Group, Inc. v. Public Util. Dist. No. 1 of Snohomish, 554 U.S. 527 (2008), and NRG Power Marketing LLC v. Maine Public Utility Commission, 558 U.S. 527 (2010). Changes proposed by a non-Party or FERC acting sua sponte shall be subject to the most stringent standard permissible under Law.
19.7 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.
19.8 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, 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.
19.9 Binding Effect. This Agreement shall inure to the benefit of and be binding upon the Parties and their respective successors and permitted assigns.
19.10 No Recourse to Members of Buyer. Buyer is organized as a Joint Powers Authority in accordance with the Joint Exercise of Powers Act of the State of California (California Government Code Section 6500, et seq.) pursuant to its Joint Powers Agreement and is a public entity separate from its constituent members. Buyer shall solely be responsible for all debts, obligations and liabilities accruing and arising out of this Agreement. Seller shall have no rights and shall not make any claims, take any actions or assert any remedies against any of Buyer’s constituent members, or the employees, directors, officers, consultants or advisors of Buyer or its constituent members, in connection with this Agreement. 327
19.11 Forward Contract. The Parties acknowledge and agree that this Agreement constitutes a “forward contract” within the meaning of the U.S. Bankruptcy Code, and Buyer and Seller 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.
19.12 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 of this Agreement and which do not involve the assumption 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.
19.13 Change in Electric Market Design. If a change in the CAISO Tariff renders this Agreement or any provisions hereof incapable of being performed or administered, then any Party may request that Buyer and Seller enter into negotiations to make the minimum changes to this Agreement necessary to make this Agreement capable of being performed and administered, while attempting to preserve to the maximum extent possible the benefits, burdens, and obligations set forth in this Agreement as of the Effective Date. Upon delivery of such a request, Buyer and Seller shall engage in such negotiations in good faith. If Buyer and Seller are unable, within sixty (60) days after delivery of such request, to agree upon changes to this Agreement or to resolve issues relating to changes to this Agreement, then any Party may submit issues pertaining to changes to this Agreement to the dispute resolution process set forth in Article 15. Notwithstanding the foregoing, (i) a change in cost shall not in and of itself be deemed to render this Agreement or any of the provisions hereof incapable of being performed or administered, and (ii) all of the unaffected provisions of this Agreement shall remain in full force and effect during any period of such negotiation or dispute resolution.
19.14 Service Contract. The Parties intend for the Agreement to be a service contract as described in Section 7701(e) of the Internal Revenue Code of 1986, as amended. [Signatures on following page]
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IN WITNESS WHEREOF, the Parties have caused this Agreement to be duly executed as of the Effective Date.
IP DARDEN IV, LLC, a Delaware limited
liability company
By:
Name:
Title:
SAN DIEGO COMMUNITY POWER, a
California joint powers authority
By:
Name:
Title:
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EXHIBIT A
FACILITY DESCRIPTION
Project Name: Darden IV
Site includes all or some of the following APNs:
County: Fresno County, California
CEQA Lead Agency: California Energy Commission
Zip Code: 93608
Latitude and Longitude:
Facility Description: A 91.48 MW-AC solar photovoltaic electricity generating facility co-located with a 91.48 MW-AC lithium-ion battery energy storage system.
Delivery Point: Facility PNode on the CAISO Grid.
Generating Facility Meter and Metering Points: See Exhibit R.
Storage Facility Meter and Metering Points: See Exhibit R. 330
PNode: If not available at the Effective Date, the PNode shall be updated by mutual agreement of Buyer and Seller prior to the initial delivery of Test Energy hereunder to reflect the PNode corresponding to the Facility’s Interconnection Point with the CAISO Grid.
Interconnection Point: PG&E Los Banos-Midway #2 substation Transmission Provider: Pacific Gas & Electric
Local Capacity Area and Sub-Local Capacity Area:
Additional Information: Site plan and Darden Project Boundaries provided below in Annex 1 to this Exhibit A.
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“Development Cure Period”) for the duration of any and all delays arising out of the following circumstances to the extent the following circumstances are not the result of Seller’s failure to take all commercially reasonable actions to meet its requirements and deadlines:
a. a Force Majeure Event occurs; or
b. the
Interconnection Facilities or Network Upgrades are not complete and ready for the Facility to connect and sell Product at the Delivery Point by the Guaranteed Commercial Operation Date, provided such delays are outside the reasonable control of Seller; or
c. Buyer has not made all necessary arrangements to receive the Facility Energy at the Delivery Point by the Guaranteed Commercial Operation Date.
An extension of the Guaranteed Construction Start Date for a Development Cure Period shall automatically extend the Guaranteed Commercial Operation Date on a day-for-day basis. Notwithstanding anything in this Agreement to the contrary, the cumulative extensions granted under the Development Cure Period (other than the extensions granted pursuant to clause 4(c) above or to the extent any delays are solely due to Buyer’s breach) shall not exceed , for any reason, including a Force Majeure Event, and the cumulative extensions granted to the Guaranteed Commercial Operation Date by the payment of Commercial Operation Delay Damages and any Development Cure Period(s) (other than the extensions granted pursuant to clause 4(c) above) shall not exceed . Notwithstanding anything to the contrary,
no Development Cure Period extension shall be given if (i) the delay was the result of Seller’s failure to take all commercially reasonable actions to meet its requirements and deadlines, or (ii) Seller failed to provide requested documentation as provided below.
Except as set forth in Section 10.3 regarding Force Majeure Event notice requirements, Seller shall provide prompt written notice to Buyer of a Development Cure Period delay, but in no case more than after Seller became aware of the impact of such delay, except that in the case of a delay occurring within of the Guaranteed Commercial Operation Date, or after such date, Seller must provide written notice within of Seller becoming aware of the impact of such delay. Upon request from Buyer, Seller shall provide documentation demonstrating to Buyer’s reasonable satisfaction that the delays described above did not result from Seller’s actions or failure to take commercially reasonable actions.
5. Failure to Reach Guaranteed Generating Capacity or Guaranteed Storage Capacity. a. Guaranteed Generating Capacity. If, at Commercial Operation, the Installed Generating Capacity is less than one hundred percent (100%) of the Guaranteed Generating Capacity, Seller shall have after the Commercial Operation Date to install additional capacity such that the Installed Generating Capacity one hundred percent (100%) of the
Guaranteed Generating Capacity, and Seller shall provide to Buyer a new certificate 335
substantially in the form attached as Exhibit I hereto specifying the new Installed Generating Capacity. If Seller fails to construct the Guaranteed Generating Capacity by such date, Seller shall pay “Capacity Damages” to Buyer, in an amount equal to for each MW
that the Guaranteed Generating Capacity exceeds the Installed Generating Capacity, and the Guaranteed Generating Capacity and other applicable portions of the Agreement shall be adjusted accordingly. Capacity Damages shall not be offset or reduced by the payment of Construction Delay Damages, Commercial Operation Delay Damages, or any other form of liquidated damages under this Agreement. b. Guaranteed Storage Capacity. If, at Commercial Operation, the Installed Storage Capacity is less than one hundred percent (100%) of the Guaranteed Storage Capacity, Seller shall have after the Commercial Operation Date to install additional capacity such that the Installed Storage Capacity one hundred percent (100%) of the Guaranteed Storage Capacity, and Seller shall provide to Buyer a new certificate substantially in the form attached as Exhibit I hereto specifying the new Installed Storage Capacity. If Seller fails to construct the Guaranteed Storage Capacity by such date, Seller shall pay “Storage Capacity Damages” to Buyer, in an amount equal to
for each MW that the Guaranteed Storage Capacity exceeds the Installed Storage Capacity, and other applicable portions of the Agreement shall be adjusted accordingly. Storage Capacity Damages shall not be offset or reduced by the payment of Construction Delay Damages, Commercial Operation Delay Damages, or any other form of liquidated damages under this Agreement. 336
EXHIBIT C
COMPENSATION
Buyer shall compensate Seller for the Product in accordance with this Exhibit C (the “Monthly Product Payment”).
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EXHIBIT D
SCHEDULING COORDINATOR RESPONSIBILITIES
(a) Buyer as Scheduling Coordinator for the Facility. Upon Initial Synchronization of the Facility to the CAISO Grid, Buyer shall be the Scheduling Coordinator or designate a qualified third party to provide Scheduling Coordinator services with the CAISO for the Facility for both the delivery and the receipt (as applicable) of Test Energy, Charging Energy, Discharging Energy and the Product at the Delivery Point. Prior to the Initial Synchronization of the Facility, Seller or Seller’s designee shall be the Scheduling Coordinator for the Facility. At least thirty (30) days prior to the Initial Synchronization, (i) Seller shall take all actions and execute and deliver to Buyer and the CAISO all documents necessary to authorize or designate Buyer (or Buyer’s designee) as the Scheduling Coordinator for the Facility effective as of the Initial Synchronization of the Facility to the CAISO Grid, (ii) Seller shall make available to Buyer's Scheduling Coordinator all real-time telemetry data reasonably necessary for Buyer’s Scheduling Coordinator to perform its duties as Buyer’s Scheduling Coordinator, including the relevant operational data specified in this Exhibit D, Section (i), and (iii) Buyer shall, and shall cause its designee to, take all actions and execute and deliver to Seller and the CAISO all documents necessary to authorize or designate Buyer or its designee as the Scheduling Coordinator for the Facility effective as of the Initial Synchronization of the Facility to the CAISO Grid. On and after Initial Synchronization of the Facility to the CAISO Grid. Seller shall not authorize or designate any other party to act as the Facility’s Scheduling Coordinator, nor shall Seller perform for its own benefit the duties of Scheduling Coordinator, nor shall Seller perform for its own benefit the duties of Scheduling Coordinator, and Seller shall not revoke Buyer’s authorization to act as the Facility’s Scheduling Coordinator unless agreed to by Buyer. Buyer (as the Facility’s SC) shall submit Schedules to the CAISO in accordance with this Agreement and the applicable CAISO Tariff, protocols and Scheduling practices for Product on a day-ahead, hour-ahead, fifteen-minute market or real time or other CAISO market basis that may develop after the Effective Date, as determined by Buyer.
(b) Notices. Buyer (as the Facility’s SC) shall provide Seller with access to a web-based system through which Seller shall submit to Buyer and the CAISO all notices and updates required under the CAISO Tariff regarding the Facility’s status, including, but not limited to, all outage requests, forced outages, forced outage reports, clearance requests, or must offer waiver forms. Seller shall cooperate with Buyer to provide such notices and updates. If the web-based system is not available, Seller shall promptly submit such information to Buyer and the CAISO (in order of preference) telephonically, by electronic mail, or fax transmission to the personnel designated to receive such information.
(c) CAISO Costs and Revenues. Except as otherwise set forth below, Buyer (as Scheduling Coordinator for the Facility) shall be responsible for CAISO costs (including Charging Energy, penalties, Imbalance Energy costs (except as otherwise set forth in this Agreement), and other charges) and shall be entitled to all CAISO revenues (including Discharging Energy, credits, Imbalance Energy revenues, and other payments), including revenues associated with CAISO Dispatches, bid cost recovery, Inter-SC Trade credits, or other credits in respect of the Product Scheduled or delivered from the Facility. Seller shall assume all liability and reimburse Buyer for any and all costs, charges or sanctions associated with delivery of Resource 339
Adequacy Benefits from the Facility (including Non-Availability Charges (as defined in the CAISO Tariff)); provided, any Availability Incentive Payments (as defined in the CAISO Tariff) are for the benefit of Seller and for Seller’s account and that any Non-Availability Charges (as defined in the CAISO Tariff) are the responsibility of Seller and for Seller’s account. In addition, Seller shall assume all liability and reimburse Buyer for any and all CAISO penalties and Imbalance Energy costs (i) incurred by Buyer resulting from any failure by Seller to abide by the CAISO Tariff requirements imposed on it as Facility owner (but not in connection with obligations of Buyer hereunder) or the outage notification requirements set forth in this Agreement (except to the extent such non-compliance is caused by Buyer’s failure to perform its duties as Scheduling Coordinator for the Facility), or (ii) to the extent arising as a result of Seller’s failure to comply with a timely Curtailment Order if such failure results in incremental costs to Buyer. In addition, if during the Delivery Term, the CAISO implements or has implemented any sanction or penalty related to scheduling, outage reporting, or generator operation, and any such sanctions or penalties are imposed upon the Facility or to Buyer as Scheduling Coordinator due to failure by Seller to abide by the CAISO Tariff or the outage notification requirements set forth in this Agreement, the cost of the sanctions or penalties shall be Seller’s responsibility. (d) CAISO Settlements. Buyer (as the Facility’s SC) shall be responsible for all settlement functions with the CAISO related to the Facility. Buyer shall render a separate invoice to Seller for any CAISO payments, charges or penalties (“CAISO Charges Invoice”) for which Seller is responsible under this Agreement. CAISO Charges Invoices shall be rendered after settlement information becomes available from the CAISO that identifies any CAISO charges.
Notwithstanding the foregoing, Seller acknowledges that the CAISO will issue additional invoices reflecting CAISO adjustments to such CAISO charges. Buyer will review, validate, and if requested by Seller under paragraph (e) below, dispute any charges that are the responsibility of Seller in a timely manner and consistent with Buyer’s existing settlement processes for charges that are Buyer’s responsibilities. Subject to Seller’s right to dispute and to have Buyer pursue the dispute of any such invoices, Seller shall pay the amount of CAISO Charges Invoices within ten (10) Business Days of Seller’s receipt of the CAISO Charges Invoice. If Seller fails to pay such CAISO Charges Invoice within that period, Buyer may net or offset any amounts owing to it for such CAISO Charges Invoices against any future amounts it may owe to Seller under this Agreement. The obligations under this Section with respect to payment of CAISO Charges Invoices in respect of performance prior to the expiration or termination of this Agreement shall survive the expiration or termination of this Agreement. (e) Dispute Costs. Buyer (as the Facility’s SC) may be required by Seller to dispute CAISO settlements in respect of the Facility. Seller agrees to pay Buyer’s costs and expenses (including reasonable attorneys’ fees) associated with its involvement with such CAISO disputes to the extent they relate to CAISO charges payable by Seller with respect to the Facility that Seller has directed Buyer to dispute.
(f) Terminating Buyer’s Designation as Scheduling Coordinator. At least thirty (30) days prior to expiration of this Agreement or as soon as reasonably practicable upon an earlier termination of this Agreement, the Parties will take all actions necessary to terminate the designation of Buyer as Scheduling Coordinator for the Facility as of 11:59 p.m. on such expiration date.
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(g) Master Data File and Resource Data Template; Master Resource Database.
The Parties will collaborate to comply with the applicable deadlines for filing and updating the information for the Facility in the CPUC Master Resource Database and Master Data File. Seller shall provide the data to Buyer that is required for the CAISO’s Master Data File and Resource Data Template (or successor data systems) for the Facility consistent with this Agreement at least five (5) Business Days before the deadline for submission to CAISO and Buyer (as SC) shall promptly provide such data to CAISO. Seller shall provide the data that is required for the CPUC Master Resource Database for the Facility consistent with this Agreement to Buyer for review and approval at least five (5) Business Days before the deadline for submission of such to the CPUC. Neither Party shall change such CAISO or CPUC data without the other Party’s prior written consent. At least once per Contract Year, Seller shall review and confirm that the data provided for the CAISO’s Master Data File and Resource Data Template (or successor data systems) and CPUC Master Resource Database for this Facility remains consistent with the actual operating characteristics of the Facility and provide such information to Buyer for review at least five (5) Business Days prior to submission to the CAISO or CPUC as applicable. (h) NERC Reliability Standards. Buyer (as Scheduling Coordinator) shall cooperate reasonably with Seller to the extent necessary to enable Seller to comply, and for Seller to demonstrate Seller’s compliance with, NERC reliability standards. This cooperation shall include the provision of information in Buyer’s possession that Buyer (as Scheduling Coordinator) has provided to the CAISO related to the Facility or actions taken by Buyer (as Scheduling Coordinator) related to Seller’s compliance with NERC reliability standards. 341