Agenda packet — San Diego Community Power Board of Directors, April 23, 2026

AGENDA – BOARD OF DIRECTORS – SAN DIEGO COMMUNITY POWER AGENDA
Regular Meeting
Board of Directors
Thursday, April 23, 2026
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, Board members may also attend and participate virtually in the meeting, pursuant to the Brown Act (Gov.

Code § 54953). As a convenience to the public, San Diego Community Power provides a Zoom teleconference 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 virtually attending the meeting), 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 members of the public include their 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 chairperson. Comments may be provided in one of the following ways:

1. Oral comments during a meeting. Anyone attending in person who wishes 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. When participating in a Zoom video conference by computer or mobile phone, use the “Raise Hand” feature. This will notify the moderator that a member of the public wishes to speak during a specific item on the agenda or during the non-agenda public comment period. Members of the public will not be shown on video but will be able to speak when called upon. When participating in the meeting using the Zoom dial-in number, press *9 to request to speak. Comments will be limited to three minutes. 1 AGENDA – BOARD OF DIRECTORS – SAN DIEGO COMMUNITY POWER

2. Written Comments. Written public comments must be submitted prior to the start of the meeting to [email protected]. Members of the public are asked to indicate a specific agenda item when submitting comments. All written comments received prior to the meeting will be provided to members of the Board. At the discretion of the chairperson, the first 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 received after the start of the meeting will be collected, sent to the members of Board and become part of the public record.

If members of the public have any materials to be distributed to the Board, they should be sent to [email protected], who will distribute the information to Board members.

The public may participate using the following remote options:

Teleconference Meeting Webinar
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

LAND ACKNOWLEDGMENT

SPECIAL PRESENTATIONS AND INTRODUCTIONS
- 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.
2 AGENDA – BOARD OF DIRECTORS – SAN DIEGO COMMUNITY POWER

CONSENT CALENDAR
All matters are approved by one motion without discussion unless a member of the Board 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 March 26, 2026, Meeting Minutes

2. Receive and File Update on Programs

3. Receive and File Update on Power Services

4. Receive and File Update on Customer Operations

5. Receive and File Update on IT and Data Analytics

6. Receive and File Update on Human Resources

7. Receive and File Update on Marketing, Public Relations, and Local Government Affairs

8. Receive and File Treasurer’s Report for Seven-Month Period Ending January 31, 2026

9. Receive and File Community Advisory Committee Monthly Update

10. Receive and File Update on Regulatory and Legislative Affairs

11. Approve Agreement Renewal with Keyes & Fox LLP for Regulatory Counsel Services through May 31, 2028, for a Total Not-to-Exceed Contract Amount of $1,200,000

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.

12. Consider and Approve Appointment of Molly Hintlian to the Community Advisory Committee to fill City of Encinitas Vacancy
Recommendation: Consider and approve appointment of Molly Hintlian to the Community Advisory Committee (CAC) to fill the City of Encinitas vacancy.
3 AGENDA – BOARD OF DIRECTORS – SAN DIEGO COMMUNITY POWER

13. Approve Ten-Year Agreements with the City of San José to Sell MTR Eligible Resource Adequacy and Buy System Resource Adequacy for a total net notional of $4,500,000 Recommendation: Approve Ten-Year Agreements with the City of San José as follows:
a. Sell MTR Eligible Resource Adequacy for a total of $43,200,000 and authorize the Chief Executive Officer to execute the agreement.
b. Buy System Resource Adequacy for a total of $47,700,000 and authorize the Chief Executive Officer to execute the agreement.

14. Review and Approve 2026 Community Power Rates Adjustment, to be effective as of May 1, 2026
Recommendation: Review and approve rate adjustments for the PowerOn and PowerBase services, as contained in Attachment A, to go into effect as of May 1, 2026. The recommendation includes continuing to offer San Diego Community Power (Community Power) default PowerOn service electricity generation/commodity rates that are 4% cheaper compared to San Diego Gas and Electric’s (SDG&E) generation rates and PowerBase service electricity generation rates that are 10% cheaper than San Diego Gas and Electric’s generation rates. Power100 and Power100 Green-e Certified (Green-e Plus) will maintain premiums of $0.01/kWh and $0.02/kWh, respectively, compared to PowerOn.

15. Receive and File Local Development Strategy
Recommendation: Receive and File Informational Update on San Diego Community Power’s Local Development Strategy.

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.

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 Board of Directors will adjourn until the next regular meeting scheduled for Thursday, May 28, 2026, at 5 p.m.

AGENDA – BOARD OF DIRECTORS – SAN DIEGO COMMUNITY POWER Compliance with the Americans with Disabilities Act
Community Power Board of Directors meetings comply with the Americans with Disabilities Act.

Individuals with a disability who require a modification or accommodation, including auxiliary aids or services, to participate in the public meeting may contact 888-382-0169 or [email protected]. Requests for disability-related modifications or accommodations require varying 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 sdcommunitypower.org/resources/meeting-notes. Late-arriving documents related to a Board meeting item are distributed to Members prior to or during the Board meeting and are available for public review as required by law. Public records, including agenda-related documents, can be requested electronically from [email protected] or by mailing San Diego Community Power, Attention: Clerk of the Board, 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 MEETING MINUTES – BOARD OF DIRECTORS – COMMUNITY POWER – MARCH 26, 2026

SAN DIEGO COMMUNITY POWER

BOARD OF DIRECTORS
Regular Meeting Minutes
March 26, 2026
Don L. Nay Port Administration Boardroom
3165 Pacific Hwy.

San Diego, CA 92101

WELCOME

CALL TO ORDER
Vice Chair Yamane called the Community Power Board of Directors regular meeting to order at 5:00 p.m.

ROLL CALL
PRESENT: Vice Chair Yamane, City of National City; Director Inzunza, City of Chula Vista; Director San Antonio, City of Encinitas; Director Suzuki, City of La Mesa and Alternate Director LaCava, City of San Diego
ABSENT: Chair Lawson-Remer, County of San Diego and Director Fisher, City of Imperial Beach
Staff Present: Chief Executive Officer Burns; General Counsel Tyagi; Senior Strategic Finance Manager/Interim Treasurer Spengler; Senior Rates Analyst Polonsky; Senior Director of Data Analytics and Customer Operations Utouh; Associate Director of IT and Data Analytics Yi; Senior Community Engagement Manager Crespo; Clerk of the Board Hernandez; and Assistant Clerk of the Board Vences

CLOSED SESSION
There were no public comments on Closed Session.

The Board recessed to Closed Session at 5:02 p.m.

CONFERENCE WITH LEGAL COUNSEL- ANTICIPATED LITIGATION
Government Code section 54956.9(d)(4): One matter.
6 MEETING MINUTES – BOARD OF DIRECTORS – COMMUNITY POWER – MARCH 26, 2026 CALL TO ORDER – OPEN SESSION
The Board reconvened to Open Session at 5:12 p.m.

REPORT ON CLOSED SESSION
Ms. Tyagi reported that the Board voted unanimously to initiate an appeal of Public Utilities Commission Decision 25-12-008, a Decision Approving San Diego Gas and Electric Company's 2026 Electric Procurement Revenue Requirement Forecast, 2026 Electric Sales Forecast and Greenhouse Gas Related Forecasts.

PLEDGE OF ALLEGIANCE
Director Inzunza led the Pledge of Allegiance.

LAND ACKNOWLEDGMENT
Vice Chair Yamane acknowledged the Kumeyaay Nation and all the original stewards of the land.

SPECIAL PRESENTATIONS AND INTRODUCTIONS
Vice Chair Yamane welcomed new employees Michelle Phillips, Senior Financial Analyst and Brandon Lewis, Communications Associate, to introduce themselves.

ITEMS TO BE ADDED, WITHDRAWN OR REORDERED ON THE AGENDA Vice Chair Yamane noted that at the request of staff, Item No. 13; Review and approve 2026 Community Power Rates Adjustment, to be effective as of April 1, 2026, would be pulled from the agenda.

Ms. Burns informed the Board that Community Power is waiting for additional information from San Diego Gas & Electric (SDG&E).
7 MEETING MINUTES – BOARD OF DIRECTORS – COMMUNITY POWER – MARCH 26, 2026

PUBLIC COMMENTS
There were no public comments.

CONSENT CALENDAR

1. Approve February 26, 2026, Meeting Minutes

2. Receive and File Update on Programs

3. Receive and File Update on Power Services

4. Receive and File Update on Customer Operations

5. Receive and File Update on IT and Data Analytics

6. Receive and File Update on Human Resources

7. Receive and File Update on Marketing, Public Relations, and Local Government Affairs

8. Receive and File Treasurer’s Report for Six-Month Period Ending December 31, 2025

9. Receive and File Community Advisory Committee Monthly Update

10. Receive and File Update on Regulatory and Legislative Affairs

11. Adoption of Resolution 2026-06, Authorizing San Diego Community Power to Join the California Community Choice Financing Authority as a Founding Member There were no public comments on Consent Item Nos. 1-11.

Motioned by Director Inzunza and seconded by Director San Antonio to approve Consent Calendar Item Nos. 1-11. The motion carried 5/0 as follows:

AYES: Vice Chair Yamane, Directors Inzunza, San Antonio, Suzuki, and Alternate Director LaCava
NOES: None
ABSTAINED: None
ABSENT: Chair Lawson-Remer and Director Fisher

REGULAR AGENDA

12. Community Advisory Committee Quarterly Update
8 MEETING MINUTES – BOARD OF DIRECTORS – COMMUNITY POWER – MARCH 26, 2026 Community Advisory Committee (CAC) Chair Harris provided a quarterly report and shared information about the current and future vacancies.

There were no public comments on Item No. 12.

After Board member comments, the Community Advisory Committee Quarterly Update was received and filed.

14. Adoption of Resolution 2026-07, Approving the Rate Stabilization Reserve Policy Ms. Burns introduced the item and turned it over to Messrs. Spengler and Polonsky to provide an overview of the proposed Rate Stabilization Reserve Policy.

There were no public comments on Item No. 14.

Motioned by Director Inzunza and seconded by Director Suzuki to adopt Resolution No. 2026- 07, approving the Rate Stabilization Reserve Policy. The motion carried 5/0 as follows:

AYES: Vice Chair Yamane, Directors Inzunza, San Antonio, Suzuki, and Alternate Director LaCava
NOES: None
ABSTAINED: None
ABSENT: Chair Lawson-Remer and Director Fisher

15. Approve Agreement with Calpine Community Energy, LLC for Data Management and Customer Center Services for an Estimated $12,701,612 per Fiscal Year, Plus a Maximum CPI Annual Increase of 4.0% for an Initial 3-year Term with Renewals Mr. Utouh provided an overview of the proposed agreement with Calpine.

There were no public comments on Item No. 15.

Motioned by Director Suzuki and seconded by Director San Antonio to approve agreement with Calpine Community Energy, LLC for Data Management and Customer Center Services for an initial 3-year term beginning in May 2026, with an option for one two-year renewal and yearly renewals thereafter and authorize the Chief Executive Officer to execute the contract.

The motion carried 5/0 as follows:

AYES: Vice Chair Yamane, Directors Inzunza, San Antonio, Suzuki, and Alternate Director LaCava
NOES: None
ABSTAINED: None
ABSENT: Chair Lawson-Remer and Director Fisher
9 MEETING MINUTES – BOARD OF DIRECTORS – COMMUNITY POWER – MARCH 26, 2026

16. Approve Amendment No. 2 to Professional Services Agreement with Wipro Connected Services (formerly known as Harman Connected Services, Inc.) for Enterprise Data Platform (EDP) Phase 2 Implementation and Managed Services for an additional not-to-exceed amount of $530,000 Mr. Yi provided an overview of the proposed agreement with Wipro Connected Services.

There were no public comments on Item No. 16.

After Board member comments and questions, motioned by Director Inzunza and seconded by Director Suzuki to approve amendment No. 2 to the Professional Services Agreement with Wipro Connected Services (formerly known as Harman Connected Services, Inc.) for additional scope of work and increase the not-to-exceed amount by $530,000 for a revised total contract not-to-exceed amount of $1,751,000 and authorize the Chief Executive Officer to execute the contract. The motion carried 5/0 as follows:

AYES: Vice Chair Yamane, Directors Inzunza, San Antonio, Suzuki, and Alternate Director LaCava
NOES: None
ABSTAINED: None
ABSENT: Chair Lawson-Remer and Director Fisher

17. Community Benefits Framework
Ms. Burns introduced the item and turned it over to Ms. Crespo to provide an overview of the Community Benefits Framework.

There were no public comments on Item No. 17.

After Board member comments and questions, the Community Benefits Framework was received and filed.

18. Announcement of Public Investment Grade Credit Rating from S&P Global Ratings Ms. Burns announced Community Power’s “A” Issuer Credit Rating with a Stable Outlook from S&P Global Ratings and thanked everyone for their commitment to Community Power’s mission.

There were no public comments on Item No. 18.

After Board member comments, the acknowledgement of San Diego Community Power’s publicly issued “A” Issuer Credit Rating with a Stable Outlook from S&P Global Ratings was received and filed.
10 MEETING MINUTES – BOARD OF DIRECTORS – COMMUNITY POWER – MARCH 26, 2026

CHIEF EXECUTIVE OFFICER REPORT
Ms. Burns reported that Clean Prepay Transaction No. 3 was finalized and thanked all those involved.

DIRECTOR COMMENTS
Vice Chair Yamane thanked staff for volunteering in National City.

ADJOURNMENT
The meeting was adjourned at 6:25 p.m. to the next regular meeting scheduled for Thursday, April 23, 2026, at 5 p.m.
_____________________________
Maricela Hernandez, MMC, CPMC
Clerk of the Board
11 SAN DIEGO COMMUNITY POWER
Staff Report – Item 2
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: April 23, 2026
Recommendation
Receive and file updates 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 and Energy Storage Programs, and the San Diego Regional Energy Network.

Analysis and Discussion
Updates on customer energy programs are detailed below.

Commercial Programs
Efficient Refrigeration Pilot Project
Status & Next Steps: The Efficient Refrigeration Pilot Project, funded by the California Department of Food and Agriculture (CDFA), is now complete as the CDFA grant period ended on March 31, 2026. Staff will remove this Pilot Project from future Update on Programs staff reports.
12 Residential Programs
California Energy Commission (“CEC”) Equitable Building Decarbonization Direct Install (“EBD DI”) Program
Status: Staff continue to work with Los Angeles County (“LA County”) and the EBD coalition to prepare for the launch of the EBD DI Program. Recent updates from LA County indicate that the program is expected to launch by the end of Q1 2026. Due to the targeted nature of the program, staff does not anticipate a large launch announcement or press event.

Staff are in the final stages of contract negotiations with community-based organizations (“CBOs”) in our Power Network to implement and support marketing, outreach, and educational (“ME&O”) activities. Staff will be meeting with EBD staff to discuss available tools and resources to initiate outreach as soon as the program is open.

Next Steps: Staff will finalize agreements with CBOs to conduct ME&O activities to implement the program in the San Diego region.

Flexible Load Programs
Smart Home Flex Pilot Project
Status: The evaluation of the Smart Home Flex pilot project is ongoing. Learnings from the evaluation will inform program design of the potential expansion of Smart Home Flex.

The Universal Communication Modules (UCMs) shipped to program participants have been successfully installed on enrolled heat pump water heaters. The UCMs allow Community Power to communicate with the water heaters and pre-heat water ahead of peak periods to avoid electricity usage during those times. Feedback from customers has been positive with no major issues encountered during the installation process. Staff will continue to work to increase the number of water heaters enrolled over the next few quarters.

Next Steps: Staff will continue the impact evaluation of thermostats in Smart Home Flex, while working to increase water heater enrollments in collaboration with the TECH program.

EV Flex Connect Pilot Project
Status & Next Steps: Please refer to Item 2 of the March 2026 Board agenda packet for the most recent update on this program.

Solar and Energy Storage Programs
Net Energy Metering (“NEM”) and Net Billing Tariff (“NBT”) Status & Next Steps: Please refer to Item 13 of the September 2025 Board agenda packet for the most recent update on this program.
13 Solar Battery Savings (“SBS”) Program
Status: The SBS program began accepting applications on September 30, 2025. To date, the program has received over 738 applications, 467of which have been approved, 239 of which have been installed and activated. Of the 54 contractors approved to participate in the program, 45 have submitted applications. Sixty-nine percent of applicants are market rate customers. Sixty-nine percent of projects are for new solar and storage systems (as compared to storage being added to existing solar systems).

In February 2026, Community Power posted an invitation to support a bill impact analysis study for SBS participants. Community Power staff also held quarterly contractor training for newly interested contractors to participate.

In March 2026, staff participated in outreach events intended to target potential program participants, including events hosted by program-approved battery manufacturers and contractors. Program-approved battery manufacturers or contractors are encouraged to notify program staff of any upcoming outreach opportunities. Community Power will evaluate and participate in outreach events, pending available resources. Performance incentives for 2025 were processed for 1,416 pilot participants.

Next Steps: Community Power expects to start SBS customer workshops in Q2 2026.

Solar Advantage Program (previously DAC-GT)
Status: Developers awarded through the first Solar Advantage Program's Request for Offer ("RFO") have informed Community Power that Supervisory Control and Data Acquisition ("SCADA") costs are materially higher than anticipated given their experience with other utilities. Staff have informed the California Public Utilities Commission ("CPUC") Energy Division staff of the cost impacts on project viability and have been actively engaging with SDG&E to better understand the cost drivers underlying the elevated SCADA requirements and identify cost reduction solutions under the Wholesale Distribution Access Tariff ("WDAT").

Next Steps: Pending further project viability discussions, staff intend to bring Power Purchase Agreements ("PPAs") for shortlisted projects received through the Solar Advantage Program's Second RFO to the Board for approval within 180 days of notifying bidders of their shortlisting status, per CPUC requirements (due June 17, 2026). Staff will continue to engage with SDG&E to support solutions that reduce interconnection equipment costs under WDAT to improve the viability of DAC-GT and other distribution generation projects.

San Diego Regional Energy Network (“SDREN”)
Status: Staff continue procurement activities for the remaining SDREN contract from the phased solicitations for third party implementers. For programs with executed contracts, staff continue to focus on pre-launch deliverables to begin participant enrollment. Future program 14 launch updates will be published on the SDREN website at sdren.org, which went live on March 16, 2026.

As programs begin enrollment, the SDREN Advisory Committee will be key in providing advisement on program implementation activities (e.g., effective outreach and engagement strategies to connect with underserved and hard-to-reach communities across the region), serving as an advocate for SDREN (e.g., providing letters of support if/when necessary) and spreading awareness of program benefits through community and regional networks. The application period to join the SDREN Advisory Committee closed in February 2026, and staff have completed reviewing applications.

In compliance with the CPUC Rolling Portfolio process for reviewing and approving portfolio administrators’ programs, SDREN submitted its 2028-2035 Strategic Business Plan and 2028-2031 Portfolio Plan Application on March 16, 2026, following approved CPUC templates and guidance. SDREN Application Materials can be found at sdren.org/regulatory-documents.

Next Steps: Staff will continue to finalize contract negotiations with the selected vendor from the Phase 3 solicitation. All contracts from Phase 1 and 2 have been executed. Staff anticipate the remaining Phase 3 contract to be executed by April 2026 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.’
The remaining SDREN contract is expected to be executed with the selected vendor with amounts not exceeding the budgets stated in the solicitation:

Phase 3
• Market Access Program: $4,597,330 (direct implementation), $9,006,228 (incentives).

SDREN funds are authorized by the CPUC 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). Staff report program expenditures monthly to the CPUC and these amounts are publicly available on the California Energy Data and Reporting System (CEDARS) website at https://cedars.cpuc.ca.gov/.

Regarding the SDREN Advisory Committee formation and meetings, selected organizations were notified in March 2026, and regular meetings will commence in Q2 2026. 15 Fiscal Impact
N/A
Attachments
N/A
16 SAN DIEGO COMMUNITY POWER
Staff Report - Item 3
To: Board of Directors
From: Gordon Samuel, Chief Commercial Officer
Via: Karin Burns, Chief Executive Officer
Subject: Update on Power Services
Date: April 23, 2026
Recommendation
Receive and file update on Power Services.

Background
Staff is providing 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 sixteen people strong, and recently a candidate accepted an offer for the Compliance and Contract Management Analyst position.

Administrative Amendments
In February 2026, Community Power executed an amendment to update the resource adequacy guarantee date in the Enersmart Mesa Heights resource adequacy contract to December 2026. This better reflects the new project timeline and did not add any risk to the contract or Community Power’s positions.
17 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 and/or storage project. In addition, long-term PPAs lock in renewable energy supply around which Community Power can build its power supply portfolio while also hedging power supply costs. 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, staff have released several Requests for Offers (RFOs), including an RFO this year that targeted clean-firm resources that can provide 24/7 deliveries. 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 developers 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.

To date, staff have enabled the execution of over two dozen long-term contracts for energy, renewable energy credits and/or capacity from renewable and storage projects.

Going forward, staff expect to prioritize projects that increase the portfolio’s diversity in terms of technology and innovative contract structures to achieve a pathway to 100% clean energy.

Staff will also be increasingly prioritizing local infill projects as described below.

Local Development
Local RFI
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 over the past several months. 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. This solicitation has yielded nine Board-approved PPAs and energy storage agreements. Other ongoing local initiatives include 18 continued collaboration with member agency staff and other local agencies to identify strategic opportunities to further infill development.

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/ Solar Advantage Program (previously DAC-GT)
Status: Developers awarded through the first Solar Advantage Program's Request for Offer ("RFO") have informed Community Power that Supervisory Control and Data Acquisition ("SCADA") costs are materially higher than anticipated given their experience with other utilities. Staff have informed the California Public Utilities Commission ("CPUC") Energy Division staff of the cost impacts on project viability and have been actively engaging with SDG&E to better understand the cost drivers underlying the elevated SCADA requirements and identify cost reduction solutions under the Wholesale Distribution Access Tariff ("WDAT").

Short-Term RPS Procurement
Community Power staff continue to actively manage its environmental position and closely monitor the market for opportunities to optimize the renewable and carbon-free portfolios.

Community Power has been evaluating solicitation offers, bilateral offers, and products that meet the 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 resource availability in the broader Western Interconnection, lingering supply chain impacts and 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 uncertain. 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. 19 Near-term California energy market prices have been on a decline due to seasonal weather changes and increasing solar generation associated with spring in the West. Markets are watching weather changes closely as a record-hot March has initiated snowmelt weeks ahead of schedule and statewide snowpack is just 18% of average for April 1. With La Nina weather patterns impacting California, there is potential for a highly variable year as markets remain sensitive to extreme weather events and unexpected supply shortages. At the same time, the increasing penetration of utility-scale storage resources connected to the grid is influencing daily load patterns and pushing down peak prices. 2026 summer load and resource assessments are beginning, and results of the annual analysis will give insight into the state’s energy supply moving into summer and peak demand electric season.

Fiscal Impact
N/A
Attachments
N/A
20 SAN DIEGO COMMUNITY POWER
Staff Report – Item 4
_____________________________________________________________________ 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: April 23, 2026
_____________________________________________________________________ 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 March 23, 2026, Community Power is serving a cumulative total count of 968,681 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 two post-enrollment notices through the mail at their mailing address on file within 60 days of their account start date, notifying them that they have defaulted to Community Power electric generation service. 21 B) Customer Participation Tracking
The below charts summarize customer participation by member agency as well as metrics for their elections into San Diego Community Power’s four (4) available service options.

Please note that Re-Enrollment metrics are captured and displayed through February 28, 2026.
22 23
24 25
26 27
In September 2025, Community Power implemented an option for customers to identify their reason for re-enrollment at the time they submit their request to re-enroll. Following the Solar Battery Savings Program re-launch in Q3 2025, the majority of re-enrollments were attributed to customers joining a Community Power program. After Community Power’s rate adjustment in Q1 2026, the majority of customers have re-enrolled to receive lower rates. 28 C) Contact Center Metrics
As expected, calls to our Contact Center have decreased following the warm summer months that resulted in higher electric bills and have remained steady in the winter months.

The chart below summarizes contact made by customers into the Contact Center broken down by month. Contact Center Metrics are captured and displayed through February 28, 2026.

29 San Diego Community Power anticipates that 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 the majority 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 nine Dedicated Customer Service Representatives staffed at the Contact Center and one Supervisor. Robust Quality Assurance (QA) procedures are firmly in place to ensure that customers are getting world-class customer experience when they contact Community Power.

Fiscal Impact
N/A
Attachments
N/A
30 SAN DIEGO COMMUNITY POWER
Staff Report – Item 5
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: April 23, 2026
Recommendation
Receive and file an update on IT and Data Analytics.

Background
Community Power continues to invest in a robust in-house IT and data analytics team to support efficient, secure, and scalable operations across the organization. Recent efforts have focused on delivering high-impact technology initiatives that streamline business processes, modernize core operations, and enhance decision-making, all while emphasizing low-cost, sustainable solutions. Meanwhile, the teams have continued to strengthen Community Power’s cybersecurity defenses to safeguard critical systems and data and to bolster the organization’s long-term operational resilience.

Analysis and Discussion
Information Technology
IT Service Management (ITSM)
As of March 10, total resolved tickets stood at 1,039. As of today, resolved tickets have increased to 1,126—an additional 87 tickets have been resolved, representing an 8.4% increase. With only 29 open tickets out of 1,155 total, this reflects sustained operational focus, improved service responsiveness, and effective issue resolution across the organization.

31 Infrastructure Optimization
IT continues to lead optimization efforts across the Microsoft tenant, including Entra, SharePoint, and Intune, to strengthen identity governance, collaboration, and device management while aligning infrastructure capabilities to evolving organizational and security needs.

These technical initiatives are reinforced through cross‑functional collaboration with Human Resources, Public Affairs, and Finance, enabling improvements to onboarding processes, external infrastructure support, and infrastructure security. Together, these efforts ensure our environment is resilient, secure, and purpose‑built to support organizational operations.

Cybersecurity
The transition into Q2 2026 reflects significant progress in strengthening Community Power’s cybersecurity posture and modernizing foundational controls. Building on prior‑year findings, Cybersecurity used audit results to close critical gaps across Microsoft Defender, Intune, and the Varonis data security platform, reducing exposure to internal risk and data misuse. Lessons learned from ongoing incident response informed the establishment of standardized cybersecurity baselines and operating procedures, transitioning the organization from ad hoc practices to a defined in‑house program. Targeted vendor engagement further supported cost‑effective implementation and long‑term operational resilience.

Data Governance
The IT and Data teams distributed the collaborative document introduced during planning week to the organization. We continue to work together to complete and support ongoing data governance initiatives.

Data Analytics
Enterprise Data Platform (EDP)
Phase 2 EDP development has started, with the target of the first release at the end of May. This release will feature some automations to support Programs, integration with the Community Power CRM, and onboarding of Power Services data. The managed services support team has been successfully handling requests to keep the existing platform running smoothly while the development team focuses on new development.

Geospatial Data
The team continues work on developing a strategy to integrate various geospatial data into the Enterprise Data Platform and expand the organization's maps and reports. 32 Business Intelligence (BI)
In March, the team completed six data requests, including several complex requests and supported various ad hoc inquiries. Feature requests for several existing reports are in development, as well as completion of the initial design of two new reports targeted for May release.

Fiscal Impact
N/A
Attachments
N/A
33 SAN DIEGO COMMUNITY POWER
Staff Report – Item 6
To: Board of Directors
From: Chandra Pugh, Sr. Director of People Operations and Administration Via: Karin Burns, Chief Executive Officer
Subject: Update on Human Resources
Date: April 23, 2026
Recommendation
Receive and file the update on human resources.

Background
Staff provide regular updates to the Board of Directors regarding Community Power’s human resources initiatives.

During this reporting period, the People Operations and Administration function successfully completed several high impact initiatives supporting compensation governance, compliance, leadership performance evaluation, and workforce operations. Ongoing work remains focused on salary administration, Social Security remediation and filings, recruiting across multiple roles, systems integrations, and compliance-driven reporting. Coordination with Finance, Legal, and IT continues to be critical for several complex regulatory and system-dependent initiatives.

Several initiatives remain ongoing to support organizational operations and employee experience including announcement of employee promotions, our April wellness challenge, and our second NASH leadership training for all staff and all people leaders.

This month, we are pleased to share that Will Weisman has joined San Diego Community Power as our Associate Director of Finance – Capital Investment Plan (CIP).

In this role, Will will lead and manage Community Power’s CIP. Will brings deep public‑sector financial expertise from the City of San Diego, including extensive experience in financial reporting, capital and debt support, and governance within large municipal organizations, and 34 will play a key role in strengthening discipline, transparency, and execution across our capital and programs portfolio as Community Power continues to scale.

Current Open Positions:

Chief Financial Officer
Digital Support Specialist
HR Intern
Information Systems Manager
IT Systems Analyst
Procurement Analyst
Program Manager – Solar Battery Savings
Public Affairs Intern
Key Upcoming Dates:
- Wellness Challenge Underway
Fiscal Impact
N/A
Attachments
N/A
35 SAN DIEGO COMMUNITY POWER
Staff Report – Item 7
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: April 23, 2026
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
San Diego State University Business of Being Green Sustainability Panel Doing Business for Good Summit
La Mesa Home Energy Fair
Generation STEAM San Diego Festival of Science and Engineering San Diego 350 Youth4Climate Summit
Enphase Prospective Customer Event
36 Chula Vista Community Collaborative
National City Collaborative
National City Library
Kroc Senior Center Resource Fair
Spring Fling Business Expo
Cultivating Impact Mixer
Jackie Robinson YMCA Resource Fair
Center for Excellence in Aging & Longevity
Day of the Child
Intertribal Earth Day
Transportation Justice Expo
California Clean Energy Summit
San Ysidro STEM Fair
Lakeside Earth Day Celebration
La Mesa Earth Day Fair
South Bay Earth Day
Nature Day at El Toyon Elementary
Qualcomm Earth Day Fair
UC San Diego’s Earth Day Festival
City of San Diego Arbor Day
Dia de los Niños
Ramona Earth Day Festival
Marketing, Communications and Outreach
The Public Affairs team has been working on campaigns to help customers save money and electricity before heading into warmer months.

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 the Solar Battery Savings Program. It is also ramping up efforts to promote pilot programs, including flexible he 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.

Community Power has continued its efforts to connect with local leaders through meetings and 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. 37 Local Government Affairs
Community Power continues to meet with and work with local governments and tribal nations throughout the greater San Diego region. Leadership met with the City of Coronado in March to further discuss the process by which Coronado could become a new member agency of Community Power.

Fiscal Impact
N/A
Attachments
N/A
38 SAN DIEGO COMMUNITY POWER
Staff Report – Item 8
To: Board of Directors
From: Jeb Spengler, Senior Strategic Finance Manager/ Interim Treasurer Via: Karin Burns, Chief Executive Officer
Subject: Treasurer’s Report for Seven-Month Period Ending January 31, 2026 Date: April 23, 2026
Recommendation
Receive and File Treasurer’s Report for Seven-Month Period Ending January 31, 2026.

Background
San Diego Community Power (Community Power) prepares its accounting records on a full accrual basis under GAAP for governmental enterprise funds. Year-to-date financial statements for the seven-month period ending January 31, 2026, include budget comparisons.

The Board adopted an Investment Policy on May 25, 2023, with subsequent revisions on June 27, 2024, and August 28, 2025, to ensure the safeguarding of principal, preservation of liquidity, generation of returns, and adherence to a high standard of fiduciary care. The policy requires regular reporting to the Financial and Risk Management Committee (FRMC) via the Treasurer’s Report. As of January 31, 2026, the investment portfolio was compliant with the Community Power Investment Policy.

To enhance transparency, Community Power reports newly executed contracts between $50,000 and $150,000 in the Treasurer’s Report, per the Delegated Contract Authority Policy. Monthly operational metrics are presented at Board meetings, and key risk metrics are shared during FRMC meetings as part of the Treasurer’s Report. 39 On February 26, 2026, the Community Power Board of Directors (Board) approved the Amended Fiscal Year 2025-26 Operating Budget, which serves as the basis for comparison in this report.

Analysis and Discussion
Actual financial results for the period ending January 31, 2026: $839.4 million in net operating revenues were reported compared to $852.9 million budgeted for the period. Community Power’s change in net position of $191.0 million was reported year-to-date for Fiscal Year 2025-26. The following is a summary of the actual results through January 31, 2026, compared to the Fiscal Year 2025-26 Amended Budget:
• Operating revenues are $13.5 million, or 1.6% under budget primarily due to cooler temperatures driving lower energy sales.
• Cost of energy is $62.3 million, or 9.0% under budget, primarily due to lower energy costs resulting from lower load and Net CAISO costs.
• Professional Services and Consultants: $3.8 million below budget due to lower-than-expected utilization of outside professional services. • Personnel Costs: $1.5 million under budget, driven by vacancies and accrued vacation. • Non-Operating Revenues and Expenses:
• Total investment income of $10.1 million. Investment income is not currently budgeted and is reflected in financial statements as realized. • $1.12 million in year-to-date interest and related expenses versus $1.10 million budgeted, in line with expectations.

The chart below shows the Budgeted Net Position as compared to actual operating income through the first seven months of FY26:
40 Financial Reserves:

Under Resolution 2025-23, Community Power’s revised Financial Reserves Policy establishes a minimum reserve requirement of 180 days cash on hand and a reserve target of 225 days cash on hand. For Fiscal Year 2025-26, this target equates to approximately $623 million, based on projected operating expenses.

Community Power reserves at the end of the period totaled $636.3 million, or 228 days cash on hand, including $449.2 million in unrestricted cash and $187.1 million in investment holdings (current and non-current). Total available liquidity (including unrestricted cash, investment holdings, and available lines of credit) was $863.4 million.

Presented below are charts showing Community Power’s rolling 12-month financial reserves relative to Reserve Policy thresholds, along with the composition of reserves between unrestricted cash and investments.
41 Presented below are the Budget to Actual results for the seven months ended January 31, 2026. 42 Investment Portfolio Report
Chandler Asset Management manages Community Power’s investment portfolio.

As of January 31, 2026, the market value of the portfolio was $114.8M and in compliance with Community Power’s Investment Policy. The increase is a result of a $10.0M contribution from cash holdings and $808.6K in accrued interest. Presented below is a summary of the investment portfolio’s overall characteristics.

The chart below presents monthly and year-to-date investment income for the first seven months of FY26.
43 Contract Execution between $50,000 and $150,000
To ensure transparency and comply with Community Power’s Non-Energy Procurement Policy, the table below lists contracts or amendments with not-to-exceed values between $50,000 and $150,000 that were executed under the CEO’s authority for the month of March 2026.
• Agreement 2026-01 with Resilient Transition LLC: $120,000 Capital Investment Program Fund
The FY 2026-30 Capital Investment Plan contains all the individual capital projects, major equipment purchases, and major programs for the agency that are intended to span multiple years and that are considered one-time projects rather than recurring projects.

The first year of the FY 2026-30 CIP is Community Power’s capital budget shown in the Budgetary Comparison Schedule. Unspent funds are kept within the CIP and carried forward to the subsequent fiscal year. The CIP includes funding for local development feasibility studies, customer program pilot projects, member agency grants, community grants, a customer education platform, and other community-focused areas. 44 Customer Participation Rates
The participation rate for Community Power reflects full enrollment of current member agencies. We report opt-outs and eligible accounts for each phase based on the accounts that have been notified for enrollment on a rolling basis as of the reporting month.

Presented below are the customer participation rates by jurisdiction as of March 2, 2026. 45 Presented below is the state of Community Power arrearages. The below arrearage data includes Community Power’s receivables aged 120+ days as of March 2, 2026.

Presented below is a breakout of Community Power’s arrearages data by residential and commercial customer class as of March 2, 2026.

Fiscal Impact
N/A
Attachments
A: FY 2026 Year-to-Date Period Ended January 31, 2026, Financial Statements. 46 ITEM 8

ATTACHMENT A
47 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 January 31, 2026, and the related statement of revenues, expenses, and changes in net position, and the statement of cash flows for the seven 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
March 6, 2026
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com 48 Current assets
Cash and cash equivalents - unrestricted 449,245,629$
Cash and cash equivalents - restricted 33,257,761
Accounts receivable, net of allowance 107,221,463
Accrued revenue 46,174,003
Prepaid expenses 3,238,295
Other receivables 4,743,688
Deposits 8,503,563
Investments 82,630,495
Total current assets 735,014,897
Noncurrent assets
Cash and cash equivalents - restricted 13,159,830
Investments 104,505,684
Capital assets, net of depreciation and amortization 763,425 Total noncurrent assets 118,428,939
Total assets 853,443,836
Current liabilities
Accrued cost of electricity 109,318,426
Accounts payable 4,582,774
Other accrued liabilities 2,768,253
State surcharges payable 216,750
Deposits - energy suppliers 383,731
Lease liability 900,960
Advances from grantors 45,270,591
Total current liabilities 163,441,485
Noncurrent liabilities
Lease liability 65,835
Deposits - energy suppliers 3,867,810
Total noncurrent liabilities 3,933,645
Total liabilities 167,375,130
Restricted for security collateral 1,147,000
Unrestricted 684,921,706
Total net position 686,068,706$

NET POSITION

SAN DIEGO COMMUNITY POWER

STATEMENT OF NET POSITION
As of January 31, 2026
ASSETS

LIABILITIES
See accountants' compilation report. 2 49

OPERATING REVENUES
Electricity sales, net $ 836,975,962
Grant revenue 2,806,377
Liquidated damages revenue 2,348,023
Other income 44,283
Total operating revenues 842,174,645

OPERATING EXPENSES
Cost of electricity 610,024,868
Contract services 12,841,223
Staff compensation 11,773,353
Other operating expenses 7,114,971
Depreciation and amortization 554,117
Total operating expenses 642,308,532
Operating income 199,866,113

NON-OPERATING REVENUES (EXPENSES)
Investment income 10,120,219
Interest expense (149,790)
Nonoperating revenues (expenses), net 9,970,429
CHANGE IN NET POSITION 209,836,542
Net position at beginning of year 476,232,164
Net position at end of year 686,068,706$

SAN DIEGO COMMUNITY POWER

STATEMENT OF REVENUES, EXPENSES

AND CHANGES IN NET POSITION
Seven Months Ended January 31, 2026
See accountants' compilation report. 3 50

CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from customers 873,822,233$
Receipts from grantors 22,821,252
Receipts of supplier security deposits 21,855,240
Receipts from wholesale sales and other operating activities 7,292,280 Payments to suppliers for electricity (603,997,706)
Payments for other goods and services (19,431,706)
Payments for deposits and collateral (5,330,351)
Payments for staff compensation (11,815,595)
Payments of state surcharges (1,790,551)
Net cash provided by operating activities 283,425,096

CASH FLOWS FROM NONCAPITAL FINANCING ACTIVITIES
Proceeds from bank note 19,000,000
Principal payments - bank note (19,000,000)
Interest payments (89,170)
Net cash provided (used) by noncapital
financing activities (89,170)

CASH FLOWS FROM CAPITAL AND RELATED

FINANCING ACTIVITIES
Lease payments (545,874)
Net cash used by capital and related financing activities (545,874)

CASH FLOWS FROM INVESTING ACTIVITIES
Investment income received 9,313,976
Proceeds from investment sales and maturities of investments 4,474,580 Purchase of investments (120,089,634)
Net cash provided (used) by investing activities (106,301,078) Net change in cash and cash equivalents 176,488,974
Cash and cash equivalents at beginning of year 319,174,246 Cash and cash equivalents at end of year 495,663,220$
Reconciliation to the Statement of Net Position
Unrestricted cash and cash equivalents - current 449,245,629$ Restricted cash and cash equivalents - current 33,257,761 Restricted cash and cash equivalents - noncurrent 13,159,830 Cash and cash equivalents 495,663,220$

NONCASH INVESTING ACTIVITIES
Change in fair value of investments 458,485$
Change in interest income receivable 347,758$

SAN DIEGO COMMUNITY POWER

STATEMENT OF CASH FLOWS
Seven Months Ended January 31, 2026
See accountants' compilation report. 4
51 Operating income 199,866,113$
Adjustments to reconcile operating income to net
cash provided by operating activities
Depreciation and amortization expense 554,117
(Increase) decrease in:

Accounts receivable, net 8,805,760
Accrued revenue 26,568,356
Prepaid expenses 20,563,840
Other receivables (295,939)
Deposits 2,590,648
Increase (decrease) in:

Accrued cost of electricity 7,116,260
Accounts payable 771,802
Advances from grantors 20,014,877
Other accrued liabilities 608,298
State surcharges payable (318,396)
Deposits - energy suppliers (3,420,640)
Net cash provided by operating activities 283,425,096$

SAN DIEGO COMMUNITY POWER
STATEMENT OF CASH FLOWS (continued)
Seven Months Ended January 31, 2026

RECONCILIATION OF OPERATING INCOME TO NET

CASH PROVIDED BY OPERATING ACTIVITIES
See accountants' compilation report. 5 52
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 seven months ended January 31, 2026 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
March 6, 2026
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com 53 Budget Actual
Budget Variance
(Under) Over
Actual/
Budget % Budget
Budget
Remaining

REVENUES AND OTHER SOURCES
Gross Ratepayer Revenues 868,085,000 849,721,789$ (18,363,211) 98% 1,220,987,000 371,265,211$ Less: Uncollectible Customer Accounts (15,191,000) (12,745,827) 2,445,173 84% (21,367,000) (8,621,173) Other Income - 2,392,306 2,392,306 na - (2,392,306)
Total Revenues and Other Sources 852,894,000 839,368,268 (13,525,732) 1,199,620,000 360,251,732

OPERATING EXPENSES
Cost of Energy 672,312,000 610,024,868 (62,287,132) 91% 956,691,000 346,666,132 Professional Services and Consultants 14,416,000 10,567,142 (3,848,858) 73% 24,713,000 14,145,858 Personnel Costs 12,372,000 10,825,592 (1,546,408) 88% 21,209,000 10,383,408 Marketing and Outreach 1,437,000 1,475,665 38,665 103% 2,464,000 988,335 General & Administrative 3,422,000 2,293,866 (1,128,134) 67% 5,867,000 3,573,134 Total Operating Expenses 703,959,000 635,187,132 (68,771,868) 1,010,944,000 375,756,868 Operating Income (Loss) 148,935,000 204,181,136 55,246,136 188,676,000 (15,505,136)

NON-OPERATING REVENUES (EXPENSES)
Investment Income - 10,120,219 10,120,219 na - (10,120,219) Interest and Related Expenses (1,104,000) (1,127,577) (23,577) 102% (1,893,000) (765,423) Transfer to Capital Investment Program (22,170,000) (22,170,000) - 100% (22,170,000) - Total Non-Operating Revenues (Expenses) (23,274,000) (13,177,358) 10,096,642 (24,063,000) (10,885,642) NET CHANGE 125,661,000$ 191,003,778$ 65,342,778$ 164,613,000$ (26,390,778)$

SAN DIEGO COMMUNITY POWER

BUDGETARY COMPARISON SCHEDULE
Seven Months Ended January 31, 2026

OPERATING FUND
Year-to-Date Annual
See accountants' compilation report. 54

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
Xiomalys Crespo, Senior Community Engagement Manager
Via: Karin Burns, Chief Executive Officer
Subject: Community Advisory Committee Monthly Update
Date: April 23, 2026
Recommendation
Receive and file the Community Advisory Committee (CAC) monthly update.

Background
Per Section 5.10.3 of the San Diego Community Power (Community Power) Joint Powers Authority Agreement:

At the direction of the Board Chair, the CAC provides quarterly reports to the Board of Directors on the regular agenda and monthly updates on the consent agenda. The next quarterly report is expected to be provided at the Board meeting on June 25, 2026.

Analysis and Discussion
During the April 9, 2026, regular CAC meeting, Vice-Chair Montero-Adams (City of San Diego) welcomed new Community Power staff and led the approval of the consent agenda, which included updates on Customer Operations, Marketing, Public Relations, Power Services, Programs, and Regulatory and Legislative Affairs. Member Emerson (National City) pulled the 55 Programs Update out of the consent agenda to ask staff about the implementation timeline and strategy of the Solar Battery Savings workshops.

The CAC heard from the Finance Department team on several updates, which included Community Power’s Prepay Bond transaction No. 3, its public credit rating, its financial reserves, the Rate Stabilization Reserve Policy, and the FY 2026-27 budget process. Members were supportive of the conservative approach but expressed interest in being able to discuss items such as the Rate Stabilization Reserves Policy prior to the item being heard and approved by the Board. Members also had questions on the timing of rate-setting vis-a-vis budget development, which includes staff recommendations regarding reserves, and Community Power’s policy considerations on setting 225 days as its reserves goal.

Members also had an opportunity to provide feedback on the Local Development Strategy draft. Members encouraged staff to engage with member agencies to identify eligible sites and commended staff for prioritizing community engagement as part of the strategy, which has historically proven successful in moving them forward across regulatory bodies and community groups.

No items were recommended for the Board of Directors. Members shared announcements on upcoming community events as part of grant-funded work and Member Vasilakis (City of San Diego) announced this was his last meeting as a member, as the CAC will be taking a meeting recess in May and he will not be attending the June meeting. As of April 23, 2026, the CAC has two vacancies representing the City of Imperial Beach and the City of Encinitas, with the latter expected to be filled during the April 23, 2026, regular Board meeting.

Fiscal Impact
N/A
Attachment
N/A
56 SAN DIEGO COMMUNITY POWER
Staff Report – Item 10
To: Board of Directors
From: Jack Clark, Chief Operating Officer
Patrick Welch, Associate Director of Legislative Affairs Via: Karin Burns, Chief Executive Officer
Subject: Update on Regulatory and Legislative Affairs
Date: April 23, 2026
Recommendation
Receive and file the update on regulatory and legislative affairs.

Background
Staff provide regular updates to the Board of Directors regarding Community Power’s regulatory and legislative engagement.

Analysis and Discussion
A) Regulatory Updates
Resource Adequacy (RA)
Track 1 Proposals
On March 20, 2026, parties filed reply comments on proposals filed in Track 1 of the California Public Utilities Commission's (CPUC) Resource Adequacy (RA) proceeding (R.25-10-003), which is focused on highest-priority refinements to the RA program. Proposals were filed on January 23, 2026, and workshops were held to review proposals on February 10 and 11.

Community Power's trade association, the California Community Choice Association (CalCCA), made several recommendations in its reply comments, including but not limited to:
addressing the significant forthcoming impacts of data center loads on RA requirements and 57 adopting CalCCA’s proposal for energy only resources. A Proposed Decision on Track 1 is expected in May 2026.

Slice-of- Day Transactability
On March 18, 2026, six parties filed opening comments on CPUC Energy Division’s Report on Slice-of-Day Transactability as well as the proposals filed by CalCCA and the Western Power Trading Forum (WPTF) filed on March 3.
• CalCCA's opening comments reiterated support for its hourly load obligation trading proposal and provided additional clarifications and guardrails, which was supported by Ava Community Power's opening comments.
• The California Environmental Justice Alliance/Sierra Club asked the commission to study the environmental impacts of the slice-of-day framework and trading (i.e., how it impacts gas usage).
• Vistra and Middle River Power agreed with CPUC Energy Division that trading is unnecessary and CalCCA’s proposal should be rejected.
• Forward Market Design (FMD) is a research and consulting group that supported transactability through an intermediary.

Reply comments were filed on March 30, 2026. Notably, all three investor-owned utilities (IOUs) filed reply comments agreeing with the Energy Division report that hourly load transactability is unnecessary and that CalCCA’s proposal should be rejected. As noted above, a Proposed Decision on Track 1 is expected in May 2026.

Power Charge Indifference Adjustment (PCIA)
Track 2: Energy Division Staff Report
On March 27, 2026, CPUC Energy Division released a staff report in Track 2 of the Rulemaking to Update and Reform Energy Resource Recovery Account (ERRA) and Power Charge Indifference Adjustment (PCIA) Policies and Processes (R.25-02-005). Track 2 addresses the valuation of banked pre-2019 renewable energy credits (RECs) and how that valuation is applied to investor-owned utility (IOU) bundled customers and departed load customers, like those of community choice aggregators (CCAs), such as Community Power.

The report agreed with CalCCA’s assertion that banked pre-2019 RECs should be assigned a value above zero, however it noted that there was more nuance than valuing the RECs at the current market price benchmark due to several issues raised by the IOUs. As such, the report outlines four compromise options for valuation. Opening comments on the staff report and proposals are due concurrently with the filing of opening briefs on May 22, 2026, and reply comments are due on June 5, 2026.
58 Track 3: Opening Comments on Scoping Issues
On March 27, 2026, parties filed opening comments in response to a CPUC Ruling authorizing parties to comment on what issues should be included in Track 3 of the ERRA and PCIA Rulemaking (R.25-02-005). CalCCA’s opening comments included the following recommendations:
• Adopt a broad scope for Track 3, including all scoping items originally identified in the Order Instituting Rulemaking, as well as additional items to allow a thorough review that addresses PCIA and ERRA structural, methodological, and implementation issues; • Establish a Phase 1 of Track 3, to first resolve data access and confidentiality issues prior to commencing a Phase 2 focused on substantive party proposals; • Adopt a data access protocol consistent with the protocol established in R.17-06-026, requiring the scope and term of data set forth in CalCCA’s Data Matrix; and • Provide a minimum of six months following data production for analysis and proposal development by all parties in Track 3, Phase 2.

Opening comments were also filed by the Joint IOUs, The Utility Reform Network (TURN), the California Large Energy Consumers Association (CLECA), and the Direct Access Customer Coalition and the Alliance for Retail Energy Markets (AReM/DACC). Reply Comments are due April 10, 2026.

California Energy Commission Integrated Energy Policy Report On March 10, 2026, the California Energy Commission (CEC) filed a notice of request for comments on the Draft Scoping Order for the 2026 Integrated Energy Policy Report (IEPR) Update, which is the biennially report that broadly assesses California’s energy system and puts forward recommendations to advance California’s clean energy future for all. The proposed scope includes the following:
• California Electricity Demand Forecast: an updated 15-year electricity demand forecast.
• California Geothermal Resources: an assessment of the challenges and opportunities for geothermal development in California.
• Energy Equity and Environmental Justice: CEC progress toward its commitment to embed equity and environmental justice in its policies, programs, and activities, as described in recommendations included in the 2022 IEPR Update and draft Justice, Access, Equity, Diversity, and Inclusion (JAEDI) framework.

CalCCA filed comments recommending ways the CEC should improve the load forecast process given uncertainty around data center growth, among other recommendations.

Community Power also signed onto comments led by solar and storage industry stakeholders regarding the treatment of distributed front-of-the-meter projects, like community solar, in the load forecasting process. A final scoping order will be released in April 2026. 59 Protest of SDG&E Advice Letter 4791-E
On March 23, 2026, Community Power and Clean Energy Alliance (CEA) jointly protested SDG&E's Advice Letter 4791-E (see Attachment A). The Advice Letter seeks CPUC approval to implement several changes to rates, tariffs, and rate design adopted in its General Rate Case (GRC) Phase 2 proceeding, as well as recovery of certain wildfire mitigation plan memorandum account costs addressed in Track 2 of its 2024 GRC Phase 1.

Community Power and CEA do not oppose the establishment of a new Medium Commercial customer class as approved in Decision 25-09-006 but contest that SDG&E’s proposed Power Charge Indifference Adjustment (PCIA) rates reflecting this change contain material error by failing to appropriately adjust sales volumes between customer classes. The Protest asks the CPUC to instruct SDG&E to file an amended Advice Letter containing corrected PCIA rates that reflect the sales expected to move into the Medium Commercial class and make clear that there will be a timeline of at least one month between that filing and the effective date of the rate changes proposed therein.

Protest of SDG&E Advice Letter 4817-E
On April 6, 2026, Community Power and Clean Energy Alliance (CEA) jointly protested SDG&E's Advice Letter 4817-E (see Attachment B). The Advice Letter seeks Commission approval of SDG&E’s plans to present the Power Charge Indifference Adjustment (PCIA) rate as a separate line item on bundled customer bills and in its Electric Energy Commodity Cost (EECC) tariffs, which was directed by a previous CPUC decision as a result of Community Power advocacy.

Community Power and CEA oppose the open-ended delay proposed by SDG&E and request that Energy Division reject AL 4817-E and direct SDG&E to submit an amended advice letter that: 1) seeks to implement the bundled PCIA line item by August 1, 2026, and in no event later than December 31, 2026, and 2) describes the specific elements SDG&E will display as part of the PCIA line item on bundled customer bills. The Protest further requests that the CPUC consider evaluating changes to the bundled PCIA rate calculation in SDG&E’s upcoming 2027 ERRA Forecast proceeding.

Rulemaking to Improve California Climate Credit
On March 17, 2026, the CPUC adopted the Decision temporarily pausing the distribution of the 2026 Climate Credit by SDG&E, PG&E, and SCE so the CPUC can determine when later in 60 2026 it should be applied to maximize affordability. The utilities must file implementation advice letters within 15 days to update customer-facing messaging to clarify that customers will receive the credit later in 2026 and that the change is intended to reduce bills when they are the highest.

Rulemaking to Update Distribution Level Interconnection Rules and Regulations On March 3, 2026, the CPUC issued a Scoping Memo and Ruling establishing that the issues in the Rulemaking to Update Distribution Level Interconnection Rules (Rule 21) and Regulations.

The proceedings will be addressed in multiple phases and the Scoping Memo outlined the issues to be addressed in Phase 1. It also sets forth various questions for parties to address in Appendix A related to Phase 1, which broadly concern (1) Modifications to Screens Q and R, (2) Interconnection Timelines Established for IOUs, and (3) Interconnection Fees for Non-Net Energy Metering (NEM) Resources. Opening comments on these questions are due April 30 and reply comments are due May 29. The CPUC Energy Division will also hold workshops, as needed, to discuss priority of the remaining issues.

Order Instituting Rulemaking to Establish Energization Timelines On March 19, 2026, the CPUC issued an Assigned Commissioner Ruling amending the scope of Phase 2 of the proceeding to refine the Commission’s approach to meeting and enforcing energization targets established by legislation. It adds new scoped issues focused on (1) how the Commission will determine and enforce remedial actions for utilities that miss energization targets, including whether and how to use the existing Enforcement Policy, (2) whether to take steps to implement new legislative reporting requirements, and (3) improvement to the energization process. Comments on the Ruling are due April 16 and reply comments are due April 30.

Application of San Diego Community Power for Approval of the San Diego Regional Energy Network 2028-2031 Portfolio Plan and 2028-2035 Business Plan (Application 26-03-19) On March 16, 2026, all Energy Efficiency Portfolio Administrators – including San Diego Community Power on behalf of the San Diego Regional Energy Network (SDREN) – filed their Business Plan Portfolio Applications (BPAs) with the CPUC. The Application consists of two parts: the 4-year Portfolio Plan and 8-year Business Plan. The Portfolio Plan is a more granular document detailing programs and budgets, whereas the Business Plan serves as a long-term strategic plan. SDREN’s BPA can be found here: https://sdcommunitypower.org/sdren/.

The CPUC is expected to consolidate all BPAs into a single proceeding, whereby interested parties can weigh-in on proposed programs, budgets, and broader policy recommendations. 61 Of elevated importance will be party comments on the 4-Year Portfolio Plan programs and budgets; party comments will help the CPUC determine whether any reductions to 2028- 2031 programs and associated budgets are warranted.

In the meantime, parties may file responses (termed “protest” if the response seeks to deny relief requested by any Portfolio Administrator) to the BPAs on May 1. Replies to responses will be due May 18. Community Power, on behalf of SDREN, anticipates filing a response on May 1 detailing which policy issues should be addressed in the consolidated proceeding. If parties file protests to the SDREN BPA, Community Power accordingly plans on filing a response on May 18.

Order Instituting Rulemaking on California Advanced Electric Rate Design The CPUC has issued a draft rulemaking to comprehensively modernize residential and non-residential electric rate design so that rates more accurately reflect cost causation, send efficient price signals, address affordability concerns, and support reliability, electrification, and environmental justice. The proceeding builds on and aims to close gaps from the Demand Flexibility Rulemaking (R.22-07-005) and responds to new statutory directives related to data centers (Senate Bill 57) and industrial electrification/process heat recovery (Assembly Bill 2109). The draft rulemaking is likely to be on the May 9 CPUC meeting agenda, and comments will be due 30 days after the final issuance.

Order Instituting Rulemaking to Modernize the Electric Grid for a High Distributed Energy Resource (DER) Future
The CPUC issued a ruling setting the scope for Phase 2 of the High DER Rulemaking to develop a DER orchestration framework for the investor-owned utility (IOU) Distribution System Operators (DSOs). The ruling presents an approach for moving forward with the development of a framework for DER orchestration for IOU DSOs. The ruling proposes a number of CPUC-led workshops to refine the proposed application process, including discussion of guiding principles, technical requirements, and other foundational elements necessary for DER orchestration. The ruling proposes that SDG&E, SCE, and PG&E file applications for the development of an IOU DSO-led DER orchestration framework for each respective IOU. The ruling proposes a hybrid procedural approach that begins with two CPUC-led workshops to build early alignment on key technical, conceptual and market issues, followed by formal applications from the IOUs to develop and operationalize the full DER orchestration framework. Comments on the ruling are due April 20 and reply comments are due April 30.

The CPUC will hold a workshop on May 21 to discuss proposed application process, including discussion of guiding principles, technical requirements, and other foundational elements necessary for DER orchestration.
62 B) State Legislative Activities Update
CalCCA Sponsored Legislation on the Power Charge Indifference Adjustment (PCIA) AB 1761 Approved by Assembly Committee on Utilities & Energy
On March 18 the Committee voted 15-3 to approve AB 1761 (Rogers) and sent it to be considered by the Assembly Committee on Appropriations. The bill, which is supported by Community Power, would bring improved transparency to the way the PCIA is calculated.

Greater transparency allows CCAs to better forecast costs and shield customers from sudden rate swings. It reduces repeated fights over information, improves regulatory efficiency, and encourages utilities to verify calculations since the underlying data would be open to review.

At the hearing, Community Power’s Sacramento representative testified in support of the bill.

SDG&E’s Regional Vice President testified in opposition, arguing the bill would lead to the disclosure of market sensitive data. However, the author of AB 1761 (Rogers) accepted amendments to the bill to create tighter guardrails around the data, which the SDG&E representative said will go a long way in addressing their opposition. Additionally, Assembly Members Chris Ward and Tasha Boerner were added as coauthors of the legislation.

CalCCA Sponsored Legislation on Ratepayer Savings for Resource Adequacy (RA) Approved by Senate Committee on Energy, Utilities & Communications On April 7 the Committee voted 13-0 to approve SB 1138 (Padilla). The bill, which is supported by Community Power, makes an important affordability improvement to the CPUC’s RA program, which ensures load-serving entities (LSEs) like Community Power have enough capacity under contract to meet peak system and local needs. The CPUC recently changed the RA paradigm from being based on monthly compliance to hourly compliance. The program is now known as slice of day (SOD). It requires hourly compliance, but it does not permit hourly trading, representing a misalignment with commercial realities since commercial RA transactions are based on blocks of time, often 24 hour or monthly blocks.

Therefore, under SOD, if Community Power is short in a particular hour on our obligation, we have to purchase an entire commercial block, overpaying for capacity that is not needed. This adds unnecessary costs to ratepayers.

SB 1138 (Padilla) fixes this and would allow LSEs to trade hourly SOD obligations. This means that Community Power would be able to trade with another LSE for the one hour we were hypothetically short on. An analysis by CalCCA found that savings from hourly trading could have reached $179 million statewide in 2025. Estimated savings for Community Power in 2025 could have been as much as $10.8 million. The bill will next be heard by the Senate Committee on Appropriations.
63 Community Power Joins Group Opposing Legislation to Eliminate Public Purpose Program Charges
The coalition of 12 groups opposes AB 1208 (Hoover), which would eliminate the requirement to collect the public purpose program (PPP) charge from ratepayers and instead shift those costs to the state’s Greenhouse Gas Reduction Fund (GGRF), which consists of revenues from the auction of carbon allowances in the state’s Cap-and-Invest program. While well intentioned, AB 1208 (Hoover) effectively eliminates funding for the San Diego Regional Energy Network (SDREN), which has a four-year budget approved by the CPUC from PPP revenues.

The GGRF cannot sustain valuable programs like those offered through SDREN. GGRF revenues are hard to predict, and their use may also require revisiting the spending priorities established by the Legislature in SB 840 (Chapter 121, Statutes of 2025). GGRF discretionary revenues are allocated in tiers of priority, including towards replacing the State Responsibility Area fire prevention fee, high speed rail, public transit passes, a University of California Climate Research Center, community air protection, and several other programs that do not pertain to program efforts currently supported by the PPP.

Given the key role that energy efficiency programs play in the state’s energy management strategy and the benefits they provide to affordability and grid stability, the state must ensure that these programs remain viable. Shifting the funding source of the state’s energy efficiency and demand management programs to the volatile GGRF will threaten both the affordability benefits and system reliability benefits that are provided by these programs. The coalition letter is included as an attachment (Attachment E). Despite the opposition, the Assembly Committee on Utilities & Energy approved the bill on April 8, sending it to the Assembly Committee on Appropriations for consideration.

Community Power Supports Legislation on Portable Solar Devices at Committee Hearing Community Power voiced its support of SB 868 (Wiener) at a hearing of the Senate Committee on Energy, Utilities, and Communications on March 17. The bill would help accelerate deep decarbonization, promote local development, and strengthen community resilience—while keeping affordability and equity at the center of the clean energy transition by reducing barriers to portable solar, which may prove to be a useful technology in San Diego, where a significant share of households are renters and face structural barriers to participating in rooftop solar programs. The Committee approved the legislation 14-3. It will next be heard by the Senate Committee on Appropriations.
64 Community Power Files Four Additional Support Letters for Legislation on Natural Gas Alternatives, Transmission Planning, and the Cost of Rooftop Solar Since the last Board meeting, Community Power has adopted support positions on four additional pieces of state legislation. The four letters are attached to this report (Attachments C, D, F and G). All of Community Power’s bill positions and associated position letters can be found on our Legislative Priorities webpage: https://sdcommunitypower.org/legislative-priorities/.

Community Power is now supporting AB 2313 (Berman), which would fill a gap in the current SB 1221 (Chapter 602, Statutes of 2024) implementation process underway at the CPUC. SB 1221, a forward-looking law focused on transitioning away from household use of natural gas, allows a gas corporation to cease providing natural gas service in an area if the CPUC determines that adequate substitute energy service is available. The CPUC hasn’t determined how to fund the gas alternatives – such as replacement of gas appliances with electric ones – in selected priority neighborhood decarbonization pilot zones. AB 2313 (Berman) fills this gap by creating a Gas Distribution Service Line Replacement Alternatives Program to offer monetary incentives to adopt alternatives that do not require connection to the gas system, such as switching to electric appliances. Funding would come from costs approved for gas line replacement, with cost recovery over ten years. The legislation provides a prudent safeguard measure in the event the CPUC takes a long time to determine how to fund alternatives in pilot neighborhood decarbonization zones that will be converted from gas to electric service.

It aligns with Community Power’s mission and support for policies that enable building electrification, equity, and acceleration of deep decarbonization.

AB 2493 (Petrie-Norris) would help ensure timely project delivery, guard against unnecessary ratepayer costs and will help optimize California’s resource market by ensuring there is sufficient transmission capacity in a timely manner. The bill would empower the CPUC to order remedial actions for priority transmission projects. This is important because transmission capacity is essential to meet both our Board established 100% renewable goal and the state’s standards.

Community Power’s market experience suggests that completion of transmission network upgrades – projects that generally increase the capacity of existing transmission facilities – are a significant barrier to both the deliverability of projects and timely commercial operation of generating and energy storage projects. Likewise, the timely completion of new transmission facilities approved in the California Independent System Operator (CAISO) transmission planning process (TPP) is also vital to accessing new, diverse generating and energy storage projects. The most recent statistics from the CPUC’s Public Advocates Office Transmission Data Dashboard demonstrate the problem: fifty-nine percent of transmission projects approved since 2012 are still being built; nearly half of all transmission projects approved in 65 the TPP since 2000 have seen delays beyond their original in service date; and the average delay is just over two years, with the longest delay reaching 15 years.

Also on transmission, Community Power is supporting AB 2369 (Rogers). Sponsored by Sonoma Clean Power, this bill would solve a problem related to energy only charging resources. As a result of CPUC market design, paired solar and storage projects can receive full transmission deliverability – an important CAISO determination for a project to count towards RA obligations – but the solar generation component gets an energy-only designation and will not be counted as capacity for charging storage resources. This is because the combined capacity on paper of a solar array plus battery storage is often twice the capacity of the point of interconnection where deliverability is capped. As a result, while physically Community Power’s contracted projects are charging the batteries with paired solar as designed and being grid dispatched at or up to the capacity limit of the point of interconnection, Community Power must go out to the market to purchase additional generation with full deliverability to satisfy the CPUC’s charging sufficiency requirements in the RA program. This problematic market design adds unnecessary costs to Community Power’s customers. The bill will require the CPUC’s RA program to recognize the reliability contribution of energy-only resources.

Doing so will allow more resources to connect to the grid at scale and provide reliability benefits.

AB 2389 (Irwin) would extend a current property tax exclusion for solar and solar + storage systems of any size for public agencies and up to 2 MW for other customers. Absent the bill, the exclusion on property tax would expire in 2027. AB 2389 (Irwin) will support Community Power’s continued work with our customers and member public agencies to meet both programmatic and distributed wholesale procurement goals. Community Power has committed to building 1 gigawatt (GW) of locally sited distributed energy resources, 150 MW of which will come from customer program efforts, such as our Flexible Load Strategy, which relies on – in part – customer sited solar and storage systems. Another 150 MW will come from wholesale procurement of local solar and storage distributed projects. AB 2389 (Irwin) is important legislation that will boost the economic viability of the prospective projects, especially considering H.R. 1’s elimination of the federal Residential Clean Energy Tax Credit and the phase out of the investment and production tax credits for solar resources.

C) Federal Activities Update
Community Power Joins Other CCAs to Oppose Federal Legislation That Would Roll Back Energy Efficiency Standards
The letter, which is included as Attachment H, addressed to U.S. Senators Alex Padilla and Adam Schiff, opposes H.R. 4626 (the Home Appliance Protection and Affordability Act) and H.R. 4758 (the Homeowner Energy Freedom Act). Both bills were recently approved by the U.S. House of Representatives.
66 H.R. 4626 would give the Department of Energy (DOE) new authority to weaken or revoke existing appliance efficiency standards and create significant roadblocks to future updates, including through imposing arbitrary payback and energy savings thresholds that would block cost-effective standards. Crucially, it would also prohibit states from setting their own standards if a federal standard is eliminated, making it more difficult for California to fill the void.

H.R. 4758 would repeal rebates and training programs that help consumers adopt cost-saving technologies and help contractors deliver those savings. The bill specifically targets the High-Efficiency Electric Home Rebate (HEEHRA) Program and State-Based Home Energy Efficiency Contractor Training Grants, which provided income-qualified California households with a total of $290 million to replace outdated gas-fired appliances with new, all-electric heat pump water heater and HVAC systems, and another $10.3 million to support residential energy contractor training. These are critical programs that support California families, including many CCA customers, by lowering upfront costs for energy-saving upgrades and reducing their monthly bills.

Local Member of Congress Introduces new Energy Bills Relief Act The legislation, announced on March 18, is co-sponsored by 120 members of the House of Representatives and is being promoted by the House Sustainable Energy and Environment Coalition. Congress Member Mike Levin is Vice Chair of the Coalition and one of the lead legislative authors. The 419-page Energy Bills Relief Act contains the provisions from numerous bills previously introduced by various members of Congress. At a high level, the bill would restore clean energy tax credits that were repealed or reduced by H.R. 1, which was signed into law on July 1, 2025. Among many other things, it would also boost funding for low-income programs, reform project permitting, and make various changes to laws that govern the development of the electric grid. A schedule has not been announced to have the bill heard and voted on in a committee.

Senators Launch Inquiry into Data Center Development Plans One of the most prominent energy-related policy discussions right now is on the development of data centers being built to support the deployment of artificial intelligence.

The sudden construction of large data centers raises numerous policy questions, such as how to manage the sudden load growth without impacting other customers, how to power the new load, and how to timely interconnect data centers to the grid.

On March 13, U.S. Senators Sheldon Whitehouse (D-RI), Martin Heinrich (D-NM), and Chris Van Hollen (D-MD) opened an investigation into nine companies planning data center 67 projects that will be powered by new natural gas plants. The Senators, highlighting concerns regarding the health and environmental impacts of these new natural gas plants, sent letters to Meta, OpenAI, xAI, Fermi America, American Intelligence & Power Corporation, Joule, Crusoe, Fundamental Data, and Pacifico Energy requesting information about how they chose their power generation sources and what emissions analysis was performed prior to that decision, which emphasizes congressional concerns over the environmental impacts of data center development. The projects led by the companies appear to be in states other than California. Several of these companies have signed onto the President’s “Ratepayer Protection Pledge” – announced on March 4 – in which the companies promised to "build, bring, or buy” new generation to support their power needs. The companies have until March 27 to respond to the Senators’ inquiries.

Fiscal Impact
N/A
Attachments
A: Protest of San Diego Community Power and Clean Energy Alliance to SDG&E Advice Letter 4791-E
B: Protest of San Diego Community Power and Clean Energy Alliance to SDG&E Advice Letter 4817-E
C: AB 2313 (Berman) Support Letter
D: AB 2493 (Petrie-Norris) Support Letter
E: AB 2508 (Hoover) Coalition Oppose Letter
F: AB 2389 (Irwin) Support Letter
G: AB 2369 (Rogers) Support Letter
H: Joint CCA Letter Opposing H.R. 4626 and H.R. 4758
68 ITEM 10

ATTACHMENT A
69 SDCP and CEA Protest of SDG&E AL 4791-E 1
March 23, 2026
Via E-Mail ([email protected])
Energy Division, Tariff Unit
California Public Utilities Commission
505 Van Ness Avenue, 4th Floor
San Francisco, California 94102
Subject: Protest of San Diego Community Power and Clean Energy Alliance to San Diego Gas & Electric Company Advice Letter 4791-E
Dear Energy Division Tariff Unit:

San Diego Community Power (“SDCP”)1 and Clean Energy Alliance (“CEA”)2 (together, the “SD CCAs”) hereby protest San Diego Gas & Electric Company (“SDG&E”) Advice Letter (“AL”) 4791-E, Implementation of 2024 General Rate Case Phase 2 and Track 2 Wildfire Mitigation Costs for Electric Rates Effective April 1, 2026. Through AL 4791-E, SDG&E seeks Commission approval to implement several changes to rates, tariffs, and rate design adopted in its General Rate Case (“GRC”) Phase 2 proceeding, as well as recovery of certain wildfire mitigation plan memorandum account costs addressed in Track 2 of its 2024 GRC Phase 1.3 While the SD CCAs do not oppose the establishment of a new Medium Commercial customer class as approved in Decision (“D.”) 25-09-006,4 SDG&E’s proposed Power Charge Indifference Adjustment (“PCIA”) rates reflecting this change contain material error. Specifically, in calculating updated PCIA rates, SDG&E failed to appropriately adjust sales volumes between 1 SDCP is the Community Choice Aggregator (“CCA”) for the cities of Chula Vista, Encinitas, Imperial Beach, La Mesa, National City, and San Diego, as well as the unincorporated areas of San Diego County.
2 CEA is the CCA for the cities of Carlsbad, Del Mar, Solana Beach, Escondido, San Marcos, Oceanside, and Vista.
3 San Diego Gas & Electric Company (“SDG&E”) Advice Letter (“AL”) 4791-E: Implementation of 2024 General Rate Case Phase 2 and Track 2 Wildfire Mitigation Costs for Electric Rates Effective April 1, 2026 (March 2, 2026).
4 Decision (“D.”) 25-09-006, Attachment B, Section 3.2.4.1 (Sept. 22, 2025). 70 SDCP and CEA Protest of SDG&E AL 4791-E 2
customer classes, despite adjusting revenues to reflect this new class structure. This inconsistency results in distorted PCIA rates, understating rates for the Small Commercial class and overstating rates for the Medium and Large Commercial classes.

Accordingly, the SD CCAs protest this Advice Letter pursuant to General Order (“GO”) 96-B, Section 7.4.2(3). The SD CCAs respectfully request that Energy Division reject AL 4791-E and direct SDG&E to submit an amended Advice Letter proposing corrected PCIA rates that properly reflect the sales expected to move into the Medium Commercial class. The SD CCAs further request that in directing the filing of an amended Advice Letter, the Commission make clear that there will be a timeline of at least one month between that filing and the effective date of the rate changes proposed therein, commensurate with the timing contemplated in AL 4791-E.

I. BACKGROUND
In its most recent GRC Phase 2, SDG&E received Commission approval for the implementation of a new Medium Commercial customer class.5 Previously, SDG&E had a Small Commercial customer class, encompassing customers with demand less that 20 kW, as well as a Medium/Large Commercial & Industrial (“C&I”) customer class, which encompassed customers with demand over 20 kW.6 The new Medium Commercial class will be available to customers with demand at or above 20 kW and less than 200 kW.7 To implement this change, SDG&E recategorized several rate schedules as Medium Commercial for the purposes of revenue allocation and marginal cost studies, and bifurcated two existing Large C&I schedules into Medium Commercial and Large C&I versions.8
In AL 4791-E, SDG&E proposes updated rates, tariffs, and rate design reflective of this new class structure. These updated rates and tariffs include changes to PCIA rates as reflected in Attachment D, Schedule CCA-CRS: Community Choice Aggregation Cost Responsibility Surcharge.9 The PCIA is a non-bypassable charge which both bundled and unbundled customers 5 Id. at Attachment B, Section 3.2.4.1
6 See SDG&E AL 4791-E at 3.
7 Id.
8 Id.
9 See id. at Attachment D, Schedule CCA-CRS.
71 SDCP and CEA Protest of SDG&E AL 4791-E 3
are responsible for.10 Whereas CCA customers pay CCA-specific generation charges, plus a PCIA rate, SDG&E currently embeds bundled PCIA rates in its bundled generation rates.11 Accordingly, inaccuracies in proposed PCIA rates impact both bundled and unbundled customers.

II. PROTEST
A. SDG&E’s PCIA Rate Calculations Reflect a Mismatch in the Alignment of Revenues and Sales Volumes Associated with its Commercial Classes.

In separating out its new Medium Commercial class, SDG&E notes that it did not develop Medium Commercial-specific PCIA rates, and instead proposes to use existing Medium/Large C&I rates for this purpose until SDG&E has standalone PCIA rate filings, at which point SDG&E plans to develop Medium Commercial PCIA rates.12 The SD CCAs do not object to this approach as an interim methodology.

Although SDG&E does not propose a Medium Commercial class-specific PCIA rate, SDG&E’s existing PCIA rates are necessarily impacted by its updated revenue allocations associated with the new Medium Commercial class. At a high level, where revenues are reallocated among customer classes, the associated sales volumes must also be updated to maintain consistency and ensure that the resulting rates appropriately reflect cost responsibility. In evaluating the workpapers underlying SDG&E’s updated PCIA rates, the SD CCAs discovered that SDG&E adjusted revenue allocations to reflect the new Medium Commercial class, but did not update the underlying sales volumes.

As a result of this error, SDG&E’s proposed PCIA rates are distorted among customer classes. Specifically, SDG&E’s proposed PCIA rates decreased for Small Commercial customers and increased for Medium and Large Commercial customers, materially departing from the PCIA rates previously approved and effective as of January 1, 2026.13 To illustrate this error, the SD CCAs calculated an impact based on a best estimate of corrected sales volumes attributable to the Medium Commercial class. Correcting the sales volumes underlying SDG&E’s proposed PCIA 10 See D.25-09-006 at 64.
11 Id. at 65.
12 SDG&E AL 4791-E at Footnote 7.
13 See, e.g., SDG&E AL 4757-E, Attachment H, Schedule CCA-CRS (Dec. 31, 2025). 72 SDCP and CEA Protest of SDG&E AL 4791-E 4
rates increased the Small Commercial PCIA rates by approximately $0.01359 and decreased the Medium/Large C&I PCIA rates by as much as $0.00579. After this correction, the PCIA rates proposed in AL 4791-E align more closely with the PCIA rates effective January 1, 2026.

The SD CCAs do not have the detailed data necessary to conduct a similar analysis of SDG&E’s proposed Commodity and Delivery rates. However, a high-level review of Attachment A indicates that SDG&E did adjust sales volumes when calculating the Commodity and Delivery Rates.

B. Accurate PCIA Rates are Critical to Ensure Just and Reasonable Rates, and to Mitigate Unreasonable Impacts on CCA Operations.

Because PCIA rates are incorporated into CCA customers’ total bills and inform CCA ratesetting, even small distortions in PCIA rates can translate into meaningful customer bill impacts and impair CCAs’ ability to set accurate and reasonably stable rates. As described above, PCIA rates are non-bypassable for both bundled and unbundled customers. To the extent PCIA rates are erroneously calculated and fail to reflect cost responsibility, both bundled and unbundled customers will be subject to unjust and unreasonable bill impacts. In the instant case and absent correction, both bundled and unbundled Medium/Large C&I customers would be responsible for an unreasonable portion of PCIA cost responsibility and subject to an unexpected PCIA rate increase outside of the typical ERRA cycle.

Beyond customer bill impacts more broadly, inaccuracies in PCIA rate calculations impact CCAs’ ability to set their own generation rates in a manner reflecting underlying cost structures.

For example, the SD CCAs rely on SDG&E’s rate calculations as inputs to their own rate models and analyses and are thereby constrained in developing updated and accurate rates for their customers when these inputs contain inaccuracies. Moreover, the SD CCAs adjust rates in a cadence aligned with material updates to SDG&E’s PCIA rates, meaning that the SD CCAs will be delayed in their ability to update customer rates pending resolution of this error. Accordingly, it is imperative that the Commission act quickly to reject AL 4791-E and provide SDG&E with direction to correct its PCIA rate calculations.
73 SDCP and CEA Protest of SDG&E AL 4791-E 5
C. In Ordering this Correction, the Commission Should Make Clear the Timeline Between Refiling and Rate Implementation.

SDG&E submitted AL 4791-E on March 2, 2026, with a proposed effective date of April 1, 2026.14 This approximately one-month window between filing and implementation of the proposed rate updates is critical to the SD CCAs’ ability to review and analyze both the accuracy of those proposed rates and to incorporate changes into potential CCA rate adjustments. The SD CCAs therefore respectfully request that in directing SDG&E to re-submit an amended Advice Letter, the Commission clarify that there will be at least a one-month period between that filing and the effective date of the rate changes described therein, commensurate with the timing contemplated in the instant Advice Letter.

III. CONCLUSION
For the reasons set forth above, the SD CCAs request that Energy Division reject Advice Letter 4791-E, instruct SDG&E to file an amended Advice Letter containing corrected PCIA rates that reflect the sales expected to move into the Medium Commercial class, and make clear that there will be a timeline of at least one month between that filing and the effective date of the rate changes proposed therein.

Respectfully submitted,
March 23, 2026 /s/ Alissa Greenwald
Alissa Greenwald
Tim Lindl
Keyes & Fox LLP
580 California Street, 12th Floor
San Francisco, CA 94104
Telephone: (913) 302-5567
E-mail: [email protected]
[email protected]
On behalf of San Diego Community Power
and Clean Energy Alliance
cc: [email protected]
[email protected]
Service Lists: A.22-05-015 et al., A.23-01-008
14 See SDG&E AL 4791-E at 1.
74 ITEM 10

ATTACHMENT B
75 SDCP and CEA Protest of SDG&E AL 4817-E 1
April 6, 2026
Via E-Mail ([email protected])
Energy Division, Tariff Unit
California Public Utilities Commission
505 Van Ness Avenue, 4th Floor
San Francisco, California 94102
Subject: Protest of San Diego Community Power and Clean Energy Alliance to San Diego Gas & Electric Company Advice Letter 4817-E
Dear Energy Division Tariff Unit:

San Diego Community Power (“SDCP”)1 and Clean Energy Alliance (“CEA”)2 (together, the “SD CCAs”) hereby protest San Diego Gas & Electric Company (“SDG&E”) Advice Letter (“AL”) 4817-E, Request to Present Power Charge Indifference Adjustment Rate on Bundled Customer Bills and in its Electric Energy Commodity Cost Tariffs Pursuant to 2024 General Rate Case Phase 2 Decision. Through AL 4817-E, SDG&E seeks Commission approval of its plans to present the Power Charge Indifference Adjustment (“PCIA”) rate as a separate line item on bundled customer bills and in its Electric Energy Commodity Cost (“EECC”) tariffs.3 SDG&E explains that do so, it plans to recover PCIA revenues allocated to bundled customers through a separate bundled PCIA rate and that it will display the bundled PCIA rate as a separate line item in its EECC tariffs and on bundled customer bills.4
1 SDCP is the Community Choice Aggregator (“CCA”) for the cities of Chula Vista, Encinitas, Imperial Beach, La Mesa, National City, and San Diego, as well as the unincorporated areas of San Diego County.
2 CEA is the CCA for the cities of Carlsbad, Del Mar, Solana Beach, Escondido, San Marcos, Oceanside, and Vista.
3 San Diego Gas & Electric Company (“SDG&E”) Advice Letter (“AL”) 4817-E: Request to Present Power Charge Indifference Adjustment Rate on Bundled Customer Bills and in its Electric Energy Commodity Cost Tariffs Pursuant to 2024 General Rate Case Phase 2 Decision 25-09-006 (Mar. 17, 2026). 4 Id. at 1-2.
76 SDCP and CEA Protest of SDG&E AL 4817-E 2
The bundled PCIA line item is an important step forward towards greater PCIA transparency and understandability for both bundled and unbundled customers. By presenting the PCIA as a separate line item on bundled customer bills and in SDG&E’s EECC tariffs, SDG&E will effectuate the Commission’s prior guidance that “bundled customers should be made aware of the fact that all customers are paying their share of the utility’s uneconomic costs.”5 In ordering SDG&E to implement this change, the Commission further reasoned that “[p]lacement of a PCIA rate in a separate line-item in EECC tariffs and on bundled customer bills will help customers better understand that the PCIA charge is not a fixed charge.”6 While the SD CCAs strongly support this change, SDG&E proposes an open-ended and entirely discretionary delay in actually implementing the PCIA line item in its EECC tariffs and on bundled customer bills. This proposal is unreasonable and contrary to the intention underlying the Commission’s direction for this advice letter submission. Further, AL 4817-E lacks important details as to how SDG&E intends to present the bundled PCIA rate on bundled customer bills in compliance with Decision (“D.”) 25-09-006. Finally, while the SD CCAs do not, at this time, contest SDG&E’s methodology to calculate the bundled PCIA rate, the Commission should revisit this calculation methodology in SDG&E’s 2027 Energy Resource Recovery Account (“ERRA”) Forecast proceeding to consider the reasonableness of discrepancies between the latest vintage unbundled PCIA rate and SDG&E’s proposed bundled PCIA rate.

Accordingly, the SD CCAs protest this Advice Letter pursuant to General Order (“GO”) 96-B, Sections 7.4.2(2) and 7.4.2(6). The SD CCAs respectfully request that Energy Division reject AL 4817-E and direct SDG&E to submit an amended advice letter that seeks to implement the bundled PCIA line item by August 1, 2026, and in no event later than December 31, 2026. In addition, the SD CCAs request that Energy Division direct this amended advice letter to describe the specific elements of the PCIA line item to be presented on bundled customer bills. The SD CCAs further recommend that the Commission revisit the bundled PCIA rate calculation in SDG&E’s upcoming 2027 ERRA Forecast proceeding.
5 Decision (“D.”) 18-10-019, p. 119 (Oct. 19, 2018) (emphasis added). 6 D.25-09-006, p. 66 (Sept. 22, 2025).
77 SDCP and CEA Protest of SDG&E AL 4817-E 3
I. BACKGROUND
The PCIA is a non-bypassable charge for which both bundled and unbundled customers are responsible.7 Whereas CCA customers pay CCA-specific generation charges, plus a PCIA rate, SDG&E currently embeds bundled PCIA rates in its bundled generation rates.8 SDG&E does not currently present bundled customers with a delineated line item PCIA charge in the “Electric Charges” section of bills, or in its EECC tariffs.9 By contrast, SDG&E presents the PCIA on unbundled customer bills as a separate line item in the “Electric Charges” section of unbundled customer bills.10 That line item includes the customer’s kilowatt-hour (“kWh”) usage, the dollar per kWh PCIA rate applied, and the resulting PCIA charge.11 In its most recent GRC Phase 2, the Commission directed SDG&E to “(1) show the PCIA rate on bundled customer bills in the same manner it currently displays the PCIA on unbundled customer bills as a volumetric rate and (2) delineate the PCIA from bundled commodity rates in its EECC tariffs.”12 In AL 4817-E, SDG&E proposes a new methodology to calculate a separate PCIA rate for bundled customers.13 SDG&E states that it will present this bundled PCIA rate as a separate line item in EECC tariffs and on bundled customer bills, but that it will not implement this change until 2027, at the earliest.14
II. PROTEST
A. The Commission Should Require SDG&E to Implement the Bundled PCIA Line Item By August 1, 2026.

1. AL 4817-E is Insufficient to Meet the Requirements of D.25-09-006.

In D.25-09-006, the Commission ordered SDG&E to “submit a Tier 1 Advice Letter that seeks Commission approval to present the Power Charge Indifference Adjustment rate on bundled 7 See id. at 64.
8 Id. at 65.
9 See id.; see also Application (“A.”) 23-01-008, Opening Brief of San Diego Community Power and Clean Energy Alliance, p. 5, Figures 1-2 (Aug. 16, 2024). 10 See id. at 6, Figure 3.
11 See id.
12 D.25-09-006 at 67.
13 AL 4817-E at 1-2.
14 Id. at 2.
78 SDCP and CEA Protest of SDG&E AL 4817-E 4
customer bills and present the Power Charge Indifference Adjustment rate in its Electric Energy Commodity Cost tariffs no later than 180 days after effective date of the final decision.”15 The plain language of D.25-09-006 requires SDG&E to timely seek Commission approval to implement a bundled PCIA line item – not to defer implementation to an undefined date of its choosing. Indeed, Ordering Paragraph 10 does not state that this advice letter submission should seek Commission approval of SDG&E’s plans to implement the bundled PCIA line item at some time in the future.

AL 4817-E does not satisfy D.25-09-006’s directive. Rather than providing meaningful implementation details, SDG&E merely states that it intends to implement the bundled PCIA line item “in 2027, at the earliest.”16 AL 4817-E offers no implementation plan, no IT development or testing progress, and no concrete milestones. This lack of specificity, coupled with SDG&E’s failure to propose any near-term efforts to implement the bundled PCIA line item, are inconsistent with the Commission’s intent and render this advice letter submission effectively meaningless.

2. SDG&E Fails to Substantiate its Claim That it is Not Currently Feasible to Implement the Bundled PCIA Line Item.

Even if some limited delay were permissible under D.25-09-006, SDG&E fails to demonstrate that near-term implementation is infeasible. SDG&E asserts that development and testing requirements, other planned rate implementation projects, and its ongoing Customer Information System (“CIS”) migration prevent implementation prior to 2027, at the earliest.17 But those assertions are generalized and unsupported. SDG&E provides no detailed explanation as to the scope of work required to implement the bundled PCIA line item, no assessment of resource constraints, and no specific analysis as to why this effort cannot proceed alongside other planned projects.

In discovery, SDG&E identified various projects planned for 2026 and early 2027, but did not explain how those efforts specifically limit its ability to develop, test, and validate the bundled 15 D.25-09-006 at Ordering Paragraph (“OP”) 10.
16 AL 4817-E at 2.
17 Id.
79 SDCP and CEA Protest of SDG&E AL 4817-E 5
PCIA line item.18 Nor did it identify specific resource limitations, areas of overlap that would constrain bandwidth, or competing priorities that would make timely implementation infeasible.

In the absence of specific, detailed constraints, SDG&E’s claimed inability to implement the bundled PCIA line item is insufficient to justify its proposed delay.

3. SDG&E’s Request for an Undefined, Indefinite Delay is Unreasonable.

Beyond its lack of specific justification, SDG&E’s proposed delay is also effectively open-ended. AL 4817-E states that SDG&E plans to implement the bundled PCIA line item “in 2027, at the earliest.”19 SDG&E further declined to provide target timelines or an outer bound by which implementation will occur.20 In short, SDG&E seeks unfettered discretion over when it will choose to comply with D.25-09-006.

This request is particularly unreasonable given the Commission’s longstanding efforts to increase PCIA transparency and understandability. Nearly ten years ago, the Commission emphasized that changes to customer bill and investor-owned utility tariffs were needed to improve PCIA transparency.21 Yet SDG&E has repeatedly relied on similar justifications – i.e., the existence of outstanding, Commission-required bill or rate changes – to defer meaningful improvements.22 The Commission should not permit further, indefinite delay based on the same generalized rationale, particularly where SDG&E has failed to substantiate its claimed constraints.

4. The Commission Should Establish a Deadline by Which SDG&E Must Implement the Bundled PCIA Line Item.

Because SDG&E has failed to provide a defined implementation timeline, the Commission should establish one. Absent Commission direction, SDG&E’s proposal would permit indefinite delay. To ensure timely implementation, the Commission should instruct SDG&E to implement the necessary rate, bill presentment, and tariff changes by August 1, 2026. This timeline corresponds with SDG&E’s scheduled General Rate Case Memorandum Account rate update, 18 See Attachment A: Select SDG&E Responses to SD CCA Data Requests (“DRs”), DR 1.06 (Mar. 31, 2026).
19 AL 4817-E at 2.
20 Attachment A at DR 1.08.
21 D.18-10-019 at 119.
22 See D.20-03-019, pp. 20-21 (Mar. 26, 2020).
80 SDCP and CEA Protest of SDG&E AL 4817-E 6
thereby aligning the work necessary to effectuate this change with other planned rate updates and creating efficiencies for Commission review and approval.

If the Commission determines that the August 1, 2026 deadline is not reasonable, then it should, in the alternative, direct SDG&E to implement the bundled PCIA line item no later than December 31, 2026. SDG&E has estimated that development, testing, and validation may require six to seven months.23 Assuming the Commission issues a final resolution in May of 2026, this end-of-year deadline provides SDG&E ample time to complete implementation efforts while ensuring that delay does not extend indefinitely.

B. The Commission Should Require SDG&E to Specify the Elements it Intends to Include in the PCIA Line Item on Bundled Customer Bills.

In concluding that SDG&E must present a separate bundled PCIA rate on bundled customer bills and in its EECC tariffs, the Commission emphasized that “volumetric charges should be displayed in a fair manner on both bundled and unbundled customer bills.”24 Accordingly, the Commission concluded that SDG&E must “show the PCIA rate on bundled customer bills in the same manner it currently displays the PCIA on unbundled customer bills as a volumetric rate.”25 SDG&E presents the PCIA on unbundled customer bills as a separate line item in the “Electric Charges” section that includes the customer’s kilowatt-hour (“kWh”) usage, the dollar-per-kWh PCIA rate applied, and the resulting PCIA charge.26 Although SDG&E states that it will display the bundled PCIA rate as a separate line item on bundled customer bills, it fails to specify whether that presentation will include the essential elements required by D.25-09-006 – namely, the kWh usage, the relevant dollar-per-kWh PCIA rate, and the resulting PCIA charge.27 Without these elements, SDG&E’s bundled PCIA bill presentation will not mirror its unbundled PCIA bill presentation. The Commission should therefore direct SDG&E to specify the precise components of its bundled PCIA bill presentation in an amended advice letter filing.
23 Attachment A at DR 1.05.
24 D.25-09-006 at 66.
25 Id. at Conclusion of Law (“COL”) 29 (emphasis added). 26 See A.23-01-008, SD CCA Opening Brief at 6, Figure 3. 27 AL 4817-E at 2.
81 SDCP and CEA Protest of SDG&E AL 4817-E 7
C. The Commission Should Revisit SDG&E’s Bundled PCIA Rate Calculation in its 2027 ERRA Forecast Proceeding.

Currently, SDG&E’s bundled customers are assigned the most recent PCIA vintage, and the bundled PCIA rate component is embedded within SDG&E’s generation rates.28 In AL 4817- E, SDG&E explains that in order to effectuate the required bill and tariff changes, it will recover PCIA revenues allocated to bundled customers through a new, separate bundled PCIA rate.29 SDG&E explains that it will calculate the bundled PCIA rate by allocating bundled PCIA revenues to each customer class using the authorized generation allocation factors, then dividing the class-level revenues by the authorized forecasted bundled kWh sales per customer class.30 Importantly, the resulting rate differs from the latest vintage bundled PCIA rate component currently incorporated within SDG&E’s generation rates.31
SDG&E argues that simply utilizing the latest vintage PCIA rate as the bundled PCIA rate is improper as it would result in a cost shift between customer classes. SDG&E currently allocates the PCIA revenue requirement to all customer classes in each vintage using the same generation allocation factors.32 However, SDG&E asserts that the resulting revenues forecasted to be collected from each vintage of unbundled PCIA rates are not necessarily aligned with the authorized generation revenue allocation factors, primarily due to variations in each class’s portion of departed load sales per vintage.33 As unbundled PCIA rates are cumulative of each preceding vintage and therefore reflect this misalignment, SDG&E argues that application of the latest vintage PCIA rate to unbundled sales would result in a cost shift.34 The SD CCAs do not, at this time, contest SDG&E’s proposed bundled PCIA rate calculation as set forth in AL 4817-E. However, the discrepancy between the new bundled PCIA rate and SDG&E’s existing latest vintage PCIA rate highlights an issue that merits further Commission evaluation in a future proceeding. It is possible that adjustments to the generation allocation factors would sufficiently mitigate cost shifting while allowing for use of the existing 28 See D.25-09-006 at 65; Attachment A at DR 1.02.
29 AL 4817-E at 1-2.
30 Id.
31 Attachment A at DR 1.02.
32 See id.
33 Id.
34 Id.
82 SDCP and CEA Protest of SDG&E AL 4817-E 8
unbundled PCIA rate calculation and aligning SDG&E’s bundled PCIA rate calculation more closely with the methodology utilized by other investor-owned utilities. The Commission should therefore revisit this issue in SDG&E’s upcoming 2027 ERRA Forecast proceeding, where a more complete record can support evaluation of potential cost shifts and improvements to this calculation methodology.

III. CONCLUSION
For the reasons set forth above, the SD CCAs request that Energy Division reject AL 4817- E and direct SDG&E to submit an amended advice letter that: 1) seeks to implement the bundled PCIA line item by August 1, 2026, and in no event later than December 31, 2026, and 2) describes the specific elements SDG&E will display as part of the PCIA line item on bundled customer bills.

The SD CCAs further request that the Commission consider evaluating changes to the bundled PCIA rate calculation in SDG&E’s upcoming 2027 ERRA Forecast proceeding.

Respectfully submitted,
April 6, 2026 /s/ Alissa Greenwald
Alissa Greenwald
Jacob Schlesinger
Keyes & Fox LLP
580 California Street, 12th Floor
San Francisco, CA 94104
Telephone: (913) 302-5567
E-mail: [email protected]
[email protected]
On behalf of San Diego Community Power
and Clean Energy Alliance
cc: [email protected]
[email protected]
Service List: A.23-01-008
83 ATTACHMENT A
Select SDG&E Responses to SD CCA Data Requests
84 San Diego Community Power/Clean Energy Alliance
SDCP_CEA-SDGE-DR-001_4817-E
DATE RECEIVED: March 20, 2026
DATE RESPONDED: March 31, 2026
SDCP/CEA to SDG&E 1.02.

Referring generally to SDG&E Advice Letter 4817-E: Does SDG&E agree that the most recent vintage PCIA rates calculated using SDG&E’s PCIA model workpapers used in ERRA proceedings would be equivalent to the PCIA rate for bundled customers described in AL 4817-E (e.g. vintage 2026 PCIA rates would be equal to bundled PCIA rates for 2026)? If SDG&E does not agree, please explain in detail why the most recent vintage PCIA rates would not be equivalent to the proposed PCIA rates for bundled customers.

SDG&E Response to 1.02:

The most recent vintage PCIA rates are not equivalent to the proposed PCIA rates for bundled customers presented in AL 4817-E. To execute the directives in D.25-09-006 SDG&E calculates bundled PCIA rates separately because utilizing the most recent vintage PCIA rates would result in a cost shift between customer classes. This dynamic is a result of the established PCIA rate calculation methodology, described in more detail below.

SDG&E uses the authorized generation revenue allocation factors, which are the same factors used to allocate bundled commodity revenues, to split PCIA-related revenues among the customer classes. However, pursuant to the established unbundled PCIA rates calculation methodology, the resulting revenues forecasted to be collected from each vintage of unbundled PCIA rates is not necessarily aligned with the authorized generation revenue allocation factors. When developing unbundled PCIA rates, the class-level incremental revenues for each vintage of resources, which are allocated based on the authorized generation allocation factors, are divided by the class-level departed load sales for that vintage.1 Notably, each customer class’s portion of the total departed load sales differs per vintage. The final unbundled PCIA rates are cumulative of each preceding vintage, and therefore the resulting revenues to be collected from the latest vintage of unbundled PCIA rates reflects the differing customer class sales and effective revenues resulting from all incremental unbundled vintaged rates. As a result, applying the latest unbundled vintage PCIA rate to bundled sales would result in a cost shift.

Vintaged PCIA rates are currently calculated for unbundled customers only, and are used as an illustrative proxy only in the summary section of bundled bills, since bundled PCIA revenues are already embedded in bundled commodity rates.2 In order to both “delineate the PCIA from bundled commodity rates in its EECC tariffs” and implement the approved revenue allocation factors, pursuant to D.25-09-006, SDG&E proposes to take the bundled 1 D.19-10-001, OP 6.
2 Because bundled PCIA is embedded within bundled commodity rates, it is collected via seasonal demand and time-of-use volumetric rates versus unbundled PCIA is a flat, non-seasonal $/kWh rate. 85 San Diego Community Power/Clean Energy Alliance
SDCP_CEA-SDGE-DR-001_4817-E
DATE RECEIVED: March 20, 2026
DATE RESPONDED: March 31, 2026
portion of PCIA revenues, allocate them among the customer classes using the authorized generation revenue allocation, then divide the revenues per class by the classes’ sales, which prevents cost shifting among customer classes, and results in different rates than the latest vintage unbundled PCIA rates.

86 San Diego Community Power/Clean Energy Alliance
SDCP_CEA-SDGE-DR-001_4817-E
DATE RECEIVED: March 20, 2026
DATE RESPONDED: March 31, 2026
SDCP/CEA to SDG&E 1.05.

Referring to SDG&E Advice Letter 4817-E at page 2, stating “this Bundled PCIA rate change…will therefore require significant development, testing, and validation prior to implementation”: Please explain whether SDG&E has conducted any specific assessments as to the anticipated timeline needed to complete this development, testing, and validation. If so, please explain in detail and provide any materials either supporting the this assessment.

SDG&E Response to 1.05:

The Bundled PCIA rate change will impact every rate schedule and therefore requires rigorous and comprehensive testing and review to ensure it is accurately captured in SDG&E’s billing system. While SDG&E has not conducted a detailed assessment of the specific development timeline, its anticipated schedule is based on high‑level, cross‑functional discussions between rates and billing systems teams that considered both the scope of the change and overall feasibility. SDG&E’s anticipated schedule is a 6 to 7 month timeframe once a feasible starting date is identified. Given the broad, system‑wide impact and the need to coordinate this effort alongside other near‑ and medium‑term implementation workstreams, it is reasonable, prudent, and in ratepayers’ best interest for SDG&E to perform thorough testing and validation prior to implementation. 87 San Diego Community Power/Clean Energy Alliance
SDCP_CEA-SDGE-DR-001_4817-E
DATE RECEIVED: March 20, 2026
DATE RESPONDED: March 31, 2026
SDCP/CEA to SDG&E 1.06.

Referring to SDG&E Advice Letter 4817-E at page 2, stating “SDG&E already has several substantial regulatory and rate changes/implementations planned for 2026”:

Please provide a list of the regulatory and rate changes/implementations that SDG&E has planned for 2026, including the target deadline to implement these regulatory and rate changes/implementations, as well as citations to the relevant Commission decisions, rulings, or dispositions ordering those changes/implementations.

SDG&E Response to 1.06:

Below are the regulatory and rate changes/implementations planned for 2026 and early 20273:

1. Implementation of 2024 General Rate Case Phase 2 and Track 2 Wildfire Mitigation Costs
a. Effective Date: April 1, 2026
b. Regulatory reference: D.25-09-006 and D.26-01-021

2. Climate Credit OIR
a. Effective Date: TBD 2026, likely August & September 20264 b. Regulatory Reference: R.25-07-013

3. TO6 Offer of Settlement Filing
a. Effective Date: TBD – Q2/Q3 2026
b. Regulatory Reference: ER25-270-002

4. General Rate Case Memorandum Account Roll-Off
a. Effective Date: August 1, 2026
b. Regulatory Reference: D.24-12-074

5. Virtual Net Billing Tariff and multifamily Net Billing Tariff:
a. Effective Date: September 1, 2026
b. Regulatory Reference: Resolution E-5374

6. Prevailing Wage (PURPA Compliance)
a. Implementation Date: September 1, 2026
b. Regulatory Reference: D.23-11-068

7. January 1, 2027 Consolidated Rate Change
a. Effective Date: January 1, 2027
b. Regulatory Reference: Resolution E-5217
3 Implementations in early 2027 require lead-time and work in 2026. 4 On March 26, 2026, a proposed decision was published on R. 25-07-013, which directs the IOUs to shift the distributions of the electric climate credits to August and September. 88 San Diego Community Power/Clean Energy Alliance
SDCP_CEA-SDGE-DR-001_4817-E
DATE RECEIVED: March 20, 2026
DATE RESPONDED: March 31, 2026

8. Disadvantaged Communities Green Tariff (DAC-GT) Discount a. Effective Date: Q1 2027
b. Requested by San Diego Community Power

9. Demand Flexibility Rate Design
a. Effective Date: TBD
b. Regulatory Reference: R.22-07-005; A.26-02-001

89 San Diego Community Power/Clean Energy Alliance
SDCP_CEA-SDGE-DR-001_4817-E
DATE RECEIVED: March 20, 2026
DATE RESPONDED: March 31, 2026
SDCP/CEA to SDG&E 1.08.

Referring to SDG&E Advice Letter 4817-E at page 2, stating “SDG&E plans to implement this change in 2027, at the earliest”: Please explain in which quarter of 2027 SDG&E currently aims to implement the Bundled PCIA line item. In addition, please explain the latest possible date at which SDG&E expects to implement the Bundled PCIA line item.

SDG&E Response to 1.08:

As the regulatory landscape for 2027 and later is currently developing and the regulatory/rate changes that will be required are still unknown, SDG&E does not have a finalized date that this change will be implemented as internal discussions are on-going to determine how to best integrate this change along with the existing regulatory requirements noted above, and ensure the appropriate level of testing and validation is completed.

END OF RESPONSE
90 ITEM 10

ATTACHMENT C
91 [email protected]
619-208-2897
March 16, 2026
The Honorable Cottie Petrie Norris
Assembly Committee on Utilities & Energy
1020 N Street, Room 408A
Sacramento, CA 95814
Subject: AB 2313 (Berman) Gas corporations: gas distribution service line replacements: alternatives– SUPPORT Dear Assemblymember Petrie Norris,
On behalf of San Diego Community Power (SDCP), I write in support of AB 2313 (Berman). SDCP is a not-for-profit public agency that offers competitive, renewable, and community-focused electricity service to more than 965,000 customers across the cities of San Diego, Chula Vista, Encinitas, Imperial Beach, La Mesa, National City, as well as the unincorporated areas in the County of San Diego. The agency’s mission is to deliver affordable, 100% renewable energy by 2035 or earlier and invest in the community to ensure an equitable and sustainable future for San Diego.

AB 2313 (Berman) would fill a gap in the current SB 1221 (Chapter 602, Statutes of 2024) implementation process underway at the CPUC. SB 1221, a forward-looking law focused on transitioning away from household use of natural gas, allows a gas corporation to cease providing natural gas service in an area if the CPUC determines that adequate substitute energy service is available. The CPUC hasn’t determined how to fund the gas alternatives – such as replacement of gas appliances with electric ones – in selected priority neighborhood decarbonization pilot zones. AB 2313 (Berman) fills this gap by creating a Gas Distribution Service Line Replacement Alternatives Program to offer monetary incentives to adopt alternatives that do not require connection to the gas system, such as switching to electric appliances. Funding would come from costs approved for gas line replacement, with cost recovery over 10 years.

The legislation provides a prudent safeguard measure in the event the CPUC takes a long time to determine how to fund alternatives in pilot neighborhood decarbonization zones that will be converted from gas to electric service. It aligns with SDCP’s mission and support for policies that enable building electrification, equity, and acceleration of deep decarbonization.

Thank you for considering our position. Please contact me or our representative, Amy Costa ([email protected]), with any questions.

Sincerely,
Patrick Welch
Associate Director of Legislative Affairs
Cc: The Honorable Marc Berman, 23rd Assembly District
92 ITEM 10

ATTACHMENT D
93 March 19, 2026
The Honorable Cottie Petrie Norris
Assembly Committee on Utilities & Energy
1020 N Street, Room 408A
Sacramento, CA 95814
Subject: AB 2493 (Petrie-Norris) Electrical corporations: interconnection: transmission: auditor – SUPPORT Dear Assembly Member Petrie Norris,
On behalf of San Diego Community Power (SDCP), I write in support of AB 2493 (Petrie-Norris). SDCP is a not-for-profit public agency that offers competitive, renewable, and community-focused electricity service to more than 965,000 customers across the cities of San Diego, Chula Vista, Encinitas, Imperial Beach, La Mesa, National City, as well as the unincorporated areas in the County of San Diego. The agency’s mission is to deliver affordable, 100% renewable energy by 2035 or earlier and invest in the community to ensure an equitable and sustainable future for San Diego. SDCP has contracted for 3.4 gigawatts (GWs) of renewable and storage capacity from local and geographically diverse solar, wind, and battery storage projects. We expect over 1.5 GWs of these resources to come online this year, marking a significant achievement for SDCP since first serving customers in 2021.

Transmission capacity is essential to meet both our Board established 100% renewable goal and the state’s standards. Our market experience suggests that completion of transmission network upgrades – projects that generally increase the capacity of existing transmission facilities – are a significant barrier to both the deliverability of projects and timely commercial operation of generating and energy storage projects. Likewise, the timely completion of new transmission facilities approved in the California Independent System Operator (CAISO) transmission planning process (TPP) is also vital to accessing new, diverse generating and energy storage projects. The most recent statistics from the Public Advocates Office Transmission Data Dashboard demonstrate the problem. Fifty-nine percent of transmission projects approved since 2012 are still being built. Nearly half of all transmission projects approved in the TPP since 2000 have seen delays beyond their original in service date. The average delay is just over two years, with the longest delay reaching 15 years.

Delays in transmission projects can result in new costs to ratepayers in the form of increased project costs and payments for expensive bridge capacity contracts to replace the capacity that was expected to come online by a specific date. Empowering the California Public Utilities Commission (CPUC) to order remedial actions for priority transmission projects is an important step to fix the problem. AB 2493 (Petrie-Norris) will help ensure timely project delivery, guard against unnecessary ratepayer costs and will help optimize California’s resource market by ensuring there is sufficient transmission capacity in a timely manner.

To ensure the bill appropriately aligns with the scope of the problem, we respectfully offer two suggestions for consideration:

1. The audit process should be appropriately staffed so it does not become a new administrative roadblock itself, especially given the relatively low 100-megawatt threshold definition for priority projects. Adequate staffing will ensure audits are efficient and do not inadvertently delay critical projects, allowing the intended benefits of the bill to be realized without creating additional obstacles. 94 [email protected]
619-208-2897
2 2. It may be prudent to authorize the CPUC to order remedial actions regardless of an audit under certain conditions, with specific focus given to generators procuring equipment or self-building on behalf of the electrical corporation using consistent labor and safety standards, as there is market willingness to engage in these activities. This flexibility could enable the CPUC to respond quickly to market opportunities and address urgent needs, ensuring that projects are not stalled when stakeholders are prepared and capable of advancing them responsibly.

Thank you for your leadership on this important issue. Please contact me or our representative, Amy Costa ([email protected]), with any questions.

Sincerely,
Patrick Welch
Associate Director of Legislative Affairs
95 ITEM 10

ATTACHMENT E
96 April 1, 2026
Assemblymember Cottie Petrie-Norris, Chair
Assembly Committee on Utilities and Energy
1020 N Street, Suite 121
Sacramento, CA 95814
Re: AB 2508 (Hoover)- Oppose
Dear Chair Petrie-Norris,
We the undersigned write to express our respectful opposition to AB 2805 (Hoover), which would eliminate the current funding stream for the state’s Public Purpose Programs, including energy efficiency (EE) and research and development programs, and instead force them to compete for more volatile and scarce Greenhouse Gas Reduction Funds (GGRF). Injecting this level of uncertainty into the state’s EE programs will compound the current affordability crisis by eliminating the benefits of EE to both individual ratepayers and the energy system as a whole. It will cost more than it will save. 97 Energy Efficiency is Crucial for Reliability and Affordability California is facing a new era of load growth, driven by electrification and data centers. The CEC estimates that total electricity consumption will increase by as much as 45%, and peak demand will increase by as much as 42%, by 2045.1 Without robust and stable energy efficiency programs to manage demand and support reliability, these increases will be even larger. California’s Loading Order policy prioritizes EE and demand reduction before other generation resources, because the cheapest electron is the one we never have to buy at all.
2 Modern EE programs also reduce peak demand by seamlessly integrating demand response and load flexibility measures capable of shifting peak loads, thereby saving ratepayers money. Importantly, the CEC’s load forecasts, which are the basis for electricity procurement planning, assume at least 13.5 GWh in achievable energy efficiency savings.3 Without these programs, load serving entities (LSEs) will need to procure an additional 13.5 GWh of generation capacity statewide to cover the shortfall.

Those costs will be passed on to ratepayers.

Beyond avoided procurement costs, EE programs provide savings on the transmission and distribution side of the bill as well. Reducing energy demand also reduces the need for new infrastructure to deliver electricity, and EE is a highly cost-effective way to do so. The CPUC’s 2025 Report on Demand Side Management Programs found that:
“…the portions of Public Purpose Program funds allocated to energy efficiency and demand response programs comprise less than five percent of the electric revenue requirement and less than four percent of the gas revenue requirement for the large investor-owned utilities. This low impact on rates provides a low-cost path to equitably achieve cost savings for customers and reduce total energy consumption and peak demand, which in turn reduces retail rates through lower energy prices and avoided capacity, transmission, and distribution costs”
4 1
Slide 9, https://www.energy.ca.gov/filebrowser/download/9328?fid=9328. Peak demand refers to the time when statewide energy usage is highest, typically 4-9pm on summer days, and power is most expensive to supply during this time.
2 Cal. Pub. Util. Code § 454.5(b)(9)(C)
3

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Page 10 ends

98 EE Provides Direct Savings to Individual Customers
Energy efficiency is one of the best tools customers can use to directly protect themselves against high rates and bills. If customers cannot reduce their usage through energy efficiency, they are more at risk of falling behind on their bills and even being disconnected, especially low-income residents who are already in economically precarious positions. While the Energy Savings Assistance Program (ESA) serves exclusively low-income customers, a significant portion of the non-income qualified energy efficiency portfolio also serves lower income customers, rural customers, affordable multi-family housing, and small businesses. For many customers, EE functions as an affordability safety net as well as an environmental opportunity.

Stable Funding is Necessary to Continue Realizing These Benefits Successful energy efficiency programs depend on reliable, predictable multi-year funding.

Funding certainty allows administrators to plan ahead with confidence, which helps ensure that all customers can participate. It also improves cost-effectiveness by allowing for bulk purchasing, efficient use of administrative resources, and other economies of scale. Sustainable and reliable funding is also essential to support nearly 312,000 energy efficiency jobs and 53,000 EE businesses across California.5 Neither the State General Fund nor the GGRF are able to provide the necessary funding certainty to sustain these valuable programs and ensure they remain cost effective. Not only are GGRF revenues hard to predict as noted by the Legislative Analysts Office (LAO), 6 but using GGRF for PPP costs may also require revisiting the deal struck by the Legislature in SB 840 (Limon, 2025). Under the legislation, GGRF discretionary revenues are allocated in tiers of priority, including towards replacing the State Responsibility Area fire prevention fee, high speed rail, public transit passes, a University of California Climate Research Center, community air protection, and several other programs that do not pertain to efforts currently supported by the PPP.

Given the key role that EE programs play in the state’s energy management strategy and the benefits they provide to affordability and grid stability, the state must ensure that these programs remain viable. Shifting the funding source of the state’s EE programs to the volatile GGRF will threaten both the affordability benefits and system reliability benefits that are provided by these programs. As such, we urge you to vote NO on AB 2508. 5 https://building-performance.org/documents/2025/EEJAFullReport_2025.pdf 6

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99 Sincerely,
Stephanie Chen
Vice President of Legislative Affairs
MCE
Chris Burmeister
Board Chair
California Efficiency + Demand
Management Council
Lucas Frerichs
Yolo County Supervisor
District 2
Sheila Allen, RN, PhD
Yolo County Supervisor
District 4
Brian Tisdale, Councilman
City of Lake Elsinore
Advocacy Committee Chair
Western Riverside Council of
Governments
Ericka Flores
Clean Energy & Equity Advocate
Natural Resources Defense Council
Ms. Shawn Marshall
Chief Executive Officer
Peninsula Clean Energy
Patrick Welch
Associate Director of Legislative Affairs
San Diego Community Power
Patricia Terry
Portfolio Lead
Northern Rural Energy Network
Demian Hardman
Board Chair
Local Government Sustainable Energy
Coalition (LGSEC)
Steve Frisch
President
Sierra Business Council
Craig Perkins
President & Executive Director
The Energy Coalition
Anthony Dang
Policy and Community Outreach Manager
Climate Action Campaign
Sneha Ayyagari
Director of Policy
Rising Sun Center for Opportunity
Chris Sentieri
Principal

CEER LLC
Jo Fleming
President
Environmental Innovations
Alexis Sutterman
Senior Policy Manager
Brightline Action
100
ITEM 10

ATTACHMENT F
101
[email protected]
619-208-2897
March 26, 2026
The Honorable Mike Gipson
Chair, Assembly Committee on Revenue & Taxation
1020 N Street, Room 167A
Sacramento, CA 95814
Subject: AB 2389 (Irwin) Property taxation: active solar energy systems: customer sited: extension – SUPPORT Dear Assemblymember Gipson,
On behalf of San Diego Community Power, I write in support of AB 2389 (Irwin). SDCP is a not-for-profit public agency that offers competitive, renewable, and community-focused electricity service to more than 965,000 customers across the cities of San Diego, Chula Vista, Encinitas, Imperial Beach, La Mesa, National City, as well as the unincorporated areas in the County of San Diego. The agency’s mission is to deliver affordable, 100% renewable energy by 2035 or earlier and invest in the community to ensure an equitable and sustainable future for San Diego.

SDCP supports efforts to enhance development of local and regional sources of renewable energy, policies that uplift collaboration with our member public agencies on local energy resources and projects, as well as legislation that enhances community choice aggregator’s ability to invest in local clean energy, including infill solar and battery storage, and other distributed energy resources to enhance grid resiliency and promote equity in the communities SDCP serves.

By extending an existing property tax exclusion of up to 2 megawatts (MW) for non-public sector entities and of any size for public agencies, AB 2389 (Irwin) will support SDCP’s continued work with our customers and member public agencies to meet both programmatic and distributed wholesale procurement goals. SDCP has committed to building 1 gigawatt (GW) of locally sited distributed energy resources, 150 MW of which will come from customer program efforts, such as our Flexible Load Strategy, which relies on – in part – customer sited solar and storage systems.

Another 150 MW will come from wholesale procurement of local solar and storage distributed projects. AB 2389 (Irwin) is important legislation that will boost the economic viability of the prospective projects, especially considering H.R. 1’s elimination of the federal Residential Clean Energy Tax Credit and the phase out of the investment and production tax credits for solar resources.

Thank you for considering our position. Please contact me or our representative, Amy Costa ([email protected]), with any questions.

Sincerely,
Patrick Welch
Associate Director of Legislative Affairs
Cc: The Honorable Jacqui Irwin, 42nd Assembly District
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ITEM 10

ATTACHMENT G
103
[email protected]
619-208-2897
April 3, 2026
The Honorable Cottie Petrie Norris
Assembly Committee on Utilities & Energy
1020 N Street, Room 408A
Sacramento, CA 95814
Subject: AB 2369 (Rogers) Electricity: resource adequacy requirements: transmission facility planning – SUPPORT Dear Assembly Member Petrie-Norris,
On behalf of San Diego Community Power, I write in support of AB 2369 (Rogers). SDCP is a not-for-profit public agency that offers competitive, renewable, and community-focused electricity service to more than 965,000 customers across the cities of San Diego, Chula Vista, Encinitas, Imperial Beach, La Mesa, National City, as well as the unincorporated areas in the County of San Diego. The agency’s mission is to deliver affordable, 100% renewable energy by 2035 or earlier and invest in the community to ensure an equitable and sustainable future for San Diego.

SDCP has contracted for 3.4 gigawatts (GW) of renewable and storage capacity from local and geographically diverse solar, wind, and battery storage projects, with 1.5 GW expected to come online this year, marking a significant achievement for SDCP since first serving customers in 2021.

AB 2369 (Rogers) will protect ratepayers from increasing electricity costs while helping achieve our renewable and clean energy goals on schedule and maintaining electric system reliability. It requires the California Public Utilities Commission's (CPUC) resource adequacy (RA) program to recognize the reliability contribution of energy-only resources. Doing so will allow more resources to connect to the grid at scale and provide reliability benefits.

As a result of CPUC market design, paired solar and storage projects can receive full transmission deliverability – an important California Independent System Operator (CAISO) determination for a project to count towards RA obligations – but the solar generation component gets an energy-only designation and won't be counted as capacity for charging storage resources. This is because the combined capacity on paper of a solar array plus battery storage is often twice the capacity of the point of interconnection where deliverability is capped. As a result, while physically SDCP’s contracted projects are charging the batteries with paired solar as designed and being grid dispatched at or up to the capacity limit of the point of interconnection, SDCP must go on the market to purchase additional generation with full deliverability to satisfy the CPUC’s charging sufficiency requirements in the RA program. This problematic market design adds unnecessary costs to SDCP’s customers.

We applaud the author’s leadership and urge support for the legislation. Please contact me or our representative, Amy Costa ([email protected]), with any questions.

Sincerely,
Patrick Welch
Associate Director of Legislative Affairs
Cc: The Honorable Chris Rogers, 2nd Assembly District
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ITEM 10

ATTACHMENT H
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1 – Appliance Standards Awareness Project (ASAP) Analysis: “Appliance Efficiency Standards Lower Utility Bills and Cut Electricity Demand in Every State” (January 2026)
March 25, 2026
The Honorable Alex Padilla The Honorable Adam Schiff
United States Senate United States Senate
331 Hart Senate Office Building 112 Hart Senate Office Building Washington, DC 20510 Washington, DC 20510
Dear Senator Padilla and Senator Schiff,
We, the undersigned California Community Choice Aggregators (CCAs), write to express our strong opposition to the Home Appliance Protection and Affordability Act (H.R. 4626) and the Homeowner Energy Freedom Act (H.R. 4758) — two bills that would undermine critical federal policies that reduce energy waste and save money for American families.

Formed and led by local governments in more than 200 towns, cities, and counties throughout the state, California’s 25 CCAs collectively serve over 14 million residents and businesses with electric service options that support local energy priorities. Our organizations support lowering energy costs and creating good jobs, including through programs that incentivize building electrification and energy efficiency upgrades.

At a time of rising electricity demand and affordability concerns, improving the energy efficiency of our homes, businesses, and communities is one of the most effective ways to combat rising energy costs and reduce strain on our electric grid. Without national efficiency standards for appliances, the average California household would have paid $8,000 more on utility bills over the last decade, and electricity consumption in the state would have been 19% higher in 2025.1 For these reasons, we respectfully urge you to reject H.R. 4626 and H.R. 4758, each of which would raise energy bills, increase grid strain, and jeopardize bipartisan consumer protections.

Home Appliance Protection and Affordability Act (H.R. 4626) H.R. 4626 would give the Department of Energy (DOE) new authority to weaken or revoke existing appliance efficiency standards and create significant roadblocks to future updates, including through imposing arbitrary payback and energy savings thresholds that would block cost-effective standards. Crucially, it would also prohibit states from setting their own standards if a federal standard is eliminated, making it more difficult for California to fill the void.

106
Existing law already requires that DOE set standards that are “technologically feasible and economically justified” and ensure that consumers continue to have access to product features they value. Instead of safeguarding affordability and consumer choice, H.R. 4626 would impose unnecessary additional restrictions on adopting proven standards that are already designed to consider those exact concerns. Further, energy efficiency, alongside load flexibility, will remain a critical tool to promote ratepayer affordability and offset emerging load growth from data centers. For more on this, we recommend reviewing the American Council for an Energy Efficient Economy (ACEEE) February report titled “Faster and Cheaper: Demand-Side Solutions for Rapid Load Growth.” Homeowner Energy Freedom Act (H.R. 4758)
H.R. 4758 would repeal rebates and training programs that help consumers adopt cost-saving technologies and help contractors deliver those savings. The bill specifically targets the High-Efficiency Electric Home Rebate (HEEHRA) Program and State-Based Home Energy Efficiency Contractor Training Grants, which provided income-qualified California households a total of $290 million to replace outdated gas-fired appliances with new, all-electric heat pump water heater and HVAC systems, and another $10.3 million to support residential energy contractor training. These are critical programs that support California families, including many CCA customers, by lowering upfront costs for energy-saving upgrades and reducing their monthly bills.

At a time when electricity demand is rising and Californians are feeling the crunch of high energy prices, we urge you to oppose legislation that would drive up costs, increase grid strain, and undermine bipartisan consumer protections. Thank you for leadership and we look forward to continuing to work together to strengthen community choice and expand energy savings for all our customers. Please reach out to Dominic Faria at [email protected] with any questions or to discuss further.

Sincerely,
Patrick Welch
Associate Director of Legislative Affairs
San Diego Community Power
107
Bena Chang
Director of Government and Legislative Affairs
Silicon Valley Clean Energy
Sam Sadle
Principal Legislative Manager
Ava Community Energy
Mike Mielke
Legislative Policy + Government Affairs
Peninsula Clean Energy
Scott Green
Scott Green
Senior Government Affairs Manager
San Jose Clean Energy
Faith Carlson
Regulatory and Legislative Policy Manager
Redwood Coast Energy Authority
Stephanie Chen
Vice President of Legislative Affairs
MCE
CC: Senator Mike Lee, Chairman, Senate Committee on Energy & Natural Resources 108
Senator Martin Heinrich, Ranking Member, Senate Committee on Energy & Natural Resources
109

SAN DIEGO COMMUNITY POWER
Staff Report - Item 11
To: Board of Directors
From: Jack Clark, Chief Operating Officer
Patrick Welch, Associate Director of Legislative Affairs Via: Karin Burns, Chief Executive Officer
Subject: Approve Agreement Renewal with Keyes & Fox LLP for Regulatory Counsel Services through May 31, 2028, for a Total Not-to-Exceed Contract Amount of $1,200,000
Date: April 23, 2026
Recommendation
Approve the Renewal Agreement with Keyes & Fox LLP for regulatory counsel services through May 31, 2028, for a total not-to-exceed (NTE) contract amount of $1,200,000 and authorize the Chief Executive Officer to execute the contract.

Background
Following an April 2023 Request for Proposals (RFP) for Regulatory Legal Counsel Services, the Community Power Board approved a three-year agreement with Keyes & Fox (K&F) LLP with an NTE of $1,300,000 (“Original Agreement”) on June 22, 2023. It superseded a short-term agreement that was previously approved in March 2023. The Original Agreement is for general regulatory counsel services and to provide legal representation before the California Public Utilities Commission (CPUC) and other regulatory agencies, as well as compliance related issues and any other matters K&F and Community Power both mutually agree to undertake. It is in effect through May 31, 2026 and contains a clause that allows for a two-year extension upon mutual agreement.

The agreement discussed in this staff report is not related to a separate agreement with K&F for outside energy procurement counsel.
110

Analysis and Discussion
Over the past three years, K&F has acted as outside regulatory counsel to Community Power at the CPUC, a quasi-judicial state agency with primary jurisdiction to regulate the state’s investor-owned utilities (IOUs). Importantly, the CPUC sets the mechanics underlying the Power Charge Indifference Adjustment (PCIA) through policy proceedings and San Diego Gas & Electric’s (SDG&E) annual Energy Resource Recovery Account (ERRA) proceedings. The CPUC also has broad regulatory authorities that extend beyond IOUs. The agency administers the Resource Adequacy compliance program, a regulatory mechanism to ensure that California has enough electric capacity contracted to ensure reliability. The CPUC also authorizes ratepayer funding for certain programs and sets rules related to community solar, energy efficiency, the Renewables Portfolio Standard, integrated resource plans, can order resource procurement, and more. K&F at times has served as counsel for engagement with other regulatory agencies such as the Federal Energy Regulatory Commission (FERC).

K&F directly supports Community Power’s intervention in these matters through written testimony, pleadings, ex parte meetings, and analysis of SDG&E filings. Their services are critical to managing and directly impacting the CPUC’s decisions and outcomes on Community Power and our customers, including the PCIA and its methodology, which was identified by Community Power staff as the biggest financial risk in a December 2025 presentation to the Board.

K&F has considerable experience representing CCAs, including intimate experience litigating issues with SDG&E on behalf of both Community Power and the Clean Energy Alliance. Below are examples of notable outcomes based on interventions led by K&F attorneys under the Original Agreement:
• Intervening in the SDG&E 2024 general rate case to prevent new utility owned generation costs. K&F’s litigation in A.22-05-016 on behalf of Community Power prevented SDG&E from investing tens of millions of dollars without sufficient cost recovery review at the Miramar Energy Facility on upgrades to add energy storage. The costs would have been born not just by SDG&E’s bundled customers, but also Community Power’s unbundled customers. As a result of K&F’s intervention, the CPUC directed SDG&E to more clearly make future proposals based on their impacts to bundled and unbundled customers.
• Secured additional oversight of SDG&E’s PCIA costs. In the 2021 ERRA Compliance proceeding (A.22-06-001), K&F objected to SDG&E’s accounting practices that led to additional oversight measures that help Community Power ensure that their PCIA rates are accurate and that SDG&E is properly managing the associating financial accounts. • Saving customers $54 million by impacting an unfavorable CPUC decision on cost allocation. In R.20-05-003, K&F secured a petition for modification (PFM) on the 111
Modified Cost Allocation Mechanism, which pertains to reliability costs IOUs incur on behalf of CCAs like Community Power. K&F’s intervention allowed Community Power – and the Clean Energy Alliance – to procure 49 MW of capacity from SDG&E using a correcting forecast method that will save at least $54 million over 12 years. • Helped secure SDREN funding. They developed the motion for the San Diego regional Energy Network’s (SDREN’s) 2024-2031 Business Plan Application, and filed comments during application proceeding deliberation, leading to the CPUC’s approval of SDREN’s formation, and authorization of $124,274,206 to fund SDREN’s portfolio of ten programs from 2024-2028. SDREN is an essential part of Community Power’s commitment to affordability, increasing targeted funding for energy efficiency, and accelerating deep decarbonization, equitably and expeditiously. • Precluded SDG&E from zeroing out the value of resources Community Power customers already paid for. In A.25-05-012, K&F intervened in a last-minute proposal from SDG&E to use renewable energy credits (RECs) they purchased before 2019 for their renewable energy compliance while assigning zero value to Community Power customers, despite our customers being bundled customers at the time SDG&E purchased the RECs. K&F successfully prevented CPUC approval of SDG&E’s proposal. • Protesting improper PCIA calculation. Supported the timely filing of a protest on an SDG&E Advice Letter to change PCIA rates for various commercial customer classes that had been erroneously calculated. Absent K&F’s support to formally protest the matter, Community Power customers may have faced incorrectly calculated PCIA rates, resulting in some paying too much and others paying too little. • Restoring equitable access to incentive funds for CCA customers. Secured CPUC decision to change program rules that effectively barred CCA customers, particularly low-income customers, from accessing Self Generation Incentive Program (SGIP) incentives. This created a de facto requirement for customer to opt out of CCA service to qualify for SGIP incentives, undermining equity and program intent. K&F supported sustained advocacy through pleadings and ex parte meetings leading to a change in the program rules, restoring access to SGIP incentives for low-income CCA customers. • Enhancing bill transparency. Successfully argued for bill presentment enhancements in SDG&E’s 2024 General Rate Case Phase 2 proceeding (A.23-01-008) to provide greater transparency to PCIA rates applied to bundled customers and be more aligned with how the PCIA is presented on CCA customer bills.

K&F offers reasonable rates when compared with some of the other responses that were received as a result of the April 2023 RFP for the Original Agreement and put forth a reasonable budget for the two-year extension that was in line with staff expectations. K&F also offers additional services through EQ Research, a partner on the Agreement. EQ Research can 112
provide necessary services such as monitoring advice letters or summarizing CPUC decisions at lower non-attorney rates.

Extending the current agreement by two years, as contemplated by the Original Agreement, will allow Community Power to continue important ongoing work – uninterrupted – on behalf of Community Power’s customers and operational teams. Exercising the two-year extension will avoid a lengthy RFP process and disruption in valuable regulatory and CPUC-related involvement.

The agreement with K&F contemplates joint representation, as appropriate, with the Clean Energy Alliance. This joint advocacy brings scale and efficiency to litigation and advocacy at the CPUC. The Clean Energy Alliance Board approved a contract extension with K&F on March 26, 2026.

Fiscal Impact
The total NTE of the two-year renewal is $1,200,000, with the financial impact to Community Power being $1,028,000. The two-year renewal contemplates two issues that influence the total NTE:

1. Inflation adjusted rates for attorney billing. The increased rates are up 11.5% on average across all attorneys since 2023. They predict smaller rate increases if inflation cools.

2. Increased hours due to increased engagement in new CPUC cases and increased workload on the PCIA generally. Specifically, Community Power staff has directed K&F to engage in four new CPUC dockets: SDG&E’s Demand Flex Rate Application 26-02- 001, SDG&E’s Smart Meter 2.0 Application 25-02-001, SDG&E’s 2028-2035 Energy Efficiency Rolling Portfolio Business Plan Application 26-03-012, and SDG&E’s Palomar Decarbonization Project Application. Additionally, SDG&E files a General Rate Case (GRC) every three years, with their next cycle beginning in two years. GRC’s are time intensive, substantive proceedings at the CPUC. Additionally, the CPUC can, and does, regularly open new proceedings that require additional engagement beyond the scope of work that is active today.

The NTE reflects K&F’s absorption of legal work on behalf of SDREN that is valued at $172,000. It is cost recoverable from the SDREN budget approved by the CPUC. The 2028- 2035 SDREN Business Plan Portfolio Application was filed on March 16, 2026. In late Q2/early Q3 2026, the CPUC is expected to initiate a proceeding which will determine whether to grant SDREN’s budget request to continue its programs for 2028-2031. Extensive litigation and party deliberation is expected in the coming year, for which K&F’s services will be integral.

One month of the extended contract would be covered by Community Power’s FY 26 budget, which concludes on June 30. As of February 2026, there was around $166,000 left under the 113
Original Agreement’s NTE in FY 26. There are sufficient funds from the Original Agreement to cover the first month of work – June 2026 – under the extended contract. The rest of the extended contract’s funding for FY 2027 will be included in the FY 2027 budget proposal that staff plans to bring to the Board in May.

K&F’s work is critical to achieving Community Power ratepayer savings. For example, the work completed by K&F that is outlined in the Analysis and Discussion section above has reduced PCIA costs to Community Power customers by $165.4 million, creating additional headroom for Community Power generation rates. Their continued work on Community Power’s behalf is essential to continuing to seek additional, future customer savings.

Strategic Plan
Extending Community Power’s agreement with K&F by two years is critical to Community Power’s Regulatory Advocacy, and supports the following strategic plan goals:
• Advocating for public policies that advance Community Power organizational priorities; • Educating and engaging policymakers to ensure policies are consistent with Community Power’s regulatory and legislative policy platform; • Advocating for regulatory outcomes and leveraging opportunities consistent with the policy platform, mission, vision, values, and needs;
• Ensuring high customer retention and satisfaction;
• Promoting fiscal stability; and
• Providing affordable clean energy and invest in the community to create an equitable and sustainable future for the San Diego region.

Attachments
A: New Two-Year Agreement
B: Original Agreement
114
ITEM 11

ATTACHMENT A
115

MUTUAL CONSENT TO RENEW AGREEMENT WITH KEYES & FOX LLP
WHEREAS, SAN DIEGO COMMUNITY POWER, an independent public agency (“Community Power”), and KEYES & FOX LLP entered into that certain agreement entitled

ENGAGEMENT LETTER AND JOINT REPRESENTATION AGREEMENT BETWEEN KEYES & FOX LLP AND SAN DIEGO COMMUNITY POWER, effective on June 1, 2023, hereinafter referred to as “Original Agreement”; and
WHEREAS, the Original Agreement includes an option to renew the Original Agreement upon mutual written consent through May of 2028.

WHEREAS, the Original Agreement states, as follows: “If the option to extend is elected, budgets for any extension will be determined at that time.” WHEREAS, Community Power and KEYES & FOX have determined it is in their mutual interest to exercise the option to renew the Original Agreement through mutual written consent through May 2028 (“Renewal”).

NOW, THEREFORE, FOR VALUABLE CONSIDERATION, THE PARTIES AGREE AS FOLLOWS:

1. The Original Agreement is hereby extended through May 31, 2028.

2. Unless otherwise agreed to in writing, Community Power will not be obligated for fees in excess of one million two hundred thousand dollars ($1,200,000) between June 1, 2026 and May 31, 2028.

3. This Renewal shall be effective on June 1, 2026.

4. Except as expressly modified herein, all of the provisions of the Original Agreement shall remain in full force and effect. In the case of any inconsistencies between the Original Agreement and this Renewal, the terms of this Renewal shall control.

5. This Renewal may be executed in counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

IN WITNESS WHEREOF, the parties have caused this Renewal to be executed as of the dates set forth besides their signatures below.

CONSULTANT NAME

KEYES & FOX LLP
By: __________________________
Name: Tim Lindl
Title: Partner
Date: __________________________

SAN DIEGO COMMUNITY POWER
A Joint Powers Authority
By: ___________________________
Name: Karin Burns
Title: Chief Executive Officer
Date: __________________________
116
ITEM 11

ATTACHMENT B
117
118
119
120
121
122
123
124

SAN DIEGO COMMUNITY POWER
Staff Report – Item 12
To: Board of Directors
From: Jack Clark, Chief Operating Officer
Jen Lebron, Senior Director of Public Affairs
Xiomalys Crespo, Senior Community Engagement Manager
Via: Karin Burns, Chief Executive Officer
Subject: Consider and Approve Appointment of Molly Hintlian to the Community Advisory Committee to Fill City of Encinitas Vacancy
Date: April 23, 2026
Recommendation
Consider and approve appointment of Molly Hintlian to the Community Advisory Committee (CAC) to fill the City of Encinitas vacancy.

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 the Authority. The Community Advisory Committee is advisory only, and shall not have decision-making authority, nor receive any delegation of authority from the Board of Directors. Each Party may nominate a committee member(s) and the Board shall determine the final selection of committee members, who should represent a diverse cross-section of interests, skills set, and geographic regions.

Analysis and Discussion
Community Power staff announced a vacancy for the City of Encinitas at the June 12, 2025, CAC regular meeting, and the June 26, 2026, Board of Directors meeting; at the latter, outgoing 125
member Gary Jahns was recognized for his service in the CAC since before Community Power began servicing Encinitas residents.

Staff worked with Director San Antonio to review the incoming application, resume, and qualifications of Molly Hintlian, advancing her nomination. Molly brings over ten years of experience in strategic marketing and communications and advising nonprofits, small businesses, and community-based organizations. She graduated from the Encinitas Citizens Academy in 2025 and is an active participant of the Community Emergency Response Team.

If approved by the Board with a simple majority vote, staff will work with the representative to conduct their oath of office and onboarding prior to the next CAC meeting on June 11, 2026.

Staff will also update the Community Power website to include the new representative.

There is one additional CAC vacancy for the City of Imperial Beach. Staff continue to promote vacancies through Community Power’s social media channels and the CAC, as well as directly engaging with staff, advocacy organizations, and the general public during networking and tabling events in all our member agencies.

Fiscal Impact
N/A
Strategic Plan
This item supports Community Power’s Public Affairs strategic goals by establishing Community Power as a trusted public agency that collaborates and engages with local stakeholders, and increasing brand awareness through outreach, education, and strategic communications to help customers understand their energy usage, save money, and utilize customer offerings.

Attachment
N/A
126

SAN DIEGO COMMUNITY POWER
Staff Report – Item 13
To: Board of Directors
From: Gordon Samuel, Chief Commercial Officer
Kenny Key, Director of Power Contracts
Via:

Subject:

Karin Burns, Chief Executive Officer
Approve Ten-Year Agreements with the City of San José to Sell MTR Eligible Resource Adequacy and Buy System Resource Adequacy for a total net notional of $4,500,000
Date: April 23, 2026
Recommendation
Approve ten-year agreements with the City of San José as follows:
a. Sell MTR Eligible Resource Adequacy for a total of $43,200,000 and authorize the Chief Executive Officer to execute the agreement.
b. Buy System Resource Adequacy for a total of $47,700,000 and authorize the Chief Executive Officer to execute the agreement.

Background
As San Diego Community Power (Community Power) strives to meet its environmental, financial, and regulatory compliance goals and requirements, long-term resource adequacy agreements of at least ten years in duration are integral components of its energy supply portfolio. Long-term agreements are required to meet state compliance mandates such as D.21-06-025 (“MTR”), the California Public Utilities Commission (CPUC) decision that required each Load Serving Entity (LSE) in California to make long-term purchase commitments for resource adequacy from new, incremental generation facilities.

Community Power’s Board has approved several long-term contracts since 2021 to allow Community Power to meet its MTR requirements to date. In fact, Community Power has enough volume contracted to have excess MTR volume for 2027 and 2028. 127
In 2025, other CCAs, including the City of San José, reached out to Community Power to determine if there was a viable contract pathway for Community Power to sell its MTR length to help them meet their compliance needs. Community Power evaluated its current portfolio and identified a project that suits the needs of the City of San José.

Analysis and Discussion
Staff negotiated the attached buy and sell agreements for the (1) sell of 30 MW of MTR resource adequacy from a new build facility under contract with Community Power and (2) the purchase of 30 MW of 24/7 resource adequacy that is under contract with the City of San Jose.

Below is additional information regarding the agreements:

Sell Overview:
• Start deliveries in June 2027
• Contract term: 10 years
• Notional Value: $4,320,000 a year, $43,200,000 total
• Resource Adequacy Type: 4-hour battery
• Pricing: fixed for 10 years
• Community Power is protected from damages for failure to deliver the contracted quantity due to mutual volume reduction clause should either party not deliver Buy Overview:
• Start deliveries in June 2027
• Contract term: 10 years
• Notional Value: $4,770,000 a year, $47,700,000 total
• Resource Adequacy Type: 24/7
• Pricing: fixed for 10 years
• Community Power is protected from damages for failure to deliver the contracted quantity due to mutual volume reduction clause should either party not deliver Community Power Benefits:
• Since Community Power has MTR length in 2027 and 2028, this transaction allows Community Power to sell a 4-hour resource adequacy product for a 24-hour resource adequacy product. In the new slice of day resource adequacy framework, this allows Community Power to better fill its open positions and reduce costs for ratepayers. 128
Fiscal Impact
The fixed cost of the agreements, with a slight premium for Community Power to receive 24- hour resource adequacy, reduced compliance risk and should lower the cost of meeting the slice of day resource adequacy requirements.

Strategic Plan
This activity supports the strategic plan section on “Energy Portfolio Development” a goal to provide sufficient, reasonably priced, clean electricity to our customers. Tactics to achieve this goal include:
• Prudently manage the power portfolio to minimize risk and customer costs Attachments
A: WSPP Resource Adequacy Confirmation, SDCP sells to SJCE (redacted) B: WSPP Resource Adequacy Confirmation, SJCE sells to SDCP (redacted) 129
ITEM 13

ATTACHMENT A
130

WSPP RESOURCE ADEQUACY CONFIRMATION
This Confirmation confirms the transaction between San Diego Community Power, a California joint powers authority (“Purchaser”) and City of San José, a California municipal corporation (“Seller”), and each individually a “Party” and together the “Parties”, dated as of the last dated signature on the signature page hereto (the “Effective Date”), by which Seller agrees to sell and deliver, and Purchaser agrees to purchase and receive, the Product (the “Transaction”). This Transaction is governed by the WSPP Agreement dated October 31, 2025 (the “WSPP Agreement”). The WSPP Agreement and this Confirmation, including any applicable appendices, exhibits or amendments thereto, shall be collectively referred to herein as the “Agreement” and will constitute a single agreement between the Parties with respect to the Transaction. Capitalized terms not otherwise defined in this Confirmation or the WSPP Agreement are defined in the Tariff.

This Confirmation is being executed concurrently with a separate transaction between the Parties for Contingent Firm RA Product as of the same Effective Date, in which San Diego Community Power is Seller and City of San José is Purchaser (the “Related Confirmation”).

ARTICLE 1

TRANSACTION TERMS
Product, Delivery Period, Contract Quantity, Contract Quantity Availability Hours, Contract Price and other specifics of the Product are in Appendix B. Appendices A, B, C, and D are incorporated into this Confirmation.
☐ Firm RA Product:

Seller shall provide Purchaser with the Product from the Unit in the amount of the Contract Quantity. If the Unit is not available to provide the full amount of the Contract Quantity for any reason, then Seller shall have the option to supply Alternate Capacity pursuant to Section 2.3 to fulfill the remainder of the Contract Quantity during such period. If Seller fails to provide Purchaser with the Contract Quantity and has failed to supply Alternate Capacity to fulfill the remainder of the Contract Quantity during such period, then Seller shall be liable for damages and/or required to indemnify Purchaser for penalties or fines pursuant to the terms of Section 2.5. ☒ Contingent Firm RA Product:

Seller shall provide Purchaser with Product from the Unit in the amount of the Contract Quantity.

If the Unit is not available to provide the full amount of the Contract Quantity as a result of any reduction of the Contract Quantity from the Unit in accordance with Section 2.2, Seller shall have the option to notify Purchaser that either (a) Seller will not provide the portion of the Contract Quantity attributable to such reduction during the period of such non-availability; or (b) Seller will supply Alternate Capacity to fulfill all or a portion of the affected Contract Quantity during such period pursuant to Section 2.3. If the Unit is not available to provide the full amount of the Contract Quantity as a result of any reason other than as provided in Section 2.2, then Seller shall have the option to supply Alternate Capacity pursuant to Section 2.3 to fulfill all or a portion of the affected Contract Quantity during such period. If Seller fails to provide Purchaser with the Expected Contract Quantity from the Unit during any Showing Month and has failed to supply Alternate 131
Capacity to fulfill the remainder of the Expected Contract Quantity during such period, then Seller shall be liable for damages and/or required to indemnify Purchaser for penalties or fines pursuant to the terms of Section 2.5.

ARTICLE 2

DELIVERY OBLIGATIONS AND ADJUSTMENTS

2.1 Sale and Delivery of Product
(a) For each Showing Month of the Delivery Period, Seller shall sell and deliver to Purchaser, and Purchaser shall purchase and receive from Seller, the Expected Contract Quantity of the Product from the Shown Unit(s). Seller’s obligation to deliver the Expected Contract Quantity of Product for the Delivery Period is firm and will not be excused for any reason.
(b) Seller shall deliver the Expected Contract Quantity by submitting or causing to be submitted to CAISO Seller’s Supply Plans, identifying in each case the Shown Unit(s) and the characteristics of the Shown Unit(s) and Product for the relevant period, as further specified in Appendix B, all in compliance with this Confirmation.
(c) Seller shall cause all Supply Plans to meet and be filed in conformance with the requirements of the CPUC and the Tariff. Seller shall submit, or cause the Shown Unit’s SC to submit, (i) monthly Supply Plans and (ii) annual Supply Plans if the Effective Date is prior to the year-ahead Compliance Showing Deadline applicable for the Showing Months specified in Appendix B, in accordance with the Tariff and CPUC requirements and no later than the initial Compliance Showing Deadline for such Showing Month, identifying and confirming the transfer of the Expected Contract Quantity of Product to Purchaser for each Showing Month. The total amount of Product identified and confirmed for such Showing Month shall equal the Expected Contract Quantity, including a request for Hold-Back Capacity pursuant to Article Five of this Confirmation.
(d) Seller shall sell and deliver Product from a Shown Unit that meets the requirements set forth in Appendix B. In no event shall a Shown Unit utilize coal or coal materials as a source of fuel or be a nuclear generating facility. A Shown Unit must be a specific resource that is connected directly to the CAISO controlled grid or be under the operational control of CAISO. A Shown Unit may not be an unspecified import.

Seller shall identify the Shown Unit(s) and Expected Contract Quantity by providing Purchaser with the specific information contemplated in Appendix B no later than the Notification Deadline for the relevant Showing Month. (e) If CAISO rejects either the Supply Plan or the Resource Adequacy Plan with respect to any part of the Expected Contract Quantity for the Shown Unit(s) in any Showing Month, the Parties shall confer, make such corrections as are necessary for acceptance, and resubmit the corrected Supply Plan or Resource Adequacy Plan for validation before the applicable deadline for the Showing Month. 132
(f) The Product is delivered and received when the CIRA Tool shows that the Supply Plan submitted in compliance with Purchaser’s instructions, including Purchaser’s request, if any, for Hold-Back Capacity in accordance with Article 5, has been accepted for the Product from the Shown Unit by CAISO. Seller has failed to deliver the Product if (i) Purchaser has elected to submit the Product from the Shown Unit in its Resource Adequacy Plan and such submission is accepted by the CPUC and the CAISO, but the Supply Plan and Resource Adequacy Plan are not matched in the CIRA Tool and are rejected by CAISO notwithstanding performance of Section 2.1(e), or (ii) Seller fails to submit the volume of Expected Contract Quantity for any Showing Month in such amount as instructed by Purchaser for the applicable Showing Month. Seller will not have failed to deliver the Expected Contract Quantity if Purchaser fails or chooses not to submit the Shown Unit(s) and the Product in its Resource Adequacy Plan with the CPUC or CAISO.
(g) The Shown Unit(s) must not have characteristics that would trigger the need for Purchaser or Seller to file an advice letter or other request for authorization with the CPUC or for Purchaser to make a compliance filing pursuant to California Public Utilities Code Section 380.

2.2 Reductions in Contract Quantity
(a) If Seller is providing Contingent Firm RA Product, Seller’s obligation to deliver the Contract Quantity for each Showing Month may be reduced at Seller’s option by the amount of any Planned Outages which exist with respectto any portion of the Unit generating capacity during the applicable Showing Month; provided, (i) Seller notifies Purchaser by the Notification Deadline applicable to that Showing Month of the amount of Product from the Unit that Purchaser may include in Purchaser’s Compliance Showings applicable to that month as a result of such Planned Outage, and (ii) such reduction is able to be reflected on the Supply Plansinaccordance with the Tariff.
(b) If Seller is providing Contingent Firm RA Product, Seller’s obligation to deliver the Contract Quantity for any Showing Month may be reduced at Seller’s option if the Unit experiences a reduction in Unit NQC as determined by the CAISO or a reduction in the SOD NQC as determined by the CPUC; provided, (i) Seller notifies Purchaser by the Notification Deadline applicable to that Showing Month of the amount of Product from the Unit that Purchaser may include in Purchaser’s Compliance Showings applicable to that month as a result of reduction in Unit NQC as determined by the CAISO or a reduction in the SOD NQC as determined by the CPUC, and (ii) such reduction is able to be reflected on the Supply Plans in accordance with the Tariff. Seller’s potential reduction in Contract Quantity for each remaining Showing Month shall equal the product of (i) the applicable Showing Month Contract Quantity and (ii) the total amount (in MW) Unit NQC or SOD NQC (as applicable) that was reduced since the Effective Date, divided by (iii) Unit NQC or SOD NQC (as applicable) as of the Effective Date. 133
(c) In the event Seller is unable to provide the Contract Quantity for any portion of a Showing Month because of a Planned Outage of a Unit or reduction in Unit NQC or SOD NQC, Seller has the option, but not the obligation, to provide Product for such portions of such Showing Month from Replacement Units, provided Seller provides and identifiessuch Replacement Unitsin accordance with Section 2.3. (d) If Seller is providing Contingent Firm RA Product, Seller’s obligation to deliver the applicable Contract Quantity for any Showing Month may also be reduced by Seller if the Unit NQC and/or SOD NQC of the Unit is less than the Expected Unit NQC and/or Expected SOD NQC, as applicable, identified in Appendix B, or if the Unit has not obtained a Unit NQC and/or SOD NQC for the relevant Showing Month. If the Unit experiences such a reduction in or lack of Unit NQC and/or SOD NQC, and provided that any such reduction is beyond Seller’s reasonable control, then Seller has the option to reduce the Contract Quantity to the available Unit NQC or SOD NQC, if any, for the relevant Showing Month by providing written notice to Purchaser no later than the Notification Deadline for such Showing Month. For the avoidance of doubt, Seller may reduce the Contract Quantity to zero, provided that such reduction matches the available Unit NQC and SOD NQC and otherwise is consistent with this Section 2.2(d).
(e) ☒ If checked, the following provision and related definitions are applicable.

Seller’s obligation to deliver the Contract Quantity for each day of each Showing Month may also be reduced at Seller’s option in the event Purchaser does not deliver, for any reason, the contract quantity of product set forth in Appendix B of the Related Confirmation (such option, the “Related Reduction Option”); provided, however, that (i) Seller’s obligation to deliver the Contract Quantity of Product may not be reduced by an amount greater than the contract quantity of product that Purchaser does not deliver under the Related Confirmation and (ii) that the Related Reduction Option is subject to Seller providing written notice to Purchaser of such modification no later than five (5) Business Days before the initial Compliance Showing Deadline for such Showing Month. Seller’s rights under the Related Reduction Option are cumulative and in addition to Seller’s rights under the Related Confirmation.

2.3 Seller’s Option to Provide Alternate Capacity
If Seller is unable to provide the full Contract Quantity for a Showing Month for any reason, including, without limitation, a reduction in Unit NQC or SOD NQC, or as provided in Section

2.2, or Seller desires to provide some or all of the Contract Quantity for any Showing Month from a different generating unit other than the Unit, then Seller may, at no cost to Purchaser, provide Purchaser with replacement Product from one or more Replacement Units in an amount such that the total amount of Product provided to Purchaser from the Unit and any Replacement Unit(s) for each Showing Month is not more than the Contract Quantity, provided that in each case:
(a) Seller shall notify Purchaser in writing of its intent to provide Alternate Capacity and shall identify the proposed Replacement Units from which such Alternate Capacity 134
shall be provided no later than the Notification Deadline for Purchaser’s Compliance Showings related to such Showing Month;
(b) The proposed Replacement Units must (i) be accepted by the CAISO, and (ii) otherwise satisfy the requirements of this Agreement;
(c) Seller shall cause the Unit’s SC to submit a Supply Plan that includes the Replacement Units for each applicable Showing Month and, if applicable, annual filing, no later than the Compliance Showing Deadline for Purchaser’s Compliance Showings; and
(d) If Seller does not comply with the requirements of Sections 2.3(a), (b) and (c) for the applicable Showing Month and, if applicable, annual filing, then any such Replacement Units shall not be deemed a Replacement Unit for purposes of this Confirmation for that Showing Month and Seller shall not receive payment for such Product.

Subject to the satisfaction of the conditions contained in subsections (a) – (c) of this Section 2.3, once Seller has identified in writing any Replacement Units that meetthe requirements of this Section 2.3, then any such Replacement Units shall be deemed a Unit for purposes of this Confirmation for that Showing Month.

2.4 Planned Outages
As of the Effective Date, Seller and Purchaser have agreed to all Planned Outages as specified in Appendix D (“Planned Outage Schedule”) for all relevant Showing Months for the first (1st) calendar year, and at least fifty (50) days prior to each successive calendar year, Seller shall provide an updated Appendix D which sets forth the Planned Outages for such year. Seller may provide Purchaser with proposed changes to the Planned Outage Schedule from time to time.

Within ten (10) Business Days after Purchaser’s receipt of any Seller proposed changes, Purchaser shall notify Seller in writing of any reasonable requests for modifications to such Seller proposed changes, and Seller shall, to the extent consistent with Prudent Operating Practice, accommodate Purchaser’s requests regarding the timing of any Seller proposed changes to the Planned Outage Schedule.

2.5 Purchaser’s Remedies for Seller’s Failure to Deliver Expected Contract Quantity (a) If Seller fails to deliver any part of the Expected Contract Quantity as required herein for any Showing Month, Seller shall be liable for damages pursuant to Section 21.3 of the WSPP Agreement, without reference to the word “hourly” therein.
(b) Seller shall indemnify, defend and hold harmless Purchaser from any penalties, fines or costs, assessed against Purchaser by the CPUC, CAISO or other Governmental Body resulting from Seller’s failure to deliver the Product or a Shown Unit’s SC’s failure to timely or accurately submit Supply Plans in accordance with the Tariff and this Confirmation. The Parties shall use commercially reasonable efforts to minimize such penalties, fines or costs; 135
provided, that in no event will Purchaser be required to use or change its utilization of its owned or controlled assets or market positions to minimize these penalties, fines or costs.
(c) If Seller fails to pay the foregoing damages, penalties, fines or costs, or fails to reimburse Purchaser for those damages, penalties, fines or costs, then, without prejudice to its other rights and remedies, Purchaser may setoff and recoup those damages, penalties, fines or costs against any future amounts it may owe to Seller under this Confirmation or the WSPP Agreement.

2.6 Purchaser’s Re-Sale of Product
(a) Purchaser may re-sell all or part of the Product; provided that any such re-sale must not increase Seller’s obligations hereunder other than as set forth in this Section

2.6(a). For any such a resale, the Resource Adequacy Plan of Purchaser as used herein will refer to the Resource Adequacy Plan of Subsequent Purchaser. Seller shall, or shall cause the Shown Unit’s SC, to follow Purchaser’s instructions with respect to providing such resold Product to Subsequent Purchasers, to the extent such instructions are consistent with Seller’s obligations under this Confirmation.

Seller shall, and shall cause the Shown Unit’s SC, to take all commercially reasonable actions and execute all documents or instruments reasonably necessary to allow such Subsequent Purchasers to use such resold Product in a manner consistent with Purchaser’s rights under this Confirmation. If Purchaser incurs any liability to a Subsequent Purchaser due to the failure of Seller or the Shown Unit’s SC to comply with this Confirmation, Seller will be liable to Purchaser for the amounts Seller would have owed Purchaser under this Confirmation if Purchaser had not resold the Product.
(b) Purchaser shall notify Seller in writing of any resale of Product and the Subsequent Purchaser no later than three (3) Business Days before the Compliance Showing Deadline for each Showing Month for which Purchaser has resold the Product. (c) If CAISO or CPUC develops a centralized capacity market, Purchaser will have exclusive rights to offer, bid, or otherwise submit, or if necessary to direct the Seller or the Unit’s SC to offer, bid, or otherwise submit the Expected Contract Quantity of Product for each Showing Month for re-sale into such market, and Seller and the Unit’s SC shall comply with the Purchaser’s direction and Purchaser shall retain and receive all revenues from such re-sale.

ARTICLE 3

PAYMENTS

3.1 Payment
Purchaser shall make a monthly payment to Seller for the Product by the later of (i) ten (10) calendar days after Purchaser’s receipt of Seller’s invoice and (ii) the twentieth (20th) day of the Showing Month, and if such day is not a Business Day, the next following Business Day (“Monthly RA Capacity Payment”). The Monthly RA Capacity Payment shall equal the product of (a) the 136
applicable Contract Price for that Showing Month, (b) the Expected Contract Quantity for the Showing Month and (c) 1,000, rounded to the nearest penny (i.e., two decimal places); provided, however, that the Monthly RA Capacity Payment shall be adjusted to reflect any portion of Expected Contract Quantity for the Showing Month that was not delivered in accordance with Section 2.1 for such Showing Month.

3.2 Allocation of Other Payments and Costs
(a) Seller will receive any revenues from, and must pay all costs charged by, CAISO or any other third party with respect to the Shown Unit(s) for (i) start-up, shutdown, and minimum load costs, (ii) capacity for ancillary services, (iii) energy sales, (iv) flexible ramping product, or (v) black start or reactive power services. Purchaser must promptly report receipt of any such revenues to Seller. Purchaser must pay to Seller any such amounts described in this Section 3.2(a) received by Purchaser or a Subsequent Purchaser. Without prejudice to its other rights and remedies, Seller may setoff and recoup any such amounts that are not paid to it pursuant to this Section 3.2(a) against any amounts owed to Purchaser under the WSPP Agreement. (b) Any Availability Incentive Payments or Non-Availability Charges are for Seller to receive and pay.

ARTICLE 4

OTHER PURCHASER AND SELLER COVENANTS

4.1 CAISO Requirements
Seller shall schedule or cause the Shown Unit’s SC to schedule or make available to CAISO the Expected Contract Quantity of the Product during the Delivery Period, in compliance with the Tariff, and perform all, or cause the Shown Unit’s SC, owner, or operator to perform all, obligations under applicable law and the Tariff relating to the Product. Purchaser is not liable for, and Seller shall indemnify and hold Purchaser harmless from, the failure of Seller or the Shown Unit’s SC, owner, or operator to comply with the Tariff, and for any penalties, fines or costs imposed on Seller or the Shown Unit’s SC, owner, or operator for noncompliance.

4.2 Seller’s and Purchaser’s Duties to Take Actions to Allow Product Utilization Throughout the Delivery Period, Purchaser and Seller shall take all commercially reasonable actions and execute all documents or instruments reasonably necessary to ensure (a) Purchaser’s rights to the Expected Contract Quantity for the sole benefit of Purchaser or any Subsequent Purchaser and (b) that Purchaser may use the Expected Contract Quantity to meet its Compliance Obligations. Such commercially reasonable actions shall include, without limitation cooperating with and providing, and causing each Shown Unit’s SC, owner, or operator to cooperate with and provide, requested supporting documentation to the CAISO, the CPUC, or any other Governmental Body responsible for administering the applicable Compliance Obligations, including to demonstrate that the Expected Contract Quantity satisfies the Slice of Day Requirements and can be delivered to the CAISO controlled grid for the minimum hours required to satisfy the 137
Compliance Obligations, as applicable, pursuant to the “deliverability” standards established by the CAISO or other Governmental Body of competent jurisdiction.

If necessary, the Parties further agree to negotiate in good faith to amend this Confirmation to conform this Transaction to subsequent clarifications, revisions, or decisions rendered by CAISO or an applicable Governmental Body to maintain the benefits of the Transaction.

4.3 Seller’s Representations and Warranties
Seller represents and warrants to Purchaser throughout the Delivery Period that:
(a) Seller owns or has the exclusive right to the Product sold under this Confirmation from the Unit, and shall furnish Purchaser, CAISO, CPUC or other Governmental Authority with such evidence as may reasonably be requested to demonstrate such ownership or exclusive right;
(b) Seller shall comply with all applicable laws relating to the Product; (c) The resource attributes and capabilities associated with the Contract Quantity are and shall remain bundled across the applicable Showing Month and Seller has not and will not sell separate hourly products associated with the Contract Quantity; (d) No part of the Contract Quantity during the Delivery Period has been committed by Seller to any third party to satisfy Compliance Obligations or analogous obligations in any CAISO or non-CAISO markets;
(e) The Shown Unit(s) qualify to provide the Product under the Tariff, and the Shown Unit(s) and Seller are capable of delivering the Product; (f) The aggregation of all amounts of Capacity Attributes that Seller has sold, assigned, or transferred for the Shown Unit(s) during the Delivery Period does not exceed the Shown Unit’s Net Qualifying Capacity and, if applicable, the Effective Flexible Capacity for that Shown Unit, or the SOD NQC;
(g) If applicable, Seller has notified either the Shown Unit’s SC or the entity from which Seller purchased the Product that Seller has transferred the Contract Quantity of Product for the Delivery Period to Purchaser; and
(h) Seller has notified or will notify the Shown Unit’s SC that Purchaser is entitled to the revenues set forth in Section 3.2(b), and such Shown Unit’s SC is obligated to promptly deliver those revenues to Purchaser, along with appropriate documentation supporting the amount of those revenues.

4.4 Market Based Rate Authority
Upon Purchaser’s written request, Seller shall, in accordance with FERC Order No. 697, submit a letter of concurrence in support of any affirmative statement by Purchaser that this contractual arrangement does not transfer “ownership or control of generation capacity” from Seller to 138
Purchaser as the term “ownership or control of generation capacity” is used in 18 CFR Section

35.42. Seller shall not, in filings, if any, made subject to Order Nos. 652 and 697, claim that this contractual arrangement conveys ownership or control of generation capacity from Seller to Purchaser.

ARTICLE 5

HOLD-BACK AND SUBSTITUTE CAPACITY
No later than three (3) Business Days before the relevant Compliance Showing Deadline applicable to that Showing Month, Purchaser may request in writing that Seller not list, or cause the Unit’s Scheduling Coordinator not to list, in the Unit’s Supply Plan a portion or all of the Contract Quantity for any portion of such Showing Month (“Hold-Back Capacity”). Following Purchaser’s request for Hold-Back Capacity, Purchaser may request, in writing, that Seller make the previously requested Hold-Back Capacity available for Purchaser’s use as Substitute Capacity within the respective Showing Month. Such request shall be received by Seller no later than two (2) Business Days prior to the first day for which Purchaser seeks to use such Substitute Capacity.

The portion of the Contract Quantity that is the subject of Purchaser’s request for Hold-Back Capacity shall be deemed Contract Quantity delivered consistent with Section 2.1 for purposes of calculating a Monthly RA Capacity Payment pursuant to Section 3.1 and calculating any amounts due pursuant to Section 3.2. Seller shall, or shall cause the Unit’s Scheduling Coordinator to, comply with Purchaser’s request under this Article Five; provided that to the extent Seller is unable to provide the requested Substitute Capacity from the Unit due to a forced outage of the Unit, including as a result of a Force Majeure, the Hold-Back Capacity that is not able to be used by Purchaser as Substitute Capacity shall not be deemed Contract Quantity delivered consistent with Section 2.1 for purposes of calculating a Monthly RA Capacity Payment pursuant to Section 3.1.

ARTICLE 6
ADDITIONAL WSPP AGREEMENT AMENDMENTS; GENERAL PROVISIONS

6.1 Termination Payment
For this Transaction, the first sentence of Section 22.2(b) of the WSPP Agreement is deleted in its entirety and replaced with the following:
“If an Event of Default occurs, the Non-Defaulting Party shall possess the right to terminate this Confirmation and the Related Confirmation between the Parties under this Agreement upon written notice (by facsimile or other reasonable means) to the Defaulting Party, such notice of termination to be effective immediately upon receipt.” Additionally, for this Transaction, the following is inserted as a penultimate paragraph in Section

22.2(b) of the WSPP Agreement:
“If Purchaser is the Non-Defaulting Party and Purchaser reasonably expects to incur or be liable for any penalties, fines or costs from CAISO, or any Governmental Body, because Purchaser or a Subsequent Purchaser is not able to include the applicable Expected Contract Quantity in a Compliance Showing due to Seller’s Event of Default, then Purchaser may, in good faith, estimate the amount of those penalties, fines or costs and 139
include the estimate in its determination of the Termination Payment, subject to accounting to Seller when those penalties, fines or costs are finally ascertained. If this accounting establishes that Purchaser’s estimate exceeds the actual amount of penalties, fines or costs, Purchaser must promptly remit to Seller the excess amount with interest in accordance with Section 9.3 of the WSPP Agreement. The rights and obligations with respect to determining and paying any Termination Payment, and any dispute resolution provisions with respect thereto, survive the termination of this Transaction and continue until after those penalties, fines or costs are finally ascertained.”

6.2 Confidentiality
Notwithstanding Section 30.1 of the WSPP Agreement,
(a) The Parties may disclose information as necessary to (i) its officers, employees, agents, consultants, and contractors as necessary for the performance of its obligations under this Agreement (ii) as necessary to comply with any applicable law, regulation, rule, requirement, request, or order of a Governmental Body with jurisdiction, including the CAISO; (iii) a Shown Unit’s SC or as necessary for Supply Plan; and (iv) the independent evaluator or other administrator of any competitive solicitation process of Purchaser, which in turn may disclose such information as necessary to CAISO or any Governmental Body. In addition, Purchaser may disclose information as necessary to (i) the CAISO, the CPUC or a Governmental Body of competent jurisdiction, in order to support its Compliance Showings or otherwise show it has met its Compliance Obligations; and (ii) any Subsequent Purchaser.
(b) The Parties acknowledge that this Transaction, and all records related to its formation or performance, are subject to the California Public Records Act, (California Government Code section 7920.000 et. seq.), and that either Party may be required to make public this Confirmation (which may be partially redacted by a Party) in connection with the process of seeking approval from its board or commission for the execution of this Confirmation. Each Party acknowledges that the other Party may submit information to it that the other Party considers confidential, proprietary, or trade secret information pursuant the Uniform Trade Secrets Act (Cal. Civ. Code section 3426 et seq.), or otherwise protected from disclosure pursuant to an exemption to the California Public Records Act. (c) If a Party (“Disclosing Party”) contends that any information submitted to the other Party (“Receiving Party”) contains the Disclosing Party’s proprietary and confidential information which falls within one or more California Public Records Act exemptions, the Disclosing Party shall clearly mark such information “Proprietary and Confidential” and identify the specific lines containing such information. Upon request or demand of any third person or entity not a party to this Confirmation (“Requestor”) pursuant to the California Public Records Act for production, inspection and/or copying of this Confirmation or any information designated by the Disclosing Party as confidential, the Receiving Party as soon as practical shall notify the Disclosing Party that such request has been made, by 140
telephone call, letter sent via electronic mail, and/or by overnight carrier to the address, or email address listed at the end of this Confirmation. The Disclosing Party shall be solely responsible for taking whatever legal steps are necessary to protect information deemed by it to be confidential information and to prevent release of information to the Requestor by the Receiving Party. If the Disclosing Party takes no such action within ten (10) days, after receiving the foregoing notice from the Receiving Party, the Disclosing Party agrees that the Receiving Party may comply with the Requestor’s demand and is not required to defend against it.

Notwithstanding the foregoing, Receiving Party may release confidential information without notice to or over the objection of Disclosing Party if Receiving Party’s legal counsel advises Receiving Party that Receiving Party is required by law to release such confidential information.

6.3 Dodd-Frank Act
The Parties intend this Transaction to be a “customary commercial arrangement” as described in Section II.A.1 of Commodity Futures Trading Commission, Proposed Guidance, Certain Natural Gas and Electric Power Contracts, 81 Fed. Reg. 20583 at 20586 (Apr. 8, 2016) and a “Forward Capacity Transaction” within the meaning of Commodity Futures Trading Commission, Final Order in Response to a Petition From Certain Independent System Operators and Regional Transmission Organizations To Exempt Specified Transactions Authorized by a Tariff or Protocol Approved by the Federal Energy Regulatory Commission, 78 Fed. Reg. 19,880 (Apr. 2, 2013).

6.4 Change in Law
If any action by the CPUC, CAISO or any Governmental Body having jurisdiction, or any change in applicable law, occurring after the Effective Date results in (i) material changes to Purchaser’s or Seller’s obligations with regard to the Products sold hereunder, (ii) has the effect of changing the transfer and sale procedure set forth in this Confirmation so that the performance of this Confirmation becomes impracticable, or (iii) changes the Resource Adequacy Requirements such that the Product can no longer be counted towards Purchaser’s Resource Adequacy Requirements (a “Change in Law”), the Parties shall work in good faith to revise this Confirmation so that the Parties can perform their obligations regarding the purchase and sale of the Product sold hereunder in order to maintain the original intent.

6.5 Governing Law
Notwithstanding Section 24 of the WSPP Agreement, this Transaction and the rights and duties of the Parties hereunder shall be governed by and construed, enforced and performed in accordance with the laws of the state of California, without regard to principles of conflicts of law.

6.6 Collateral
Notwithstanding any provision in the WSPP Agreement to the contrary, including Section 27, neither Party shall be required to post collateral or other security for this Transaction.

6.7 No Recourse to Purchaser
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Purchaser is organized as a Joint Powers Authority in accordance with the Joint Exercise of Powers Act of the State of California (Government Code Section 6500, et seq.) and is a public entity separate from its constituent members. Purchaser will solely be responsible for all of its debts, obligations and liabilities accruing and arising out of this Confirmation. Seller will have no rights and shall not make any claims, take any actions or assert any remedies against any of Purchaser’s constituent members, or the officers, directors, advisors, contractors, consultants or employees of Purchaser or Purchaser’s constituent members, in connection with this Confirmation.

6.8 Designated Fund and Limited Obligations
(a) Designated Fund. Seller is a municipal corporation and is precluded under the California State Constitution and applicable law from entering into obligations that financially bind future governing bodies, and, therefore, nothing in the Agreement shall constitute an obligation of future legislative bodies of the City to appropriate funds for purposes of the Agreement; provided, however, that (i) Seller has created and set aside a designated fund (the “Designated Fund”) for payment of its obligations under the Agreement and (ii) subject to the requirements and limitations of applicable law and taking into account other available money specifically authorized by Seller and allocated and appropriated to the San José Clean Energy’s obligations, Seller agrees to establish San José Clean Energy rates and charges that are sufficient to maintain revenues in the Designated Fund necessary to pay its obligations under this Agreement and all of Seller’s payment obligations under its other contracts for the purchase of energy for San José Clean Energy. Seller shall provide Purchaser with reasonable access to account balance information with respect to the San José Clean Energy Designated Fund during the Term. (b) Limited Obligations. Seller’s payment obligations under the Agreement are special limited obligations of the Seller payable solely from the Designated Fund and are not a charge upon the revenues or general fund of the City of San José or upon any non- San José Clean Energy moneys or other property of the Community Energy Department or the City of San José.

6.9 City of San José Standard Provisions
a) Nondiscrimination/Non-Preference. Purchaser shall comply with all laws and agrees to not discriminate against or grant preferential treatment to any person on the basis of race, sex, color, age, religion, sexual orientation, actual or perceived gender identity, disability, ethnicity or national origin. This prohibition applies to recruiting, hiring, demotion, layoff, termination, compensation, fringe benefits, advancement, training, apprenticeship and other terms, conditions, or privileges of employment, subcontracting and purchasing. Purchaser will include in each subcontract entered into after the Effective Date of this Agreement these same obligations. This prohibition is not intended to preclude Purchaser from providing a reasonable accommodation to a person with a disability. b) Conflict of Interest. Purchaser represents that it is familiar with the local and state conflict of interest laws, and agrees to comply with those laws in performing this 142
Agreement. Purchaser certifies that, as of the Effective Date, it was unaware of any facts constituting a conflict of interest. Purchasershall avoid all conflicts of interest in performing this Agreement. Purchaser has the obligation of determining if the manner in which it performs any part of this Agreement results in a conflict of interest, and shall immediately notify the Seller in writing if it becomes aware of any facts giving rise to a conflict of interest. Seller’s violation of this subsection (b) is a material breach.
c) Gifts Prohibited. Chapter 12.08 of the San José Municipal Code prohibits a City of San José officer or designated employee from accepting any gift. Purchaser shall not offer any City of San José officer or designated employee any gift prohibited by Chapter 12.08.
d) Disqualification of Former Employees. Chapter 12.10 of the San José Municipal Code prohibits a former City of San José officer and former designated employee from providing services to the City of San José connected with his/her former duties or official responsibilities. Purchaser shall not use either directly or indirectly any officer, employee or agent to perform any services if doing so would violate Chapter 12.10.

6.10 Other WSPP Agreement Changes
For this Transaction, the WSPP Agreement shall be amended as follows:
(a) Section 9.4 is deleted in its entirety and replaced with the following:
“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, with notice of the objection given to the other Party.

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 due date to but excluding the date paid. Inadvertent overpayments shall be returned upon request or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Interest Rate from and including the date of such overpayment to but excluding the date repaid or deducted by the Party receiving such overpayment.

Any dispute with respect to an invoice is waived unless the other Party is notified in writing within twelve (12) months after the invoice is rendered or any specific adjustment to the invoice is made. If an invoice is not rendered within twelve (12) months after the close of the month during which performance of a Transaction occurred, the right to payment for such performance is waived.” (b) Section 22.1 is modified by inserting the following new text at the end thereof:
143
“(f) the failure of the Defaulting Party to pay its debts generally as they become due or the Defaulting Party’s admission in a writing that is unable to pay its debts generally as they become due;
(g) the institution, by the Defaulting Party, of a general assignment for the benefit of its creditors; or
(h) the application for, consent to, or acquiescence to, by the Defaulting Party, the appointment of a receiver, custodian, trustee, liquidator, or similar official for all or a substantial portion of its assets.”
(c) Section 22.2(b) is amended by inserting “and is continuing” after “Event of Default occurs” in the first line thereof and deleting the second sentence therein. (d) Section 22.3(c) is amended by deleting the third sentence thereof and replacing it with the following:
“If the Non-Defaulting Party’s aggregate Gains exceed its aggregate Losses and Costs after any set-off as set forth in Section 22.3(d) of the WSPP Agreement, if any, resulting from the termination of this Agreement or a Confirmation, the Termination Payment for all such Terminated Transactions shall be zero, notwithstanding any provision in this Section or Agreement to the contrary.” (e) Section 22.3(e) is deleted in its entirety and replaced with the following:
“[Intentionally omitted]”
(f) Section 22.3(f) is deleted in its entirety and replaced with the following:
“If the Defaulting Party disagrees with the calculation of the Termination Payment and the Parties cannot otherwise resolve their differences, and provided that the Defaulting Party has paid the undisputed part of the Termination Payment to the Non-Defaulting Party as provided under Section 22.3(c), and that any amounts disputed by the Defaulting Party are disputed in good faith, then the Defaulting Party may submit the calculation issue to dispute resolution pursuant to Section

34.”
(g) Section 28.1 is applicable and the Parties shall net monthly payments in accordance with Exhibit A of the WSPP. Both Parties intend for the netting provisions of Exhibit A to the WSPP Agreement to be effective on the Effective Date. (h) Section 30.1(4) is amended by inserting “or requested” after the word “required” and by adding the following at the end of the first sentence: “; or (8) to the Party’s and such Party’s affiliates’ lenders, counsel, accountants, advisors and agents who have a need to know such information and have agreed to keep such terms confidential”.
(i) Subsections 34.1 and 34.2 are deleted and replaced with the following:
144
“34.1 DISPUTE RESOLUTION

IN THE EVENT OF ANY DISPUTE ARISING UNDER THE AGREEMENT WITH RESPECT TO THIS TRANSACTION, WITHIN TEN (10) DAYS

FOLLOWING THE RECEIPT OF A WRITTEN 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 THIRTY (30) DAYS AFTER RECEIPT OF SUCH NOTICE, THEN

EITHER PARTY MAY SEEK ANY AND ALL REMEDIES AVAILABLE TO

IT AT LAW OR IN EQUITY, SUBJECT TO THE LIMITATIONS SET FORTH IN THE AGREEMENT.”
“34.2 EXCLUSIVE JURISDICTION

EACH PARTY SUBMITS TO THE EXCLUSIVE JURISDICTION OF THE

STATE OR FEDERAL COURTS LOCATED IN SAN DIEGO OR SANTA

CLARA, CALIFORNIA, FOR ANY ACTION OR PROCEEDING RELATING

TO THIS AGREEMENT OR ANY TRANSACTION, AND EXPRESSLY

WAIVES ANY OBJECTION IT MAY HAVE TO SUCH JURISDICTION OR THE CONVENIENCE OF SUCH FORUM.”
(j) In Section 34.4, the phrase “arbitration or” is deleted from the first line. (k) The following shall be inserted as a new Section 34.5:
“34.5 LIMITATION OF DAMAGES

EXCEPT AS OTHERWISE SPECIFIED IN ANY CONFIRMATION, FOR

BREACH OF ANY PROVISION OF THIS AGREEMENT FOR WHICH AN

EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, THE

EXPRESS REMEDY OR MEASURE OF DAMAGES PROVIDED IS THE SOLE

AND EXCLUSIVE REMEDY UNDER THIS AGREEMENT AND LIABILITY

FOR THE BREACH IS LIMITED AS SET FORTH IN THE PROVISION AND

ALL OTHER REMEDIES FOR DAMAGES AT LAW OR IN EQUITY ARE
WAIVED. EXCEPT AS OTHERWISE SPECIFIED IN ANY CONFIRMATION,

IF NO EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED IN

THIS AGREEMENT FOR A PARTICULAR BREACH, LIABILITY FOR THE

BREACH IS LIMITED TO DIRECT DAMAGES ONLY, THE DIRECT

DAMAGES ARE THE SOLE AND EXCLUSIVE REMEDY UNDER THIS

AGREEMENT FOR THE BREACH, AND ALL OTHER REMEDIES FOR
DAMAGES AT LAW OR IN EQUITY ARE WAIVED. EXCEPT AS

OTHERWISE SPECIFIED IN ANY CONFIRMATION, NEITHER PARTY IS

LIABLE FOR ANY OTHER TYPE OF DAMAGE, INCLUDING INCIDENTAL,

PUNITIVE, EXEMPLARY, CONSEQUENTIAL, SPECIAL OR INDIRECT

DAMAGES OF ANY NATURE (INCLUDING DAMAGES ASSOCIATED
145

WITH LOST PROFITS, BUSINESS INTERRUPTION AND LOSS OF

GOODWILL) ARISING AT ANY TIME, WHETHER IN TORT (INCLUDING

THE SOLE OR CONTRIBUTORY NEGLIGENCE OF EITHER PARTY OR

ANY RELATED PERSON), WARRANTY, STRICT LIABILITY, CONTRACT OR STATUTE, UNDER ANY INDEMNITY PROVISION, OR OTHERWISE.” (l) Section 37 is amended by inserting the following in the beginning thereof: “On the date of entering into this Confirmation,”.
(m) Section 41 “Witness” shall become Section 42 and the following “Standard of Review” Section shall be substituted in its place:
“The Parties agree as follows:

From the date of entering into a Transaction under this Agreement and throughout the term of such Transaction, the Parties each warrant and covenant as follows:

1. Absent the agreement of all Parties to the proposed change, the standard of review for changes to any section of this Agreement (including all Transactions and/or Confirmations) specifying the rate(s) or other material economic terms and conditions agreed to by the Parties herein, whether proposed by a Party, a non-party or FERC acting sua sponte, shall be the “public interest” 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)( the “Mobile-Sierra” doctrine) and clarified in 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 Pub. Util. Comm’n, 558 U.S. 165 (2010).

2. The Parties, for themselves and their successors and assigns, (i) agree that this “public interest” standard shall apply to any proposed changes in any other documents, instruments or other agreements executed or entered into by the Parties in connection with this Agreement and (ii) hereby expressly and irrevocably waive any rights they can or may have to the application of any other standard of review, including the “just and reasonable” standard.”

6.11 Counterparts
This Confirmation may be signed in any number of counterparts with the same effect as if the signatures to the counterparts were upon a single instrument. The Parties may rely on electronic, or scanned signatures as originals under this Confirmation. Delivery of an executed signature page of this Confirmation as a PDF attachment to an email shall be the same as delivery of a manually executed signature page.

6.12 Entire Agreement; No Oral Agreements or Modifications This Agreement sets forth the terms of the Transaction into which the Parties have entered and shall constitute the entire agreement between the Parties relating to the contemplated purchase and 146
sale of the Product. Notwithstanding any other provision of the Agreement, this Transaction may be confirmed only through a Documentary Writing executed by both Parties, and no amendment or modification to this Transaction shall be enforceable except through a Documentary Writing executed by both Parties.
[Signatures appear on the following page.]
147
AGREED AS OF THE EFFECTIVE DATE:

City of San José, a California municipal
corporation
San Diego Community Power, a
California joint powers authority
By:

Name:

Title:

Date:

Approved as to form:

By:

Name:

Title:

Date:

By:

Name:

Title:

Date:
148

APPENDIX A

DEFINED TERMS
“Alternate Capacity” means replacement Product which Seller has elected to provide to Purchaser from a Replacement Unit in accordance with the terms of Section 2.3. “CAISO” means the California ISO or the successor organization to the functions thereof. “Capacity Attributes” means attributes of the Shown Unit that may be counted toward Compliance Obligations, including: flexibility, dispatchability, physical location or point of electrical interconnection of the Shown Unit; Unit ability to generate at a given capacity level during a given period of time, provide ancillary services, or ramp up or down at a given rate; any current or future defined characteristics, certificates, tags, credits, or accounting constructs of the Shown Unit, howsoever entitled, identified from time to time by the CAISO or a Governmental Body having jurisdiction over Compliance Obligations.
“CIRA Tool” means the CAISO Customer Interface for Resource Adequacy. “Compliance Obligations” means, as applicable, RAR, Local RAR, FCR, and the Slice of Day Requirements.
“Compliance Showing” means the applicable LSE’s compliance plan with the resource adequacy requirements of the CPUC for an applicable Showing Month. “Compliance Showing Deadline” means, for each Showing Month, the Compliance Showing submission due date for such Showing Month. For illustrative purposes only, as of the Effective Date, the applicable Compliance Showing submission due dates are as follows: (A) forty-five (45) days prior to the Showing Month covered by the Supply Plan for the monthly Supply Plan; and (B) the last Business Day of October that is prior to commencement of the year for the annual Supply Plan, such dates may be modified by the CAISO from time to time throughout the Delivery Period.
“Contingent Firm RA Product” has the meaning set forth in Article 1 herein. “Contract Quantity” means the amount of capacity and/or energy to be supplied for a transaction under the Agreement.
“Contract Quantity Availability Hours” means the hours, in the amount set forth in Appendix B, that will be used in Purchaser’s compliance filings and which represent the hours the Shown Unit is available for production and satisfaction of the Shown Unit’s must-offer obligation. “CPUC” means the California Public Utilities Commission. “CPUC Decisions” means any currently effective or future decisions, resolutions, or rulings related to resource adequacy.
149
“CPUC Filing Guide” is the document issued annually by the CPUC which sets forth the guidelines, requirements and instructions for load serving entities to demonstrate compliance with the CPUC’s resource adequacy program, as such may be modified, amended, supplemented or updated from time to time.
“Delivery Period” has the meaning set forth in Appendix B, attached hereto. “Effective Flexible Capacity” has the meaning given in CAISO’s FERC-approved Tariff. “Expected Contract Quantity” means,with respect to any Showing Month of the Delivery Period, (a) for Firm RA Product, the Contract Quantity of Product, including the amount of Contract Quantity of Product that Seller has elected to provide Alternate Capacity, and (b) for Contingent Firm RA Product, the Contract Quantity of Product for such Showing Month, including the amount of Contract Quantity of Product that Seller has elected to provide Alternate Capacity, less any reductions to Contract Quantity consistent with Section 2.2 with respect to which Seller has not elected to provide Alternate Capacity.
“Expected Unit EFC” means the Effective Flexible Capacity the Unit is expected to provide as set forth in Appendix B.
“Expected Unit NQC” means the Net Qualifying Capacity the Unit is expected to provide as set forth in Appendix B.
“Expected SOD NQC” means the expected hourly Net Qualifying Capacity value of the Unit as set forth in Appendix B.
“FCR” means the flexible capacity requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or other Governmental Body having jurisdiction over Compliance Obligations and includes any non-binding advisory showing which an LSE is required to make with respect to flexible capacity. “FCR Attributes” means, with respect to a Shown Unit, any and all resource adequacy attributes of the Shown Unit, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction over Compliance Obligations, that can be counted toward an LSE’s FCR.
“Firm RA Product” has the meaning set forth in Article 1 herein. “Flexible Capacity Category” shall be as described in the annual CPUC Filing Guide, as such may be modified, amended, supplemented or updated from time to time. “Governmental Body” means any federal, state, local, municipal or other government; any governmental, regulatory or administrative agency, commission or other authority lawfully exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal. 150
“Incremental Capacity” means capacity that as of the Effective Date was not included in the CPUC’s 2019-2020 IRP RESOLVE/SERVM baseline generator list identified in CPUC Decision 21-06-035, and as subsequently updated by the CPUC.
“Interest Rate” means, for any date, the lesser of (a) the per annum rate of interest equal to the prime lending rate as may from time to time be published in The Wall Street Journal under “Money Rates” on such day (or if not published on such day on the most recent preceding day on which published), plus two percent (2%) and (b) the maximum rate permitted by applicable law. “Local RAR” means the local resource adequacy requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, by CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction over Compliance Obligations.
“Local RAR Attributes” means, with respect to a Shown Unit, any and all resource adequacy attributes of the Shown Unit, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction over Compliance Obligations, that can be counted toward an LSE’s Local RAR.
“LSE” means “Load Serving Entity” as such term is used in Section 40.9 of the Tariff. “MW” means megawatt.
“Net Qualifying Capacity” has the meaning given in CAISO’s FERC-approved Tariff. “Notification Deadline” is twelve (12) Business Days before the Compliance Showing Deadline. “Planned Outage” means, subject to and as further described in the CPUC Decisions, a CAISO-approved, planned or scheduled disconnection, separation or reduction in capacity of the Unit that is conducted for the purposes of carrying out routine repair or maintenance of such Unit, or for the purposes of new construction work for such Unit.
“Product” means RAR Attributes, Local RAR Attributes and FCR Attributes, each for the Delivery Period, Unit, Contract Quantity, Contract Price and other specifications contained in Appendix B. “Prorated Percentage of Unit Factor” means the percentage, as specified in Appendix B, of the Unit NQC as of the Effective Date that is dedicated to Purchaser under this Transaction. “Prorated Percentage of Unit Flexible Factor” means the percentage, as specified in Appendix B, of the Unit EFC as of the Effective Date that is dedicated to Purchaser under this Transaction. “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 power industry during the relevant time period 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 151
optimum practice, method or act to the exclusion of all others, but rather to acceptable practices, methods or acts generally accepted in the electric power industry in the Western United States. “RAR Attributes” means, with respect to a Shown Unit, any and all resource adequacy attributes of the Shown Unit, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction over Compliance Obligations, that can be counted toward an LSE’s RAR.
“Related Confirmation” has the meaning set forth in the preamble. “Replacement Unit” means a generating unit having the same Capacity Attributes as the Unit, including the Contract Quantity Availability Hours, RAR Attributes, and, as applicable, LAR Attributes, FCR Attributes, and Flexible Capacity Category, and otherwise meeting the requirements specified in Section 2.3 hereof, unless Purchaser consents in writing in its sole discretion to accept a Replacement Unit that does not have the same Capacity Attributes as the Unit. A Replacement Unit shall not utilize coal or coal materials as a source of fuel, must be a specific resource that is connected directly to the CAISO controlled grid, or be under the operational control of CAISO, and may not be an unspecified import. “Resource Adequacy Requirements” or “RAR” means the resource adequacy requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, by CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction over Compliance Obligations, including Slice of Day Requirements, but not including Local RAR or FCR. “Resource Category” shall be as described in the annual CPUC Filing Guide, as such may be modified, amended, supplemented or updated from time to time. “San José Clean Energy” means the City of San José’s community choice aggregation program.

The San José Energy Department administers and manages San José Clean Energy. “SC” means Scheduling Coordinator as defined in the Tariff. “Showing Month” means the calendar month of the Delivery Period that is the subject of the related Compliance Showing.
“Shown Unit” means the Unit, or any Replacement Unit meeting the requirements of Section 2.3 of this Confirmation and specified by Seller in a Supply Plan. “Slice of Day” or “SOD” means the CPUC’s 24-hour Slice-of-Day Framework established in D.22-06-050 and D.23-04-010 and D. 24-06-004, as may be modified by the CPUC from time to time.
“Slice of Day Requirements” means the Slice of Day framework, or any successor program thereof as may be established and modified by the CPUC from time to time. 152
“SOD NQC” means the lesser of the Expected SOD NQC and the hourly Net Qualifying Capacity value of the Unit as determined by the CPUC pursuant to the Slice of Day Requirements on a subsequent date of determination.
“Start Date” has the meaning set forth in Appendix B, attached hereto. “Subsequent Purchaser” means the purchaser of Product from Purchaser in a re-sale of Product by Purchaser.
“Substitute Capacity” has the meaning set forth in the Tariff for “RA Substitute Capacity”. “Tariff” means the CAISO Tariff, including any current CAISO-published “Operating Procedures” and “Business Practice Manuals,” in each case as amended or supplemented from time to time.
“Unit” means Unit 1 as described in Appendix B.
“Unit EFC” means the lesser of the Expected Unit EFC and Unit’s Effective Flexible Capacity on a subsequent date of determination.
“Unit NQC” means the lesser of the Expected Unit NQC and Unit’s Net Qualifying Capacity on a subsequent date of determination.
153

APPENDIX B

PRODUCT AND UNIT INFORMATION
Product:

RAR Local RAR Flexible Capacity
and all Capacity Attributes related to such Product.

Additional Product Information (fill in all that apply):

CAISO Zone: NP15
CPUC Local Area (if applicable): Stockton
Flexible Capacity Category (if applicable): 1
Delivery Period: The Delivery Period for this Agreement shall be ten (10) years and shall begin on the Start Date set forth in the Related Confirmation, subject to the Parties’ rights and obligations set forth therein.

Contract Quantity and Contract Price:

Showing
Month and
Year
RAR
Contract
Quantity (MW)
Flexible Capacity
Contract Quantity
(MW)
Contract
Quantity
Availability
Hours
Contract Price
($/kW-mo.)
Each Showing
Month of the
Delivery Period
HE 1-24
154
Unit 1
Additional information for battery and other storage resources:

Paired resource (yes/no)
If a paired resource, does it charge exclusively from the paired resource or is grid charging allowed?
Efficiency Rate
Co-located or hybrid resource
Interconnection limit (if part of co-located or hybrid resource) Number of cycles per day
Additional information for solar and wind resources:

Part of co-located or hybrid resource (yes/no)
For calculation of correct SOD hourly QC based on exceedance values:

Region
Solar type (tracking, fixed)
Interconnection limit (if part of co-located or hybrid resource) 155

APPENDIX C

NOTICE INFORMATION
San Diego Community Power City of San José
All Notices:
815 E Street, Suite 12716
San Diego, CA 92112
Attn: Jennine Camara, Director of Portfolio
Management
Phone: (619) 894-5608
Email: [email protected]
Duns: 117548142
Federal Tax ID Number: 85-0824464
All Notices:

San José Clean Energy
200 E. Santa Clara Street, San José, CA 95113
Attn: Deputy Director, Power Resources
Phone: (408) 535-4999
Email: [email protected]
Duns: 06-354-1874
Federal Tax ID Number: 94-6000419
with a copy to:

Office of the City Attorney
Attn. Deputy City Attorney, Energy Department
200 East Santa Clara Street, 16th Floor Tower
San Jose, CA 95113-1905
Direct: (408) 535-1900
Email: [email protected]
Invoices:

Attn: SDCP Settlements
Phone: (619) 732-0023
Email: [email protected]
Invoices:

Attn: Division Manager, Risk Management,
Contracts, & Administration
Phone: (408) 535-4999
Email: [email protected]
Scheduling:

Tenaska Power Services Co.

Attn: Kara Whillock
Phone: (972) 333-6122
Email: [email protected]
Day Ahead: (817) 303-1115
Real Time: (817) 303-1852
Facsimile: (817) 303-1104
Scheduling:

Attn: NCPA Pre-Scheduling Desk
Phone: 916-781-4227 or 916-781-4290
Email: [email protected]
Alternative:

Attn: NCPA Scheduling Coordination Desk
Phone: 916-781-4237 or 916-781-4280
Email: [email protected]
Wire Transfer:

Attn: Rosa Cucicea
VP – Clean Energy Division Manager
(415) 293-4201 Ph | (925) 323-6022 Cell |
(415) 293-4201 Fx
201 Mission St., Suite 1300 | San Francisco,
CA 94105
Wire Transfer:
156
Credit and Collections:

Attn: SDCP Finance
E-mail: [email protected]
Credit and Collections:

Attn: Division Manager, Budget & Financial
Planning
Phone: (408) 535-4999
Email: [email protected]
Defaults:
815 E Street, Suite 12716
San Diego, CA 92112
Attn: SDCP General Counsel
Email: [email protected]
Defaults:

Attn: Director of Finance
200 East Santa Clara Street Tower 13
San Jose, CA 95113
Phone: (408) 535-7011
Email: [email protected]
and an additional copy to:

Office of the City Attorney
Attn. Deputy City Attorney, Energy Department
200 East Santa Clara Street, 16th Floor Tower
San Jose, CA 95113-1905
Direct: (408) 535-1900
Email: [email protected]
157

APPENDIX D

PLANNED OUTAGE SCHEDULE
Unit Name CAISO
Resource ID *
Outage (MW) SLIC
Outage Start Date
SLIC
Outage End Date

N/A N/A N/A N/A N/A
158
ITEM 13

ATTACHMENT B
159

WSPP RESOURCE ADEQUACY CONFIRMATION
This Confirmation confirms the transaction between San Diego Community Power, a California joint powers authority (“Seller”) and City of San José, a California municipal corporation (“Purchaser”), and each individually a “Party” and together the “Parties”, dated as of the last dated signature on the signature page hereto (the “Effective Date”), by which Seller agrees to sell and deliver, and Purchaser agrees to purchase and receive, the Product (the “Transaction”). This Transaction is governed by the WSPP Agreement dated October 31, 2025 (the “WSPP Agreement”). The WSPP Agreement and this Confirmation, including any applicable appendices, exhibits or amendments thereto, shall be collectively referred to herein as the “Agreement” and will constitute a single agreement between the Parties with respect to the Transaction. Capitalized terms not otherwise defined in this Confirmation or the WSPP Agreement are defined in the Tariff.

This Confirmation is being executed concurrently with a separate transaction between the Parties for Contingent Firm RA Product as of the same Effective Date, in which San Diego Community Power is Purchaser and City of San José is Seller (the “Related Confirmation”).

ARTICLE 1

Seller shall provide Purchaser with Product from the Unit in the amount of the Contract Quantity.

If the Unit is not available to provide the full amount of the Contract Quantity as a result of any reduction of the Contract Quantity from the Unit in accordance with Section 2.2, Seller shall have the option to notify Purchaser that either (a) Seller will not provide the portion of the Contract Quantity attributable to such reduction during the period of such non-availability; or (b) Seller will supply Alternate Capacity to fulfill all or a portion of the affected Contract Quantity during such period pursuant to Section 2.3. If the Unit is not available to provide the full amount of the Contract Quantity as a result of any reason other than as provided in Section 2.2, then Seller shall have the option to supply Alternate Capacity pursuant to Section 2.3 to fulfill all or a portion of the affected Contract Quantity during such period. If Seller fails to provide Purchaser with the Expected Contract Quantity from the Unit during any Showing Month and has failed to supply Alternate 160
Capacity to fulfill the remainder of the Expected Contract Quantity during such period, then Seller shall be liable for damages and/or required to indemnify Purchaser for penalties or fines pursuant to the terms of Section 2.5.

ARTICLE 2

DELIVERY OBLIGATIONS AND ADJUSTMENTS

Seller shall identify the Shown Unit(s) and Expected Contract Quantity by providing Purchaser with the specific information contemplated in Appendix B no later than the Notification Deadline for the relevant Showing Month. (e) If CAISO rejects either the Supply Plan or the Resource Adequacy Plan with respect to any part of the Expected Contract Quantity for the Shown Unit(s) in any Showing Month, the Parties shall confer, make such corrections as are necessary for acceptance, and resubmit the corrected Supply Plan or Resource Adequacy Plan for validation before the applicable deadline for the Showing Month. 161
(f) The Product is delivered and received when the CIRA Tool shows that the Supply Plan submitted in compliance with Purchaser’s instructions, including Purchaser’s request, if any, for Hold-Back Capacity in accordance with Article 5, has been accepted for the Product from the Shown Unit by CAISO. Seller has failed to deliver the Product if (i) Purchaser has elected to submit the Product from the Shown Unit in its Resource Adequacy Plan and such submission is accepted by the CPUC and the CAISO, but the Supply Plan and Resource Adequacy Plan are not matched in the CIRA Tool and are rejected by CAISO notwithstanding performance of Section 2.1(e), or (ii) Seller fails to submit the volume of Expected Contract Quantity for any Showing Month in such amount as instructed by Purchaser for the applicable Showing Month. Seller will not have failed to deliver the Expected Contract Quantity if Purchaser fails or chooses not to submit the Shown Unit(s) and the Product in its Resource Adequacy Plan with the CPUC or CAISO.
(g) The Shown Unit(s) must not have characteristics that would trigger the need for Purchaser or Seller to file an advice letter or other request for authorization with the CPUC or for Purchaser to make a compliance filing pursuant to California Public Utilities Code Section 380.
(h) Seller acknowledges that Purchaser intends to use this Agreement to comply with Purchaser’s Mid-Term Reliability obligations, and Seller agrees to reasonably cooperate with Purchaser to ensure that Purchaser can use the Product to meet the requirements of Mid-Term Reliability; provided, that, Seller makes no representation or warranty that the Product shall meet such requirements.

2.2 Reductions in Contract Quantity
(a) If Seller is providing Contingent Firm RA Product, Seller’s obligation to deliver the Contract Quantity for each Showing Month may be reduced at Seller’s option by the amount of any Planned Outages which exist with respectto any portion of the Unit generating capacity during the applicable Showing Month; provided, (i) Seller notifies Purchaser by the Notification Deadline applicable to that Showing Month of the amount of Product from the Unit that Purchaser may include in Purchaser’s Compliance Showings applicable to that month as a result of such Planned Outage, and (ii) such reduction is able to be reflected on the Supply Plansinaccordance with the Tariff.
(b) If Seller is providing Contingent Firm RA Product, Seller’s obligation to deliver the Contract Quantity for any Showing Month may be reduced at Seller’s option if the Unit experiences a reduction in Unit NQC as determined by the CAISO or a reduction in the SOD NQC as determined by the CPUC; provided, (i) Seller notifies Purchaser by the Notification Deadline applicable to that Showing Month of the amount of Product from the Unit that Purchaser may include in Purchaser’s Compliance Showings applicable to that month as a result of reduction in Unit NQC as determined by the CAISO or a reduction in the SOD NQC as determined by the 162
CPUC, and (ii) such reduction is able to be reflected on the Supply Plans in accordance with the Tariff. Seller’s potential reduction in Contract Quantity for each remaining Showing Month shall equal the product of (i) the applicable Showing Month Contract Quantity and (ii) the total amount (in MW) Unit NQC or SOD NQC (as applicable) that was reduced since the Effective Date, divided by (iii) Unit NQC or SOD NQC (as applicable) as of the Effective Date. (c) In the event Seller is unable to provide the Contract Quantity for any portion of a Showing Month because of a Planned Outage of a Unit or reduction in Unit NQC or SOD NQC, Seller has the option, but not the obligation, to provide Product for such portions of such Showing Month from Replacement Units, provided Seller provides and identifiessuch Replacement Unitsin accordance with Section 2.3. (d) If Seller is providing Contingent Firm RA Product, Seller’s obligation to deliver the applicable Contract Quantity for any Showing Month may also be reduced by Seller if the Unit NQC and/or SOD NQC of the Unit is less than the Expected Unit NQC and/or Expected SOD NQC, as applicable, identified in Appendix B, or if the Unit has not obtained a Unit NQC and/or SOD NQC for the relevant Showing Month. If the Unit experiences such a reduction in or lack of Unit NQC and/or SOD NQC, and provided that any such reduction is beyond Seller’s reasonable control, then Seller has the option to reduce the Contract Quantity to the available Unit NQC or SOD NQC, if any, for the relevant Showing Month by providing written notice to Purchaser no later than the Notification Deadline for such Showing Month. For the avoidance of doubt, Seller may reduce the Contract Quantity to zero, provided that such reduction matches the available Unit NQC and SOD NQC and otherwise is consistent with this Section 2.2(d).
(e) ☒ If checked, the following provision and related definitions are applicable.

2.2, or Seller desires to provide some or all of the Contract Quantity for any Showing Month from 163
a different generating unit other than the Unit, then Seller may, at no cost to Purchaser, provide Purchaser with replacement Product from one or more Replacement Units in an amount such that the total amount of Product provided to Purchaser from the Unit and any Replacement Unit(s) for each Showing Month is not more than the Contract Quantity, provided that in each case:
(a) Seller shall notify Purchaser in writing of its intent to provide Alternate Capacity and shall identify the proposed Replacement Units from which such Alternate Capacity shall be provided no later than the Notification Deadline for Purchaser’s Compliance Showings related to such Showing Month;
(b) The proposed Replacement Units must (i) be accepted by the CAISO, and (ii) otherwise satisfy the requirements of this Agreement;
(c) Seller shall cause the Unit’s SC to submit a Supply Plan that includes the Replacement Units for each applicable Showing Month and, if applicable, annual filing, no later than the Compliance Showing Deadline for Purchaser’s Compliance Showings; and
(d) If Seller does not comply with the requirements of Sections 2.3(a), (b) and (c) for the applicable Showing Month and, if applicable, annual filing, then any such Replacement Units shall not be deemed a Replacement Unit for purposes of this Confirmation for that Showing Month and Seller shall not receive payment for such Product.

2.4 Planned Outages
As of the Effective Date, Seller and Purchaser have agreed to all Planned Outages as specified in Appendix D (“Planned Outage Schedule”) for all relevant Showing Months for the following first (1st) calendar year, and at least fifty (50) days prior to each successive calendar year, Seller shall provide an updated Appendix D which sets forth the Planned Outages for such year. Seller may provide Purchaser with proposed changes to the Planned Outage Schedule from time to time.

2.5 Purchaser’s Remedies for Seller’s Failure to Deliver Expected Contract Quantity (a) If Seller fails to deliver any part of the Expected Contract Quantity as required herein for any Showing Month, Seller shall be liable for damages pursuant to Section 21.3 of the WSPP Agreement, without reference to the word “hourly” therein.
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(b) Seller shall indemnify, defend and hold harmless Purchaser from any penalties, fines or costs, assessed against Purchaser by the CPUC, CAISO or other Governmental Body resulting from Seller’s failure to deliver the Product or a Shown Unit’s SC’s failure to timely or accurately submit Supply Plans in accordance with the Tariff and this Confirmation. The Parties shall use commercially reasonable efforts to minimize such penalties, fines or costs; provided, that in no event will Purchaser be required to use or change its utilization of its owned or controlled assets or market positions to minimize these penalties, fines or costs.
(c) If Seller fails to pay the foregoing damages, penalties, fines or costs, or fails to reimburse Purchaser for those damages, penalties, fines or costs, then, without prejudice to its other rights and remedies, Purchaser may setoff and recoup those damages, penalties, fines or costs against any future amounts it may owe to Seller under this Confirmation or the WSPP Agreement.

PAYMENTS

3.1 Payment
Purchaser shall make a monthly payment to Seller for the Product by the later of (i) ten (10) calendar days after Purchaser’s receipt of Seller’s invoice and (ii) the twentieth (20th) day of the Showing Month, and if such day is not a Business Day, the next following Business Day (“Monthly RA Capacity Payment”). The Monthly RA Capacity Payment shall equal the product of (a) the applicable Contract Price for that Showing Month, (b) the Expected Contract Quantity for the Showing Month and (c) 1,000, rounded to the nearest penny (i.e., two decimal places); provided, however, that the Monthly RA Capacity Payment shall be adjusted to reflect any portion of Expected Contract Quantity for the Showing Month that was not delivered in accordance with Section 2.1 for such Showing Month.

3.2 Allocation of Other Payments and Costs
(a) Seller will receive any revenues from, and must pay all costs charged by, CAISO or any other third party with respect to the Shown Unit(s) for (i) start-up, shutdown, and minimum load costs, (ii) capacity for ancillary services, (iii) energy sales, (iv) flexible ramping product, or (v) black start or reactive power services. Purchaser must promptly report receipt of any such revenues to Seller. Purchaser must pay to Seller any such amounts described in this Section 3.2(a) received by Purchaser or a Subsequent Purchaser. Without prejudice to its other rights and remedies, Seller may setoff and recoup any such amounts that are not paid to it pursuant to this Section 3.2(a) against any amounts owed to Purchaser under the Confirmation and Related Confirmation.
(b) Any Availability Incentive Payments or Non-Availability Charges are for Seller to receive and pay.

ARTICLE 4

OTHER PURCHASER AND SELLER COVENANTS

4.2 Seller’s and Purchaser’s Duties to Take Actions to Allow Product Utilization Throughout the Delivery Period, Purchaser and Seller shall take all commercially reasonable actions and execute all documents or instruments reasonably necessary to ensure (a) Purchaser’s 166
rights to the Expected Contract Quantity for the sole benefit of Purchaser or any Subsequent Purchaser and (b) that Purchaser may use the Expected Contract Quantity to meet its Compliance Obligations. Such commercially reasonable actions shall include, without limitation cooperating with and providing, and causing each Shown Unit’s SC, owner, or operator to cooperate with and provide, requested supporting documentation to (a) Purchaser in order to meet its Mid-Term Reliability obligations and (b) the CAISO, the CPUC, or any other Governmental Body responsible for administering the applicable Compliance Obligations, including to demonstrate that the Expected Contract Quantity satisfies the Slice of Day Requirements and can be delivered to the CAISO controlled grid for the minimum hours required to satisfy the Compliance Obligations, as applicable, pursuant to the “deliverability” standards established by the CAISO or other Governmental Body of competent jurisdiction.

4.3 Seller’s Representations and Warranties
Seller represents and warrants to Purchaser throughout the Delivery Period that:
(a) Seller owns or has the exclusive right to the Product sold under this Confirmation from the Unit, and shall furnish Purchaser, CAISO, CPUC or other Governmental Authority with such evidence as may reasonably be requested to demonstrate such ownership or exclusive right;
(b) Seller shall comply with all applicable laws relating to the Product; (c) The resource attributes and capabilities associated with the Contract Quantity are and shall remain bundled across the applicable Showing Month and Seller has not and will not sell separate hourly products associated with the Contract Quantity; (d) No part of the Contract Quantity during the Delivery Period has been committed by Seller to any third party to satisfy Compliance Obligations or analogous obligations in any CAISO or non-CAISO markets;
(e) The Shown Unit(s) qualify to provide the Product under the Tariff, and the Shown Unit(s) and Seller are capable of delivering the Product; (f) The aggregation of all amounts of Capacity Attributes that Seller has sold, assigned, or transferred for the Shown Unit(s) during the Delivery Period does not exceed the Shown Unit’s Net Qualifying Capacity and, if applicable, the Effective Flexible Capacity for that Shown Unit, or the SOD NQC;
(g) If applicable, Seller has notified either the Shown Unit’s SC or the entity from which Seller purchased the Product that Seller has transferred the Contract Quantity of Product for the Delivery Period to Purchaser;
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(h) Seller has notified or will notify the Shown Unit’s SC that Purchaser is entitled to the revenues set forth in Section 3.2(b), and such Shown Unit’s SC is obligated to promptly deliver those revenues to Purchaser, along with appropriate documentation supporting the amount of those revenues; and (i) The Product includes the exclusive right of Purchaser to claim the Contract Quantity of Product as an incremental resource for purposes of Mid-Term Reliability.

4.4 Market Based Rate Authority
Upon Purchaser’s written request, Seller shall, in accordance with FERC Order No. 697, submit a letter of concurrence in support of any affirmative statement by Purchaser that this contractual arrangement does not transfer “ownership or control of generation capacity” from Seller to Purchaser as the term “ownership or control of generation capacity” is used in 18 CFR Section

ARTICLE 5

ARTICLE 6
ADDITIONAL WSPP AGREEMENT AMENDMENTS; GENERAL PROVISIONS

6.1 Termination Payment
For this Transaction, the first sentence of Section 22.2(b) of the WSPP Agreement is deleted in its entirety and replaced with the following:
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“If an Event of Default occurs, the Non-Defaulting Party shall possess the right to terminate this Confirmation and the Related Confirmation between the Parties under this Agreement upon written notice (by facsimile or other reasonable means) to the Defaulting Party, such notice of termination to be effective immediately upon receipt.” Additionally, for this Transaction,the following is inserted as a penultimate paragraph in Section

22.2(b) of the WSPP Agreement:
“If Purchaser is the Non-Defaulting Party and Purchaser reasonably expects to incur or be liable for any penalties, fines or costs from CAISO, or any Governmental Body, because Purchaser or a Subsequent Purchaser is not able to include the applicable Expected Contract Quantity in a Compliance Showing due to Seller’s Event of Default, then Purchaser may, in good faith, estimate the amount of those penalties, fines or costs and include the estimate in its determination of the Termination Payment, subject to accounting to Seller when those penalties, fines or costs are finally ascertained. If this accounting establishes that Purchaser’s estimate exceeds the actual amount of penalties, fines or costs, Purchaser must promptly remit to Seller the excess amount with interest in accordance with Section 9.3 of the WSPP Agreement. The rights and obligations with respect to determining and paying any Termination Payment, and any dispute resolution provisions with respect thereto, survive the termination of this Transaction and continue until after those penalties, fines or costs are finally ascertained.”

6.2 Confidentiality
Notwithstanding Section 30.1 of the WSPP Agreement,
(a) The Parties may disclose information as necessary to (i) its officers, employees, agents, consultants, and contractors as necessary for the performance of its obligations under this Agreement (ii) as necessary to comply with any applicable law, regulation, rule, requirement, request, or order of a Governmental Body with jurisdiction, including the CAISO; (iii) a Shown Unit’s SC or as necessary for Supply Plan; and (iv) the independent evaluator or other administrator of any competitive solicitation process of Purchaser, which in turn may disclose such information as necessary to CAISO or any Governmental Body. In addition, Purchaser may disclose information as necessary to (i) the CAISO, the CPUC or a Governmental Body of competent jurisdiction, in order to support its Compliance Showings or otherwise show it has met its Compliance Obligations; and (ii) any Subsequent Purchaser.
(b) The Parties acknowledge that this Transaction, and all records related to its formation or performance, are subject to the California Public Records Act, (California Government Code section 7920.000 et. seq.), and that either Party may be required to make public this Confirmation (which may be partially redacted by a Party) in connection with the process of seeking approval from its board or commission for the execution of this Confirmation. Each Party acknowledges that the other Party may submit information to it that the other Party considers 169
confidential, proprietary, or trade secret information pursuant the Uniform Trade Secrets Act (Cal. Civ. Code section 3426 et seq.), or otherwise protected from disclosure pursuant to an exemption to the California Public Records Act. (c) If a Party (“Disclosing Party”) contends that any information submitted to the other Party (“Receiving Party”) contains the Disclosing Party’s proprietary and confidential information which falls within one or more California Public Records Act exemptions, the Disclosing Party shall clearly mark such information “Proprietary and Confidential” and identify the specific lines containing such information. Upon request or demand of any third person or entity not a party to this Confirmation (“Requestor”) pursuant to the California Public Records Act for production, inspection and/or copying of this Confirmation or any information designated by the Disclosing Party as confidential, the Receiving Party as soon as practical shall notify the Disclosing Party that such request has been made, by telephone call, letter sent via electronic mail, and/or by overnight carrier to the address, or email address listed at the end of this Confirmation. The Disclosing Party shall be solely responsible for taking whatever legal steps are necessary to protect information deemed by it to be confidential information and to prevent release of information to the Requestor by the Receiving Party. If the Disclosing Party takes no such action within ten (10) days, after receiving the foregoing notice from the Receiving Party, the Disclosing Party agrees that the Receiving Party may comply with the Requestor’s demand and is not required to defend against it.

6.4 Change in Law
If any action by the CPUC, CAISO or any Governmental Body having jurisdiction, or any change in applicable law, occurring after the Effective Date results in (i) material changes to Purchaser’s or Seller’s obligations with regard to the Products sold hereunder, (ii) has the effect of changing the transfer and sale procedure set forth in this Confirmation so that the performance of this Confirmation becomes impracticable, or (iii) changes the Resource Adequacy Requirements such that the Product can no longer be counted towards Purchaser’s Resource Adequacy Requirements (a “Change in Law”), the Parties shall work in good faith to revise this Confirmation so that the 170
Parties can perform their obligations regarding the purchase and sale of the Product sold hereunder in order to maintain the original intent.

6.6 Collateral
Notwithstanding any provision in the WSPP Agreement to the contrary, including Section 27, neither Party shall be required to post collateral or other security for this Transaction.

6.7 No Recourse to Seller
Seller is organized as a Joint Powers Authority in accordance with the Joint Exercise of Powers Act of the State of California (Government Code Section 6500, et seq.) and is a public entity separate from its constituent members. Seller will solely be responsible for all of its debts, obligations and liabilities accruing and arising out of this Confirmation. Purchaser will have no rights and shall not make any claims, take any actions or assert any remedies against any of Seller’s constituent members, or the officers, directors, advisors, contractors, consultants or employees of Seller or Seller’s constituent members, in connection with this Confirmation.

6.8 Designated Fund and Limited Obligations
(a) Designated Fund. Purchaser is a municipal corporation and is precluded under the California State Constitution and applicable law from entering into obligations that financially bind future governing bodies, and, therefore, nothing in the Agreement shall constitute an obligation of future legislative bodies of the City to appropriate funds for purposes of the Agreement; provided, however, that (i) Purchaser has created and set aside a designated fund (the “Designated Fund”) for payment of its obligations under the Agreement and (ii) subject to the requirements and limitations of applicable law and taking into account other available money specifically authorized by Purchaser and allocated and appropriated to the San José Clean Energy’s obligations, Purchaser agrees to establish San José Clean Energy rates and charges that are sufficient to maintain revenues in the Designated Fund necessary to pay its obligations under this Agreement and all of Purchaser’s payment obligations under its other contracts for the purchase of energy for San José Clean Energy. Purchaser shall provide Seller with reasonable access to account balance information with respect to the San José Clean Energy Designated Fund during the Term.
(b) Limited Obligations. Purchaser’s payment obligations under the Agreement are special limited obligations of the Purchaser payable solely from the Designated Fund and are not a charge upon the revenues or general fund of the City of San José or upon any non- San José Clean Energy moneys or other property of the Community Energy Department or the City of San José.
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6.9 City of San José Standard Provisions
a) Nondiscrimination/Non-Preference. Seller shall comply with all laws and agrees to not discriminate against or grant preferential treatment to any person on the basis of race, sex, color, age, religion, sexual orientation, actual or perceived gender identity, disability, ethnicity or national origin. This prohibition applies to recruiting, hiring, demotion, layoff, termination, compensation, fringe benefits, advancement, training, apprenticeship and other terms, conditions, or privileges of employment, subcontracting and purchasing. Seller will include in each subcontract entered into after the Effective Date of this Agreement these same obligations. This prohibition is not intended to preclude Seller from providing a reasonable accommodation to a person with a disability. b) Conflict of Interest. Seller represents that it is familiar with the local and state conflict of interest laws, and agrees to comply with those laws in performing this Agreement. Seller certifies that, as of the Effective Date, it was unaware of any facts constituting a conflict of interest. Seller shall avoid all conflicts of interest in performing this Agreement. Seller has the obligation of determining if the manner in which it performs any part of this Agreement results in a conflict of interest, and shall immediately notify the Purchaser in writing if it becomes aware of any facts giving rise to a conflict of interest. Seller’s violation of this subsection (b) is a material breach.
c) Gifts Prohibited. Chapter 12.08 of the San José Municipal Code prohibits a City of San José officer or designated employee from accepting any gift. Seller shall not offer any City of San José officer or designated employee any gift prohibited by Chapter 12.08.
d) Disqualification of Former Employees. Chapter 12.10 of the San José Municipal Code prohibits a former City of San José officer and former designated employee from providing services to the City of San José connected with his/her former duties or official responsibilities. Seller shall not use either directly or indirectly any officer, employee or agent to perform any services if doing so would violate Chapter 12.10.

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 172
interest accrued at the Interest Rate from and including the due date to but excluding the date paid. Inadvertent overpayments shall be returned upon request or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Interest Rate from and including the date of such overpayment to but excluding the date repaid or deducted by the Party receiving such overpayment.

Any dispute with respect to an invoice is waived unless the other Party is notified in writing within twelve (12) months after the invoice is rendered or any specific adjustment to the invoice is made. If an invoice is not rendered within twelve (12) months after the close of the month during which performance of a Transaction occurred, the right to payment for such performance is waived.” (b) Section 22.1 is modified by inserting the following new text at the end thereof:
“(f) the failure of the Defaulting Party to pay its debts generally as they become due or the Defaulting Party’s admission in a writing that is unable to pay its debts generally as they become due;
(g) the institution, by the Defaulting Party, of a general assignment for the benefit of its creditors; or
(h) the application for, consent to, or acquiescence to, by the Defaulting Party, the appointment of a receiver, custodian, trustee, liquidator, or similar official for all or a substantial portion of its assets.”
(c) Section 22.2(b) is amended by inserting “and is continuing” after “Event of Default occurs” in the first line thereof and deleting the second sentence therein. (d) Section 22.3(c) is amended by deleting the third sentence thereof and replacing it with the following:
“If the Non-Defaulting Party’s aggregate Gains exceed its aggregate Losses and Costs after any set-off as set forth in Section 22.3(d) of the WSPP Agreement, if any, resulting from the termination of this Agreement or a Confirmation, the Termination Payment for all such Terminated Transactions shall be zero, notwithstanding any provision in this Section or Agreement to the contrary.” (e) Section 22.3(e) is deleted in its entirety and replaced with the following:
“[Intentionally omitted]”
(f) Section 22.3(f) is deleted in its entirety and replaced with the following:
“If the Defaulting Party disagrees with the calculation of the Termination Payment and the Parties cannot otherwise resolve their differences, and provided that the Defaulting Party has paid the undisputed part of the Termination Payment to the Non-Defaulting Party as provided under Section 22.3(c), and that any amounts disputed by the Defaulting Party are disputed in good faith, then the Defaulting Party may submit the calculation issue to dispute resolution pursuant to Section

34.”
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(g) Section 28.1 is applicable and the Parties shall net monthly payments in accordance with Exhibit A of the WSPP. Both Parties intend for the netting provisions of Exhibit A to the WSPP Agreement to be effective on the Effective Date. (h) Section 30.1(4) is amended by inserting “or requested” after the word “required” and by adding the following at the end of the first sentence: “; or (8) to the Party’s and such Party’s affiliates’ lenders, counsel, accountants, advisors and agents who have a need to know such information and have agreed to keep such terms confidential”.
(i) Subsections 34.1 and 34.2 are deleted and replaced with the following:
“34.1 DISPUTE RESOLUTION

IN THE EVENT OF ANY DISPUTE ARISING UNDER THE AGREEMENT WITH RESPECT TO THIS TRANSACTION, WITHIN TEN (10) DAYS

FOLLOWING THE RECEIPT OF A WRITTEN 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 THIRTY (30) DAYS AFTER RECEIPT OF SUCH NOTICE, THEN

EITHER PARTY MAY SEEK ANY AND ALL REMEDIES AVAILABLE TO

IT AT LAW OR IN EQUITY, SUBJECT TO THE LIMITATIONS SET FORTH IN THE AGREEMENT.”
“34.2 EXCLUSIVE JURISDICTION

EACH PARTY SUBMITS TO THE EXCLUSIVE JURISDICTION OF THE

STATE OR FEDERAL COURTS LOCATED IN SAN DIEGO OR SANTA
CLARA,
1 CALIFORNIA, FOR ANY ACTION OR PROCEEDING RELATING

TO THIS AGREEMENT OR ANY TRANSACTION, AND EXPRESSLY

EXCEPT AS OTHERWISE SPECIFIED IN ANY CONFIRMATION, FOR

BREACH OF ANY PROVISION OF THIS AGREEMENT FOR WHICH AN

EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, THE

EXPRESS REMEDY OR MEASURE OF DAMAGES PROVIDED IS THE SOLE 1 SDCP and SJCE previously entered into a confirmation letter, dated, April 18, 2022, where SDCP agreed to split jurisdictions.
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AND EXCLUSIVE REMEDY UNDER THIS AGREEMENT AND LIABILITY

FOR THE BREACH IS LIMITED AS SET FORTH IN THE PROVISION AND

ALL OTHER REMEDIES FOR DAMAGES AT LAW OR IN EQUITY ARE
WAIVED. EXCEPT AS OTHERWISE SPECIFIED IN ANY CONFIRMATION,

IF NO EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED IN

THIS AGREEMENT FOR A PARTICULAR BREACH, LIABILITY FOR THE

BREACH IS LIMITED TO DIRECT DAMAGES ONLY, THE DIRECT

DAMAGES ARE THE SOLE AND EXCLUSIVE REMEDY UNDER THIS

AGREEMENT FOR THE BREACH, AND ALL OTHER REMEDIES FOR
DAMAGES AT LAW OR IN EQUITY ARE WAIVED. EXCEPT AS

OTHERWISE SPECIFIED IN ANY CONFIRMATION, NEITHER PARTY IS

LIABLE FOR ANY OTHER TYPE OF DAMAGE, INCLUDING INCIDENTAL,

PUNITIVE, EXEMPLARY, CONSEQUENTIAL, SPECIAL OR INDIRECT

DAMAGES OF ANY NATURE (INCLUDING DAMAGES ASSOCIATED

WITH LOST PROFITS, BUSINESS INTERRUPTION AND LOSS OF

GOODWILL) ARISING AT ANY TIME, WHETHER IN TORT (INCLUDING

THE SOLE OR CONTRIBUTORY NEGLIGENCE OF EITHER PARTY OR

From the date of entering into a Transaction under this Agreement and throughout the term of such Transaction, the Parties each warrant and covenant as follows:

Public Util. Dist. No. 1 of Snohomish 554 U.S. 527 (2008) and NRG Power Marketing LLC v. Maine Pub. Util. Comm’n, 558 U.S. 165 (2010).

2. The Parties, for themselves and their successors and assigns, (i) agree that this “public interest” standard shall apply to any proposed changes in any other documents, instruments or other agreements executed or entered into by the Parties in connection with this Agreement and (ii) hereby expressly 175
and irrevocably waive any rights they can or may have to the application of any other standard of review, including the “just and reasonable” standard.”

6.12 Entire Agreement; No Oral Agreements or Modifications This Agreement sets forth the terms of the Transaction into which the Parties have entered and shall constitute the entire agreement between the Parties relating to the contemplated purchase and sale of the Product. Notwithstanding any other provision of the Agreement, this Transaction may be confirmed only through a Documentary Writing executed by both Parties, and no amendment or modification to this Transaction shall be enforceable except through a Documentary Writing executed by both Parties.
[Signatures appear on the following page.]
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AGREED AS OF THE EFFECTIVE DATE:

City of San José, a California municipal
corporation
San Diego Community Power, a
California joint powers authority
By:

Name:

Title:

Date:

Approved as to form:

By:

Name:

Title:

Date:

By:

Name:

Title:

Date:
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APPENDIX A

DEFINED TERMS
“Alternate Capacity” means replacement Product which Seller has elected to provide to Purchaser from a Replacement Unit in accordance with the terms of Section 2.3. “CAISO” means the California ISO or the successor organization to the functions thereof. “Capacity Attributes” means attributes of the Shown Unit that may be counted toward Compliance Obligations, including: flexibility, dispatchability, physical location or point of electrical interconnection of the Shown Unit; Unit ability to generate at a given capacity level during a given period of time, provide ancillary services, or ramp up or down at a given rate; any current or future defined characteristics, certificates, tags, credits, or accounting constructs of the Shown Unit, howsoever entitled, identified from time to time by the CAISO or a Governmental Body having jurisdiction over Compliance Obligations.
“CIRA Tool” means the CAISO Customer Interface for Resource Adequacy. “Compliance Obligations” means, as applicable, RAR, Local RAR, FCR, and the Slice of Day Requirements.
“Compliance Showing” means the applicable LSE’s compliance plan with the resource adequacy requirements of the CPUC for an applicable Showing Month. “Compliance Showing Deadline” means, for each Showing Month, the Compliance Showing submission due date for such Showing Month. For illustrative purposes only, as of the Effective Date, the applicable Compliance Showing submission due dates are as follows: (A) forty-five (45) days prior to the Showing Month covered by the Supply Plan for the monthly Supply Plan; and (B) the last Business Day of October that is prior to commencement of the year for the annual Supply Plan, such dates may be modified by the CAISO from time to time throughout the Delivery Period.
“Contingent Firm RA Product” has the meaning set forth in Article 1 herein. “Contract Quantity” means the amount of capacity and/or energy to be supplied for a transaction under the Agreement.
“Contract Quantity Availability Hours” means the hours, in the amount set forth in Appendix B, that will be used in Purchaser’s compliance filings and which represent the hours the Shown Unit is available for production and satisfaction of the Shown Unit’s must-offer obligation. “CPUC” means the California Public Utilities Commission. “CPUC Decisions” means any currently effective or future decisions, resolutions, or rulings related to resource adequacy.
“CPUC Filing Guide” is the document issued annually by the CPUC which sets forth the guidelines, requirements and instructions for load serving entities to demonstrate compliance with 178
the CPUC’s resource adequacy program, as such may be modified, amended, supplemented or updated from time to time.
“Delivery Period” has the meaning set forth in Appendix B, attached hereto. “Effective Flexible Capacity” has the meaning given in CAISO’s FERC-approved Tariff. “Expected Contract Quantity” means,with respect to any Showing Month of the Delivery Period, (a) for Firm RA Product, the Contract Quantity of Product, including the amount of Contract Quantity of Product that Seller has elected to provide Alternate Capacity, and (b) for Contingent Firm RA Product, the Contract Quantity of Product for such Showing Month, including the amount of Contract Quantity of Product that Seller has elected to provide Alternate Capacity, less any reductions to Contract Quantity consistent with Section 2.2 with respect to which Seller has not elected to provide Alternate Capacity.
“Expected Unit EFC” means the Effective Flexible Capacity the Unit is expected to provide as set forth in Appendix B.
“Expected Unit NQC” means the Net Qualifying Capacity the Unit is expected to provide as set forth in Appendix B.
“Expected SOD NQC” means the expected hourly Net Qualifying Capacity value of the Unit as set forth in Appendix B.
“FCR” means the flexible capacity requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or other Governmental Body having jurisdiction over Compliance Obligations and includes any non-binding advisory showing which an LSE is required to make with respect to flexible capacity. “FCR Attributes” means, with respect to a Shown Unit, any and all resource adequacy attributes of the Shown Unit, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction over Compliance Obligations, that can be counted toward an LSE’s FCR.
“Firm RA Product” has the meaning set forth in Article 1 herein. “Flexible Capacity Category” shall be as described in the annual CPUC Filing Guide, as such may be modified, amended, supplemented or updated from time to time. “Governmental Body” means any federal, state, local, municipal or other government; any governmental, regulatory or administrative agency, commission or other authority lawfully exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal. “Incremental Capacity” means capacity that as of the Effective Date was not included in the CPUC’s 2019-2020 IRP RESOLVE/SERVM baseline generator list identified in CPUC Decision 21-06-035, and as subsequently updated by the CPUC.
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“Interest Rate” means, for any date, the lesser of (a) the per annum rate of interest equal to the prime lending rate as may from time to time be published in The Wall Street Journal under “Money Rates” on such day (or if not published on such day on the most recent preceding day on which published), plus two percent (2%) and (b) the maximum rate permitted by applicable law. “Local RAR” means the local resource adequacy requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, by CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction over Compliance Obligations.
“Local RAR Attributes” means, with respect to a Shown Unit, any and all resource adequacy attributes of the Shown Unit, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction over Compliance Obligations, that can be counted toward an LSE’s Local RAR.
“LSE” means “Load Serving Entity” as such term is used in Section 40.9 of the Tariff. “MW” means megawatt.
“Mid-Term Reliability” means a resource that meets the requirements of D.21-06-035, as it may be amended by the CPUC, including that such resource is (a) incremental to the CPUC’s baseline list, and (c) a Resource Adequacy Resource (as defined in the Tariff) that is eligible to provide Capacity Attributes as set forth in the CPUC Decisions. “Net Qualifying Capacity” has the meaning given in CAISO’s FERC-approved Tariff. “Notification Deadline” is twelve (12) Business Days before the Compliance Showing Deadline. “Planned Outage” means, subject to and as further described in the CPUC Decisions, a CAISO-approved, planned or scheduled disconnection, separation or reduction in capacity of the Unit that is conducted for the purposes of carrying out routine repair or maintenance of such Unit, or for the purposes of new construction work for such Unit.
“Product” means RAR Attributes, Local RAR Attributes and FCR Attributes, each for the Delivery Period, Unit, Contract Quantity, Contract Price and other specifications contained in Appendix B. “Prorated Percentage of Unit Factor” means the percentage, as specified in Appendix B, of the Unit NQC as of the Effective Date that is dedicated to Purchaser under this Transaction. “Prorated Percentage of Unit Flexible Factor” means the percentage, as specified in Appendix B, of the Unit EFC as of the Effective Date that is dedicated to Purchaser under this Transaction. “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 power industry during the relevant time period 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 180
optimum practice, method or act to the exclusion of all others, but rather to acceptable practices, methods or acts generally accepted in the electric power industry in the Western United States. “RAR Attributes” means, with respect to a Shown Unit, any and all resource adequacy attributes of the Shown Unit, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction over Compliance Obligations, that can be counted toward an LSE’s RAR.
“Related Confirmation” has the meaning set forth in the preamble. “Replacement Unit” means a generating unit having the same Capacity Attributes as the Unit, including the Contract Quantity Availability Hours, RAR Attributes, and, as applicable, LAR Attributes, FCR Attributes, and Flexible Capacity Category, and otherwise meeting the requirements specified in Section 2.3 hereof, unless Purchaser consents in writing in its sole discretion to accept a Replacement Unit that does not have the same Capacity Attributes as the Unit. A Replacement Unit shall not utilize coal or coal materials as a source of fuel, must be a specific resource that is connected directly to the CAISO controlled grid, or be under the operational control of CAISO, and may not be an unspecified import. “Resource Adequacy Requirements” or “RAR” means the resource adequacy requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, by CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction over Compliance Obligations, including Slice of Day Requirements, but not including Local RAR or FCR. “Resource Category” shall be as described in the annual CPUC Filing Guide, as such may be modified, amended, supplemented or updated from time to time. “San José Clean Energy” means the City of San José’s community choice aggregation program.

The San José Energy Department administers and manages San José Clean Energy. “SC” means Scheduling Coordinator as defined in the Tariff. “Showing Month” means the calendar month of the Delivery Period that is the subject of the related Compliance Showing.
“Shown Unit” means the Unit, or any Replacement Unit meeting the requirements of Section 2.3 of this Confirmation and specified by Seller in a Supply Plan. “Slice of Day” or “SOD” means the CPUC’s 24-hour Slice-of-Day Framework established in D.22-06-050 and D.23-04-010 and D. 24-06-004, as may be modified by the CPUC from time to time.
“Slice of Day Requirements” means the Slice of Day framework, or any successor program thereof as may be established and modified by the CPUC from time to time. “SOD NQC” means the lesser of the Expected SOD NQC and the hourly Net Qualifying Capacity value of the Unit as determined by the CPUC pursuant to the Slice of Day Requirements on a subsequent date of determination.
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“Start Date” has the meaning set forth in Appendix B, attached hereto. “Subsequent Purchaser” means the purchaser of Product from Purchaser in a re-sale of Product by Purchaser.
“Substitute Capacity” has the meaning set forth in the Tariff for “RA Substitute Capacity”. “Tariff” means the CAISO Tariff, including any current CAISO-published “Operating Procedures” and “Business Practice Manuals,” in each case as amended or supplemented from time to time.
“Unit” means Unit 1 as described in Appendix B.
“Unit EFC” means the lesser of the Expected Unit EFC and Unit’s Effective Flexible Capacity on a subsequent date of determination.
“Unit NQC” means the lesser of the Expected Unit NQC and Unit’s Net Qualifying Capacity on a subsequent date of determination.
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183
Unit 1
Additional information for solar and wind resources:

Part of co-located or hybrid resource (yes/no)
For calculation of correct SOD hourly QC based on exceedance values:

Region
Solar type (tracking, fixed)
Interconnection limit (if part of co-located or hybrid resource) 184
185
186
Credit and Collections:

Attn: SDCP Finance
E-mail: [email protected]
Credit and Collections:

Attn: Director of Finance
200 East Santa Clara Street Tower 13
San Jose, CA 95113
Phone: (408) 535-7011
Email: [email protected]
and an additional copy to:

Office of the City Attorney
Attn. Deputy City Attorney, Energy Department
200 East Santa Clara Street, 16th Floor Tower
San Jose, CA 95113-1905
Direct: (408) 535-1900
Email: [email protected]
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SAN DIEGO COMMUNITY POWER
Staff Report - Item 14
To: Board of Directors
From: Jack Clark, Chief Operating Officer
Lucas Utouh, Senior Director of Data Analytics & Customer Operations Tim Manglicmot, Director of Finance
Aaron Lu, Rates and Strategy Manager
Diana Gonzalez, Risk Manager
Pete Polonsky, Senior Rates Analyst
Via: Karin Burns, Chief Executive Officer
Subject: Review and Approve 2026 Community Power Rates Adjustment, to be Effective as of May 1, 2026
Date: April 23, 2026
Recommendation
Review and approve rate adjustments for the PowerOn and PowerBase services, as contained in Attachment A, to go into effect as of May 1, 2026. The recommendation includes continuing to offer San Diego Community Power (Community Power) default PowerOn service electricity generation/commodity rates that are 4% cheaper compared to San Diego Gas and Electric’s (SDG&E) generation rates and PowerBase service electricity generation rates that are 10% cheaper than SDG&E’s generation rates. Power100 and Power100 Green-e Certified (Green-e Plus) will maintain premiums of $0.01/kWh and $0.02/kWh, respectively, compared to PowerOn.

Background
On January 15, 2026, the Board of Directors of San Diego Community Power (Community Power) reviewed and approved 2026 Community Power rates effective retroactively as of January 1, 2026. The aforementioned 2026 Community Power rates included Community Power default PowerOn service electricity generation/commodity rates that are 4% cheaper compared to SDG&E generation rates and PowerBase service electricity generation rates that are 10% cheaper than SDG&E’s generation rates effective as of January 1, 2026; with Power100 and Power100 Green-e Certified (Green-e Plus) maintaining premiums of $0.01/kWh and $0.02/kWh, respectively, compared to PowerOn. 189
On March 2, 2026, SDG&E filed Advice Letter 4791-E for the implementation of their 2024 General Rate Case (GRC) Phase 2 and Track 2 Wildfire Mitigation Costs for electric rates effective as of April 1, 2026. This Advice Letter contained updates to SDG&E’s bundled commodity/generation and the Power Charge Indifference Adjustment (PCIA) rates. Both SDG&E bundled generation and PCIA rates play a role in the Community Power rate setting process, particularly as it relates to Community Power’s competitiveness.

Community Power staff, along with regulatory and technical consultants, identified errors in how SDG&E calculated their PCIA rates and filed a joint Protest with Clean Energy Alliance staff to SDG&E’s Advice Letter 4791-E on March 23, 2026. SDG&E acknowledged the error and provided corrected PCIA and bundled commodity/generation rate information through a Partial Supplemental Advice Letter 4791-E-A on March 30, 2026, and implemented new rates on April 1. As a result, San Diego Community Power staff is recommending adjusting its generation rates accordingly.

Consistent with its Board-approved Rate Development Policy, Community Power’s rate setting strategy uses a hybrid approach based on cost of service and the Investor-Owned Utility (IOU) discount-focused rate-setting models. First, Community Power determines the cost recovery required to meet expected procurement and operational expenses and sets rates to at least meet that amount. Next, Community Power adds ranges that target goals for financial stability, such as reserves contributions, and discretionary spending, such as programs or operational growth opportunities. Finally, Community Power targets a competitiveness metric with SDG&E to determine where rates should be within that range and modify the discretionary spending, accordingly, aiming for a discount when possible. For the recommended rates adjustment effective as of May 1, 2026, Community Power prioritized continuing to provide the deep discount to customers that was adopted by the Board in January 2026.

The Board of Directors’ review and approval of the recommended rates adjustment would be consistent with best ratemaking practices. These new proposed rates will continue to provide customers with Community Power’s deepest discount, will address affordability concerns, and will also continue to meet Community Power’s annual revenue requirements, including the need for any reserves or coverage requirements set forth in policy and/or loan covenants, as well as debt service to operate a viable organization, as required in our Financial Reserves Policy.

Analysis and Discussion
May 1, 2026, Rates Adjustment
Community Power rates for its PowerOn and PowerBase services mirror SDG&E’s rates in terms of rate schedules, Time-Of-Use (TOU) periods, as well as demand charges. This rate design approach is typical for community choice aggregation programs ensuring ease of 190
comparison for customers with SDG&E’s rates and allows for a seamless competitive environment. Therefore, Community Power is recommending an adjustment to its rates in response to SDG&E’s Advice Letter 4791-E for the implementation of their 2024 GRC Phase 2 and Track 2 Wildfire Mitigation Costs for electric rates effective as of April 1, 2026. This recommended rates’ design and adjustment by Community Power is necessary to allow the agency to continue to provide world-class customer experience for our customers and to ensure affordability concerns continue to be addressed as well as maintaining equity among all customers.

SDG&E’s April 1, 2026, rates adjustment implemented changes adopted from SDG&E’s most recent GRC Phase 2. The most impactful changes included the creation of a new Medium Commercial customer class from the existing Small and Large Commercial and Industrial customer classes, updating the revenue that needs to be collected from each customer class, and expanding the TOU mid-day super off-peak period to the full year.

Other changes included aligning how the expanded low-income discount (i.e., E-LI) is applied to commercial customers with the same methodology for residential customers, aligning the medical baseline discount adjustment methodology, increasing commercial monthly service fees, and making various updates to delivery rates consistent with the GRC Phase 2 directives.

Lastly, SDG&E also increased delivery rates to collect $589 million in wildfire-related costs, approximately $50 million of which is included in SDG&E’s revenue requirement for 2026.

Based on SDG&E’s March 2 Advice Letter 4791-E and 4791-E-A filings to implement April 1, 2026, rates, the projected bundled system average generation rates remained relatively unchanged. However, the customer class specific average commodity rate and PCIA changes were driven by the creation of the new Medium Commercial customer class and the updated revenue allocation between customer classes per SDG&E’s GRC Phase 2 settlement.

Community Power saw a minor increase in PCIA rates for all vintages relevant to its Large Commercial and Industrial customers, including Vintage Year 2020 (Phase 1 & 2 customers), Vintage Year 2021 (Phase 3 customers), and Vintage Year 2022 (Phase 4 customers), based on SDG&E’s March Advice Letters. PCIA rates for Community Power’s Small Commercial and Agricultural customers decreased for all applicable vintages.

Community Power Rates Adjustment Mechanics
Community Power utilized its latest financial projections for rate-adjustment analysis purposes, meaning that the proposed approach for developing staff recommended rates is reasonable and appropriate to cover operational expenses and recover revenues consistent with estimated Fiscal Year (FY) 2025-2026 and FY 2026-2027 sales and expenditures.

Consistent with its Board-approved Rate Development Policy, Community Power’s rate setting strategy uses a hybrid approach based on cost of service and the IOU discount-focused rate setting models. First, Community Power determines the cost recovery required to meet 191
expected procurement and operational expenses and sets rates to at least meet that amount.

Next, Community Power adds ranges that target goals for financial stability, such as reserves contributions, and discretionary spending, such as programs or operational growth opportunities. Finally, Community Power targets a competitiveness metric with SDG&E to determine where rates should be within that range and modify the discretionary spending, accordingly, aiming for a discount when possible.

For this recommended rates adjustment, Community Power prioritized continuing to provide the deep discount to customers that was adopted in the January 1, 2026, effective rates whereby the agency’s default PowerOn service electricity generation rates were 4% cheaper compared to SDG&E generation rates and PowerBase service electricity generation rates are 10% cheaper compared to SDG&E’s generation rates.

The recommended rates adjustment was carefully designed to continue to meet customer affordability, while still yielding revenues sufficient to collect Community Power’s projected annual power supply costs and pay for other operating costs, debt service costs, community investments, a nominal planned reserve margin contribution and have a balanced budget.

Additionally, staff’s recommendation allows Community Power to balance customer affordability while maintaining its reserves and progress towards its 225- to 270-days cash on hand reserve goal and Rate Stabilization Reserve strategic goal.

Furthermore, the recommended rates adjustment and reserve targets should ensure that Community Power meets certain key metrics that are required for and to maintain an investment-grade credit rating, which is important for rate competitiveness because it facilitates better terms for power procurement and other credit-related activities. Finally, the recommended rates adjustment allows Community Power to be in compliance with its financial covenants outlined in its Revolving Credit Agreement with JP Morgan Chase Bank, its covenants and distribution requirements outlined in its Security Agreement with River City Bank, and covenants with certain power-purchase agreements.

Recommended Rate Adjustments
The staff recommended rates adjustment before the Board maintain reserves at a level consistent with the amendment of the FY 2025-26 operating budget approved by the Board on February 26, 2026. Specifically, the amendment projected that Community Power would end FY 2025-26 with 229-days cash on hand, while the proposed rate adjustment projects Community Power would end FY 2025-26 with 238-days cash on hand. Given the nominal change, the rate adjustment remains consistent with the reserve targets established in the Financial Reserves Policy amended by the Board on December 11, 2025, particularly by maintaining reserves above the 225-days cash on hand reserve target. 192
Table 1 provides an updated projection of Community Power’s FY 2025-26 operating budget given the proposed rate adjustment compared to the amendment of the FY 2025-26 operating budget approved by the Board on February 26, 2026. The updated projection also includes current projections for Community Power’s cost of energy, which are projected to decrease by $23.3 million. Given that the updated projections are lower than the revenue and expense appropriations approved by the Board on February 26, 2026, and given the nominal change, Community Power is not recommending an adjustment to the FY 2025-26 Operating Budget.

Table 1. Amended FY 2025-26 Operating Budget compared to Updated FY 2025-26 Operating Budget Projections resulting from rate adjustments.

The staff recommendation is reasonable and appropriate and considers projected operating costs based on contracts Community Power has executed to date and the projected costs of procuring energy and other wholesale services needed to supply Community Power’s customers with a default resource mix of 53% renewable and 2% carbon-free energy in our PowerOn service, as well as our 100% renewable energy in our Power100 and Power100 Green-e Certified services.
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A material difference between PCIA rates, associated with when customers transitioned from SDG&E’s bundled service and into Community Power’s service, continues to exist. The PCIA rate is the above-market cost of power associated with SDG&E’s portfolio that both SDG&E’s bundled customers as well as Community Power customers who have departed SDG&E generation/commodity service pay. A customer is assigned a PCIA “vintage” based on the year they depart service from SDG&E. The proposed rates will be trifurcated across our Phase 1 and 2 customers enrolled in 2021, Phase 3 customers enrolled in 2022, and Phase 4 customers in National City and Unincorporated areas of County of San Diego enrolled in 2023. Consistent with our Board-approved Rate Development Policy, trifurcation of rates will ensure a fair, equitable, and balanced rate structure across our customers with differing vintage years that maintains the intended cost savings for all customers.

Summary
Overall, the staff recommended rates adjustment for Board adoption provide the following benefits to Community Power customers and the organization:
• Continue to offer Community Power default PowerOn service electricity generation rates that are 4% cheaper compared to SDG&E rates, to be effective on May 1, 2026. • Continue to offer Community Power PowerBase service electricity generation rates that are 10% cheaper than SDG&E rates, to be effective on May 1, 2026. • Power100 and Power100 Green-e Certified will maintain premiums of $0.01/kWh and $0.02/kWh, respectively, compared to PowerOn.
• Higher renewable content (PowerOn product at 53% renewable and 2% carbon-free with Community Power, compared to the default SDG&E product at 41% renewable content as of the most recent 2024 Power Content Label, published in November 2025).
• Allow Community Power to maintain its current reserve levels and work towards a 225- to 270-days cash on hand reserve target which will provide financial stability. • Meets liquidity and FCC metrics that support and maintain an investment-grade credit rating.
• Satisfies credit obligations with lenders and power purchase agreements. • Prepares Community Power for future energy market fluctuations and regulatory uncertainty.

Fiscal Impact
The proposed rates adjustment was carefully designed to continue to meet customer affordability concerns while yielding revenues sufficient to collect Community Power’s projected annual power supply costs and pay for other operating costs and debt service costs, 194
to make community investments, to contribute a projected nominal planned reserve margin of 238-days cash on hand at the end of FY 2025-26, and to have a balanced budget.

Strategic Plan
This activity supports the strategic plan goals of (1) evolving rate strategy to ensure competitiveness, affordability, and fiscal sustainability, (2) developing customer strategies to increase retention and engagement and (3) building reserves by $150M to maintain a reserve target of at least 180-days cash on hand by December 2027.

Attachments
A: Staff’s recommended 2026 Community Power rates adjustment for PowerOn and PowerBase services, effective as of May 1, 2026
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ITEM 14

ATTACHMENT A
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Attachment A - Staff Recommended 2026 Community Power Rates Adjustment for PowerOn and PowerBase services, effective as of May 1, 2026.

CCA Rate Name Season Charge Type Time of Use Period PowerBase PowerOn Power100 ($/kWh) DR Summer Generation - 2020 Vintage Total $0.12643 $0.13739 + $0.01 DR Winter Generation - 2020 Vintage Total $0.12643 $0.13739 + $0.01 DR-LI-MB Summer Generation - 2020 Vintage Total $0.12643 $0.13739 + $0.01 DR-LI-MB Winter Generation - 2020 Vintage Total $0.12643 $0.13739 + $0.01 DR-SES Summer Generation - 2020 Vintage On-Peak $0.38201 $0.41022 + $0.01 DR-SES Summer Generation - 2020 Vintage Off-Peak $0.11787 $0.12825 + $0.01 DR-SES Summer Generation - 2020 Vintage Super Off-Peak $0.03639 $0.04127 + $0.01 DR-SES Winter Generation - 2020 Vintage On-Peak $0.14169 $0.15368 + $0.01 DR-SES Winter Generation - 2020 Vintage Off-Peak $0.09142 $0.10003 + $0.01 DR-SES Winter Generation - 2020 Vintage Super Off-Peak $0.02983 $0.03428 + $0.01 EV-TOU Summer Generation - 2020 Vintage On-Peak $0.38201 $0.41022 + $0.01 EV-TOU Summer Generation - 2020 Vintage Off-Peak $0.11787 $0.12825 + $0.01 EV-TOU Summer Generation - 2020 Vintage Super Off-Peak $0.03639 $0.04127 + $0.01 EV-TOU Winter Generation - 2020 Vintage On-Peak $0.14169 $0.15368 + $0.01 EV-TOU Winter Generation - 2020 Vintage Off-Peak $0.09142 $0.10003 + $0.01 EV-TOU Winter Generation - 2020 Vintage Super Off-Peak $0.02983 $0.03428 + $0.01 EV-TOU-2 Summer Generation - 2020 Vintage On-Peak $0.38201 $0.41022 + $0.01 EV-TOU-2 Summer Generation - 2020 Vintage Off-Peak $0.11787 $0.12825 + $0.01 EV-TOU-2 Summer Generation - 2020 Vintage Super Off-Peak $0.03639 $0.04127 + $0.01 197
EV-TOU-2 Winter Generation - 2020 Vintage On-Peak $0.14169 $0.15368 + $0.01 EV-TOU-2 Winter Generation - 2020 Vintage Off-Peak $0.09142 $0.10003 + $0.01 EV-TOU-2 Winter Generation - 2020 Vintage Super Off-Peak $0.02983 $0.03428 + $0.01 EV-TOU-5 Summer Generation - 2020 Vintage On-Peak $0.38201 $0.41022 + $0.01 EV-TOU-5 Summer Generation - 2020 Vintage Off-Peak $0.11787 $0.12825 + $0.01 EV-TOU-5 Summer Generation - 2020 Vintage Super Off-Peak $0.03639 $0.04127 + $0.01 EV-TOU-5 Winter Generation - 2020 Vintage On-Peak $0.14169 $0.15368 + $0.01 EV-TOU-5 Winter Generation - 2020 Vintage Off-Peak $0.09142 $0.10003 + $0.01 EV-TOU-5 Winter Generation - 2020 Vintage Super Off-Peak $0.02983 $0.03428 + $0.01 TOU-DR-1 Summer Generation - 2020 Vintage On-Peak $0.27443 $0.29538 + $0.01 TOU-DR-1 Summer Generation - 2020 Vintage Off-Peak $0.07823 $0.08594 + $0.01 TOU-DR-1 Summer Generation - 2020 Vintage Super Off-Peak $0.01000 $0.01000 + $0.01 TOU-DR-1 Winter Generation - 2020 Vintage On-Peak $0.20824 $0.22472 + $0.01 TOU-DR-1 Winter Generation - 2020 Vintage Off-Peak $0.13559 $0.14717 + $0.01 TOU-DR-1 Winter Generation - 2020 Vintage Super Off-Peak $0.05489 $0.06103 + $0.01 TOU-DR-2 Summer Generation - 2020 Vintage On-Peak $0.27443 $0.29538 + $0.01 TOU-DR-2 Summer Generation - 2020 Vintage Off-Peak $0.03892 $0.04398 + $0.01 TOU-DR-2 Winter Generation - 2020 Vintage On-Peak $0.20824 $0.22472 + $0.01 TOU-DR-2 Winter Generation - 2020 Vintage Off-Peak $0.08644 $0.09471 + $0.01 TOU-DR Summer Generation - 2020 Vintage On-Peak $0.16751 $0.18125 + $0.01 TOU-DR Summer Generation - 2020 Vintage Off-Peak $0.11516 $0.12537 + $0.01 TOU-DR Summer Generation - 2020 Vintage Super Off-Peak $0.06582 $0.07269 + $0.01 TOU-DR Winter Generation - 2020 Vintage On-Peak $0.20804 $0.22451 + $0.01 TOU-DR Winter Generation - 2020 Vintage Off-Peak $0.13544 $0.14702 + $0.01 TOU-DR Winter Generation - 2020 Vintage Super Off-Peak $0.05482 $0.06095 + $0.01 TOU-A-S Summer Generation - 2020 Vintage On-Peak $0.27343 $0.29364 + $0.01 TOU-A-S Summer Generation - 2020 Vintage Off-Peak $0.13774 $0.14878 + $0.01 TOU-A-S Winter Generation - 2020 Vintage On-Peak $0.14842 $0.16018 + $0.01 TOU-A-S Winter Generation - 2020 Vintage Off-Peak $0.06018 $0.06599 + $0.01 198
TOU-A-P Summer Generation - 2020 Vintage On-Peak $0.27193 $0.29203 + $0.01 TOU-A-P Summer Generation - 2020 Vintage Off-Peak $0.13692 $0.14791 + $0.01 TOU-A-P Winter Generation - 2020 Vintage On-Peak $0.14759 $0.15930 + $0.01 TOU-A-P Winter Generation - 2020 Vintage Off-Peak $0.05986 $0.06565 + $0.01 TOU-A-2-S Summer Generation - 2020 Vintage On-Peak $0.37737 $0.40459 + $0.01 TOU-A-2-S Summer Generation - 2020 Vintage Off-Peak $0.11305 $0.12244 + $0.01 TOU-A-2-S Summer Generation - 2020 Vintage Super Off-Peak $0.05203 $0.05730 + $0.01 TOU-A-2-S Winter Generation - 2020 Vintage On-Peak $0.13551 $0.14641 + $0.01 TOU-A-2-S Winter Generation - 2020 Vintage Off-Peak $0.06524 $0.07139 + $0.01 TOU-A-2-S Winter Generation - 2020 Vintage Super Off-Peak $0.04449 $0.04925 + $0.01 TOU-A-2-P Summer Generation - 2020 Vintage On-Peak $0.37543 $0.40251 + $0.01 TOU-A-2-P Summer Generation - 2020 Vintage Off-Peak $0.11241 $0.12175 + $0.01 TOU-A-2-P Summer Generation - 2020 Vintage Super Off-Peak $0.05178 $0.05702 + $0.01 TOU-A-2-P Winter Generation - 2020 Vintage On-Peak $0.13478 $0.14562 + $0.01 TOU-A-2-P Winter Generation - 2020 Vintage Off-Peak $0.06486 $0.07098 + $0.01 TOU-A-2-P Winter Generation - 2020 Vintage Super Off-Peak $0.04426 $0.04900 + $0.01 TOU-A-3-S Summer Generation - 2020 Vintage On-Peak $0.27643 $0.29684 + $0.01 TOU-A-3-S Summer Generation - 2020 Vintage Off-Peak $0.15843 $0.17087 + $0.01 TOU-A-3-S Summer Generation - 2020 Vintage Super Off-Peak $0.05312 $0.05846 + $0.01 TOU-A-3-S Winter Generation - 2020 Vintage On-Peak $0.13551 $0.14641 + $0.01 TOU-A-3-S Winter Generation - 2020 Vintage Off-Peak $0.06524 $0.07139 + $0.01 TOU-A-3-S Winter Generation - 2020 Vintage Super Off-Peak $0.04449 $0.04925 + $0.01 TOU-A-3-P Summer Generation - 2020 Vintage On-Peak $0.27497 $0.29528 + $0.01 TOU-A-3-P Summer Generation - 2020 Vintage Off-Peak $0.15754 $0.16992 + $0.01 TOU-A-3-P Summer Generation - 2020 Vintage Super Off-Peak $0.05275 $0.05806 + $0.01 TOU-A-3-P Winter Generation - 2020 Vintage On-Peak $0.13478 $0.14562 + $0.01 TOU-A-3-P Winter Generation - 2020 Vintage Off-Peak $0.06486 $0.07098 + $0.01 TOU-A-3-P Winter Generation - 2020 Vintage Super Off-Peak $0.04426 $0.04900 + $0.01 199
A-TC Summer Generation - 2020 Vintage Total $0.07104 $0.07758 + $0.01 A-TC Winter Generation - 2020 Vintage Total $0.07104 $0.07758 + $0.01 TOU-M Summer Generation - 2020 Vintage On-Peak $0.38835 $0.41683 + $0.01 TOU-M Summer Generation - 2020 Vintage Off-Peak $0.11160 $0.12141 + $0.01 TOU-M Summer Generation - 2020 Vintage Super Off-Peak $0.04450 $0.04978 + $0.01 TOU-M Winter Generation - 2020 Vintage On-Peak $0.13043 $0.14151 + $0.01 TOU-M Winter Generation - 2020 Vintage Off-Peak $0.05833 $0.06454 + $0.01 TOU-M Winter Generation - 2020 Vintage Super Off-Peak $0.03742 $0.04221 + $0.01 OL-TOU Summer Generation - 2020 Vintage On-Peak $0.53773 $0.57629 + $0.01 OL-TOU Summer Generation - 2020 Vintage Off-Peak $0.16493 $0.17833 + $0.01 OL-TOU Summer Generation - 2020 Vintage Super Off-Peak $0.06522 $0.07189 + $0.01 OL-TOU Winter Generation - 2020 Vintage On-Peak $0.17391 $0.18792 + $0.01 OL-TOU Winter Generation - 2020 Vintage Off-Peak $0.08271 $0.09056 + $0.01 OL-TOU Winter Generation - 2020 Vintage Super Off-Peak $0.05626 $0.06232 + $0.01 AL-TOU-M-S Summer Demand - 2020 Vintage On-Peak $17.06 $18.21 AL-TOU-M-S Summer Generation - 2020 Vintage On-Peak $0.21153 $0.22808 + $0.01 AL-TOU-M-S Summer Generation - 2020 Vintage Off-Peak $0.11429 $0.12427 + $0.01 AL-TOU-M-S Summer Generation - 2020 Vintage Super Off-Peak $0.09490 $0.10357 + $0.01 AL-TOU-M-S Winter Generation - 2020 Vintage On-Peak $0.23623 $0.25444 + $0.01 AL-TOU-M-S Winter Generation - 2020 Vintage Off-Peak $0.11765 $0.12786 + $0.01 AL-TOU-M-S Winter Generation - 2020 Vintage Super Off-Peak $0.08325 $0.09114 + $0.01 AL-TOU-M-P Summer Demand - 2020 Vintage On-Peak $16.98 $18.13 AL-TOU-M-P Summer Generation - 2020 Vintage On-Peak $0.21035 $0.22682 + $0.01 AL-TOU-M-P Summer Generation - 2020 Vintage Off-Peak $0.11360 $0.12354 + $0.01 AL-TOU-M-P Summer Generation - 2020 Vintage Super Off-Peak $0.09446 $0.10311 + $0.01 AL-TOU-M-P Winter Generation - 2020 Vintage On-Peak $0.23500 $0.25313 + $0.01 AL-TOU-M-P Winter Generation - 2020 Vintage Off-Peak $0.11702 $0.12719 + $0.01 AL-TOU-M-P Winter Generation - 2020 Vintage Super Off-Peak $0.08286 $0.09072 + $0.01 AL-TOU-L-S Summer Demand - 2020 Vintage On-Peak $16.34 $17.44 200
AL-TOU-L-S Summer Generation - 2020 Vintage On-Peak $0.20114 $0.21698 + $0.01 AL-TOU-L-S Summer Generation - 2020 Vintage Off-Peak $0.10806 $0.11763 + $0.01 AL-TOU-L-S Summer Generation - 2020 Vintage Super Off-Peak $0.08937 $0.09767 + $0.01 AL-TOU-L-S Winter Generation - 2020 Vintage On-Peak $0.22462 $0.24205 + $0.01 AL-TOU-L-S Winter Generation - 2020 Vintage Off-Peak $0.11113 $0.12090 + $0.01 AL-TOU-L-S Winter Generation - 2020 Vintage Super Off-Peak $0.07822 $0.08577 + $0.01 AL-TOU-L-P Summer Demand - 2020 Vintage On-Peak $16.27 $17.37 AL-TOU-L-P Summer Generation - 2020 Vintage On-Peak $0.20000 $0.21577 + $0.01 AL-TOU-L-P Summer Generation - 2020 Vintage Off-Peak $0.10741 $0.11693 + $0.01 AL-TOU-L-P Summer Generation - 2020 Vintage Super Off-Peak $0.08895 $0.09722 + $0.01 AL-TOU-L-P Winter Generation - 2020 Vintage On-Peak $0.22343 $0.24078 + $0.01 AL-TOU-L-P Winter Generation - 2020 Vintage Off-Peak $0.11054 $0.12027 + $0.01 AL-TOU-L-P Winter Generation - 2020 Vintage Super Off-Peak $0.07784 $0.08537 + $0.01 AL-TOU-L-T Summer Demand - 2020 Vintage On-Peak $15.57 $16.62 AL-TOU-L-T Summer Generation - 2020 Vintage On-Peak $0.18998 $0.20507 + $0.01 AL-TOU-L-T Summer Generation - 2020 Vintage Off-Peak $0.10141 $0.11052 + $0.01 AL-TOU-L-T Summer Generation - 2020 Vintage Super Off-Peak $0.08400 $0.09194 + $0.01 AL-TOU-L-T Winter Generation - 2020 Vintage On-Peak $0.21259 $0.22921 + $0.01 AL-TOU-L-T Winter Generation - 2020 Vintage Off-Peak $0.10461 $0.11395 + $0.01 AL-TOU-L-T Winter Generation - 2020 Vintage Super Off-Peak $0.07335 $0.08058 + $0.01 AL-TOU-2-S Summer Demand - 2020 Vintage On-Peak $29.15 $31.11 AL-TOU-2-S Summer Generation - 2020 Vintage On-Peak $0.17931 $0.19368 + $0.01 AL-TOU-2-S Summer Generation - 2020 Vintage Off-Peak $0.09500 $0.10369 + $0.01 AL-TOU-2-S Summer Generation - 2020 Vintage Super Off-Peak $0.07775 $0.08526 + $0.01 AL-TOU-2-S Winter Generation - 2020 Vintage On-Peak $0.20022 $0.21601 + $0.01 AL-TOU-2-S Winter Generation - 2020 Vintage Off-Peak $0.09746 $0.10631 + $0.01 AL-TOU-2-S Winter Generation - 2020 Vintage Super Off-Peak $0.06765 $0.07448 + $0.01 AL-TOU-2-P Summer Demand - 2020 Vintage On-Peak $29.01 $30.97 AL-TOU-2-P Summer Generation - 2020 Vintage On-Peak $0.17828 $0.19258 + $0.01 AL-TOU-2-P Summer Generation - 2020 Vintage Off-Peak $0.09441 $0.10305 + $0.01 201
AL-TOU-2-P Summer Generation - 2020 Vintage Super Off-Peak $0.07736 $0.08486 + $0.01 AL-TOU-2-P Winter Generation - 2020 Vintage On-Peak $0.19915 $0.21486 + $0.01 AL-TOU-2-P Winter Generation - 2020 Vintage Off-Peak $0.09692 $0.10573 + $0.01 AL-TOU-2-P Winter Generation - 2020 Vintage Super Off-Peak $0.06732 $0.07413 + $0.01 AL-TOU-2-T Summer Demand - 2020 Vintage On-Peak $27.77 $29.64 AL-TOU-2-T Summer Generation - 2020 Vintage On-Peak $0.16919 $0.18288 + $0.01 AL-TOU-2-T Summer Generation - 2020 Vintage Off-Peak $0.08895 $0.09722 + $0.01 AL-TOU-2-T Summer Generation - 2020 Vintage Super Off-Peak $0.07288 $0.08007 + $0.01 AL-TOU-2-T Winter Generation - 2020 Vintage On-Peak $0.18933 $0.20438 + $0.01 AL-TOU-2-T Winter Generation - 2020 Vintage Off-Peak $0.09155 $0.10000 + $0.01 AL-TOU-2-T Winter Generation - 2020 Vintage Super Off-Peak $0.06324 $0.06978 + $0.01 DG-R-M-S Summer Generation - 2020 Vintage On-Peak $0.53706 $0.57557 + $0.01 DG-R-M-S Summer Generation - 2020 Vintage Off-Peak $0.16531 $0.17873 + $0.01 DG-R-M-S Summer Generation - 2020 Vintage Super Off-Peak $0.06522 $0.07189 + $0.01 DG-R-M-S Winter Generation - 2020 Vintage On-Peak $0.17391 $0.18792 + $0.01 DG-R-M-S Winter Generation - 2020 Vintage Off-Peak $0.08271 $0.09056 + $0.01 DG-R-M-S Winter Generation - 2020 Vintage Super Off-Peak $0.05626 $0.06232 + $0.01 DG-R-M-P Summer Generation - 2020 Vintage On-Peak $0.53434 $0.57267 + $0.01 DG-R-M-P Summer Generation - 2020 Vintage Off-Peak $0.16440 $0.17777 + $0.01 DG-R-M-P Summer Generation - 2020 Vintage Super Off-Peak $0.06488 $0.07153 + $0.01 DG-R-M-P Winter Generation - 2020 Vintage On-Peak $0.17296 $0.18691 + $0.01 DG-R-M-P Winter Generation - 2020 Vintage Off-Peak $0.08223 $0.09005 + $0.01 DG-R-M-P Winter Generation - 2020 Vintage Super Off-Peak $0.05595 $0.06200 + $0.01 DG-R-L-S Summer Generation - 2020 Vintage On-Peak $0.51293 $0.54982 + $0.01 DG-R-L-S Summer Generation - 2020 Vintage Off-Peak $0.15697 $0.16983 + $0.01 DG-R-L-S Summer Generation - 2020 Vintage Super Off-Peak $0.06096 $0.06734 + $0.01 DG-R-L-S Winter Generation - 2020 Vintage On-Peak $0.16498 $0.17838 + $0.01 DG-R-L-S Winter Generation - 2020 Vintage Off-Peak $0.07770 $0.08522 + $0.01 DG-R-L-S Winter Generation - 2020 Vintage Super Off-Peak $0.05238 $0.05819 + $0.01 202
DG-R-L-P Summer Generation - 2020 Vintage On-Peak $0.51033 $0.54704 + $0.01 DG-R-L-P Summer Generation - 2020 Vintage Off-Peak $0.15609 $0.16890 + $0.01 DG-R-L-P Summer Generation - 2020 Vintage Super Off-Peak $0.06064 $0.06700 + $0.01 DG-R-L-P Winter Generation - 2020 Vintage On-Peak $0.16407 $0.17741 + $0.01 DG-R-L-P Winter Generation - 2020 Vintage Off-Peak $0.07724 $0.08472 + $0.01 DG-R-L-P Winter Generation - 2020 Vintage Super Off-Peak $0.05209 $0.05788 + $0.01 DG-R-L-T Summer Generation - 2020 Vintage On-Peak $0.48728 $0.52244 + $0.01 DG-R-L-T Summer Generation - 2020 Vintage Off-Peak $0.14809 $0.16036 + $0.01 DG-R-L-T Summer Generation - 2020 Vintage Super Off-Peak $0.05683 $0.06294 + $0.01 DG-R-L-T Winter Generation - 2020 Vintage On-Peak $0.15573 $0.16851 + $0.01 DG-R-L-T Winter Generation - 2020 Vintage Off-Peak $0.07269 $0.07986 + $0.01 DG-R-L-T Winter Generation - 2020 Vintage Super Off-Peak $0.04864 $0.05420 + $0.01 A6-TOU-P Summer Demand - 2020 Vintage Total $16.27 $17.37 A6-TOU-P Summer Generation - 2020 Vintage On-Peak $0.20000 $0.21577 + $0.01 A6-TOU-P Summer Generation - 2020 Vintage Off-Peak $0.10741 $0.11693 + $0.01 A6-TOU-P Summer Generation - 2020 Vintage Super Off-Peak $0.08895 $0.09722 + $0.01 A6-TOU-P Winter Generation - 2020 Vintage On-Peak $0.22343 $0.24078 + $0.01 A6-TOU-P Winter Generation - 2020 Vintage Off-Peak $0.11054 $0.12027 + $0.01 A6-TOU-P Winter Generation - 2020 Vintage Super Off-Peak $0.07784 $0.08537 + $0.01 A6-TOU-T Summer Demand - 2020 Vintage Total $15.57 $16.62 A6-TOU-T Summer Generation - 2020 Vintage On-Peak $0.18998 $0.20507 + $0.01 A6-TOU-T Summer Generation - 2020 Vintage Off-Peak $0.10141 $0.11052 + $0.01 A6-TOU-T Summer Generation - 2020 Vintage Super Off-Peak $0.08400 $0.09194 + $0.01 A6-TOU-T Winter Generation - 2020 Vintage On-Peak $0.21259 $0.22921 + $0.01 A6-TOU-T Winter Generation - 2020 Vintage Off-Peak $0.10461 $0.11395 + $0.01 A6-TOU-T Winter Generation - 2020 Vintage Super Off-Peak $0.07335 $0.08058 + $0.01 TOU-PA-S Summer Generation - 2020 Vintage On-Peak $0.23910 $0.25732 + $0.01 TOU-PA-S Summer Generation - 2020 Vintage Off-Peak $0.11828 $0.12835 + $0.01 TOU-PA-S Winter Generation - 2020 Vintage On-Peak $0.10921 $0.11866 + $0.01 TOU-PA-S Winter Generation - 2020 Vintage Off-Peak $0.03740 $0.04200 + $0.01 203
TOU-PA-P Summer Generation - 2020 Vintage On-Peak $0.23776 $0.25589 + $0.01 TOU-PA-P Summer Generation - 2020 Vintage Off-Peak $0.11754 $0.12755 + $0.01 TOU-PA-P Winter Generation - 2020 Vintage On-Peak $0.10855 $0.11795 + $0.01 TOU-PA-P Winter Generation - 2020 Vintage Off-Peak $0.03714 $0.04173 + $0.01 TOU-PA-2-S Summer Demand - 2020 Vintage On-Peak $11.24 $12.00 TOU-PA-2-S Summer Generation - 2020 Vintage On-Peak $0.11707 $0.12706 + $0.01 TOU-PA-2-S Summer Generation - 2020 Vintage Off-Peak $0.05879 $0.06484 + $0.01 TOU-PA-2-S Summer Generation - 2020 Vintage Super Off-Peak $0.04477 $0.04987 + $0.01 TOU-PA-2-S Winter Generation - 2020 Vintage On-Peak $0.12785 $0.13856 + $0.01 TOU-PA-2-S Winter Generation - 2020 Vintage Off-Peak $0.05813 $0.06414 + $0.01 TOU-PA-2-S Winter Generation - 2020 Vintage Super Off-Peak $0.03791 $0.04255 + $0.01 TOU-PA-2-P Summer Demand - 2020 Vintage On-Peak $11.19 $11.94 TOU-PA-2-P Summer Generation - 2020 Vintage On-Peak $0.11639 $0.12632 + $0.01 TOU-PA-2-P Summer Generation - 2020 Vintage Off-Peak $0.05839 $0.06441 + $0.01 TOU-PA-2-P Summer Generation - 2020 Vintage Super Off-Peak $0.04451 $0.04960 + $0.01 TOU-PA-2-P Winter Generation - 2020 Vintage On-Peak $0.12712 $0.13778 + $0.01 TOU-PA-2-P Winter Generation - 2020 Vintage Off-Peak $0.05776 $0.06374 + $0.01 TOU-PA-2-P Winter Generation - 2020 Vintage Super Off-Peak $0.03767 $0.04230 + $0.01 TOU-PA-3-S <20kW Summer Generation - 2020 Vintage On-Peak $0.27941 $0.30035 + $0.01 TOU-PA-3-S <20kW Summer Generation - 2020 Vintage Off-Peak $0.13701 $0.14833 + $0.01 TOU-PA-3-S <20kW Summer Generation - 2020 Vintage Super Off-Peak $0.04914 $0.05453 + $0.01 TOU-PA-3-S <20kW Winter Generation - 2020 Vintage On-Peak $0.09922 $0.10800 + $0.01 TOU-PA-3-S <20kW Winter Generation - 2020 Vintage Off-Peak $0.04208 $0.04700 + $0.01 TOU-PA-3-S <20kW Winter Generation - 2020 Vintage Super Off-Peak $0.02550 $0.02931 + $0.01 TOU-PA-3-P <20kW Summer Generation - 2020 Vintage On-Peak $0.27791 $0.29875 + $0.01 TOU-PA-3-P <20kW Summer Generation - 2020 Vintage Off-Peak $0.13620 $0.14747 + $0.01 TOU-PA-3-P <20kW Summer Generation - 2020 Vintage Super Off-Peak $0.04875 $0.05412 + $0.01 TOU-PA-3-P <20kW Winter Generation - 2020 Vintage On-Peak $0.09862 $0.10736 + $0.01 TOU-PA-3-P <20kW Winter Generation - 2020 Vintage Off-Peak $0.04178 $0.04668 + $0.01 204
TOU-PA-3-P <20kW Winter Generation - 2020 Vintage Super Off-Peak $0.02532 $0.02911 + $0.01 TOU-PA-3-S >=20kW Summer Demand - 2020 Vintage On-Peak $2.70 $2.89 TOU-PA-3-S >=20kW Summer Generation - 2020 Vintage On-Peak $0.25530 $0.27461 + $0.01 TOU-PA-3-S >=20kW Summer Generation - 2020 Vintage Off-Peak $0.12064 $0.13086 + $0.01 TOU-PA-3-S >=20kW Summer Generation - 2020 Vintage Super Off-Peak $0.04140 $0.04628 + $0.01 TOU-PA-3-S >=20kW Winter Generation - 2020 Vintage On-Peak $0.09328 $0.10166 + $0.01 TOU-PA-3-S >=20kW Winter Generation - 2020 Vintage Off-Peak $0.03875 $0.04345 + $0.01 TOU-PA-3-S >=20kW Winter Generation - 2020 Vintage Super Off-Peak $0.02292 $0.02655 + $0.01 TOU-PA-3-P >=20kW Summer Demand - 2020 Vintage On-Peak $2.69 $2.87 TOU-PA-3-P >=20kW Summer Generation - 2020 Vintage On-Peak $0.25394 $0.27316 + $0.01 TOU-PA-3-P >=20kW Summer Generation - 2020 Vintage Off-Peak $0.11993 $0.13010 + $0.01 TOU-PA-3-P >=20kW Summer Generation - 2020 Vintage Super Off-Peak $0.04105 $0.04591 + $0.01 TOU-PA-3-P >=20kW Winter Generation - 2020 Vintage On-Peak $0.09268 $0.10102 + $0.01 TOU-PA-3-P >=20kW Winter Generation - 2020 Vintage Off-Peak $0.03841 $0.04309 + $0.01 TOU-PA-3-P >=20kW Winter Generation - 2020 Vintage Super Off-Peak $0.02267 $0.02628 + $0.01 PA-T-1-S Summer Demand - 2020 Vintage On-Peak $6.29 $6.72 PA-T-1-S Summer Generation - 2020 Vintage On-Peak $0.12426 $0.13472 + $0.01 PA-T-1-S Summer Generation - 2020 Vintage Off-Peak $0.06323 $0.06958 + $0.01 PA-T-1-S Summer Generation - 2020 Vintage Super Off-Peak $0.04987 $0.05532 + $0.01 PA-T-1-S Winter Generation - 2020 Vintage On-Peak $0.13858 $0.15001 + $0.01 PA-T-1-S Winter Generation - 2020 Vintage Off-Peak $0.06415 $0.07056 + $0.01 PA-T-1-S Winter Generation - 2020 Vintage Super Off-Peak $0.04256 $0.04751 + $0.01 PA-T-1-P Summer Demand - 2020 Vintage On-Peak $6.26 $6.68 PA-T-1-P Summer Generation - 2020 Vintage On-Peak $0.12351 $0.13393 + $0.01 PA-T-1-P Summer Generation - 2020 Vintage Off-Peak $0.06279 $0.06911 + $0.01 PA-T-1-P Summer Generation - 2020 Vintage Super Off-Peak $0.04960 $0.05503 + $0.01 PA-T-1-P Winter Generation - 2020 Vintage On-Peak $0.13781 $0.14919 + $0.01 PA-T-1-P Winter Generation - 2020 Vintage Off-Peak $0.06376 $0.07015 + $0.01 PA-T-1-P Winter Generation - 2020 Vintage Super Off-Peak $0.04232 $0.04725 + $0.01 205
PA-T-1-T Summer Demand - 2020 Vintage On-Peak $5.99 $6.40 PA-T-1-T Summer Generation - 2020 Vintage On-Peak $0.11689 $0.12686 + $0.01 PA-T-1-T Summer Generation - 2020 Vintage Off-Peak $0.05880 $0.06485 + $0.01 PA-T-1-T Summer Generation - 2020 Vintage Super Off-Peak $0.04635 $0.05156 + $0.01 PA-T-1-T Winter Generation - 2020 Vintage On-Peak $0.13069 $0.14160 + $0.01 PA-T-1-T Winter Generation - 2020 Vintage Off-Peak $0.05988 $0.06600 + $0.01 PA-T-1-T Winter Generation - 2020 Vintage Super Off-Peak $0.03936 $0.04410 + $0.01 LS All Generation - 2020 Vintage Total $0.07950 $0.08670 + $0.01 OL-2 All Generation - 2020 Vintage Total $0.07950 $0.08670 + $0.01 LS-2-AD Summer Generation - 2020 Vintage On-Peak $0.27522 $0.29563 + $0.01 LS-2-AD Summer Generation - 2020 Vintage Off-Peak $0.15722 $0.16966 + $0.01 LS-2-AD Summer Generation - 2020 Vintage Super Off-Peak $0.05191 $0.05725 + $0.01 LS-2-AD Winter Generation - 2020 Vintage On-Peak $0.13430 $0.14520 + $0.01 LS-2-AD Winter Generation - 2020 Vintage Off-Peak $0.06403 $0.07018 + $0.01 LS-2-AD Winter Generation - 2020 Vintage Super Off-Peak $0.04328 $0.04804 + $0.01 G-TOU-M Summer Generation - 2020 Vintage On-Peak $0.16897 $0.18264 + $0.01 G-TOU-M Summer Generation - 2020 Vintage Semi-Peak $0.16374 $0.17706 + $0.01 G-TOU-M Summer Generation - 2020 Vintage Off-Peak $0.15849 $0.17145 + $0.01 G-TOU-M Winter Generation - 2020 Vintage On-Peak $0.16734 $0.18091 + $0.01 G-TOU-M Winter Generation - 2020 Vintage Semi-Peak $0.06054 $0.06690 + $0.01 G-TOU-M Winter Generation - 2020 Vintage Off-Peak $0.06052 $0.06688 + $0.01 G-OL-TOU Summer Generation - 2020 Vintage On-Peak $0.14126 $0.15306 + $0.01 G-OL-TOU Summer Generation - 2020 Vintage Semi-Peak $0.13498 $0.14636 + $0.01 G-OL-TOU Summer Generation - 2020 Vintage Off-Peak $0.13010 $0.14115 + $0.01 G-OL-TOU Winter Generation - 2020 Vintage On-Peak $0.34583 $0.37144 + $0.01 G-OL-TOU Winter Generation - 2020 Vintage Semi-Peak $0.14419 $0.15619 + $0.01 G-OL-TOU Winter Generation - 2020 Vintage Off-Peak $0.14417 $0.15617 + $0.01 G-TOU-A-S Summer Generation - 2020 Vintage On-Peak $0.31505 $0.33806 + $0.01 206
G-TOU-A-S Summer Generation - 2020 Vintage Semi-Peak $0.16855 $0.18168 + $0.01 G-TOU-A-S Summer Generation - 2020 Vintage Off-Peak $0.06312 $0.06913 + $0.01 G-TOU-A-S Winter Generation - 2020 Vintage On-Peak $0.17014 $0.18337 + $0.01 G-TOU-A-S Winter Generation - 2020 Vintage Semi-Peak $0.06686 $0.07312 + $0.01 G-TOU-A-S Winter Generation - 2020 Vintage Off-Peak $0.06638 $0.07261 + $0.01 G-TOU-A-P Summer Generation - 2020 Vintage On-Peak $0.31325 $0.33614 + $0.01 G-TOU-A-P Summer Generation - 2020 Vintage Semi-Peak $0.16753 $0.18059 + $0.01 G-TOU-A-P Summer Generation - 2020 Vintage Off-Peak $0.06266 $0.06864 + $0.01 G-TOU-A-P Winter Generation - 2020 Vintage On-Peak $0.16919 $0.18236 + $0.01 G-TOU-A-P Winter Generation - 2020 Vintage Semi-Peak $0.06645 $0.07268 + $0.01 G-TOU-A-P Winter Generation - 2020 Vintage Off-Peak $0.06597 $0.07217 + $0.01 G-AL-TOU-M-S Summer Demand - 2020 Vintage On-Peak $1.75 $1.87 G-AL-TOU-M-S Summer Generation - 2020 Vintage On-Peak $0.10525 $0.11462 + $0.01 G-AL-TOU-M-S Summer Generation - 2020 Vintage Semi-Peak $0.10492 $0.11427 + $0.01 G-AL-TOU-M-S Summer Generation - 2020 Vintage Off-Peak $0.10147 $0.11059 + $0.01 G-AL-TOU-M-S Winter Generation - 2020 Vintage On-Peak $0.38600 $0.41432 + $0.01 G-AL-TOU-M-S Winter Generation - 2020 Vintage Semi-Peak $0.16302 $0.17629 + $0.01 G-AL-TOU-M-S Winter Generation - 2020 Vintage Off-Peak $0.16300 $0.17628 + $0.01 G-AL-TOU-M-P Summer Demand - 2020 Vintage On-Peak $1.74 $1.86 G-AL-TOU-M-P Summer Generation - 2020 Vintage On-Peak $0.10452 $0.11384 + $0.01 G-AL-TOU-M-P Summer Generation - 2020 Vintage Semi-Peak $0.10419 $0.11349 + $0.01 G-AL-TOU-M-P Summer Generation - 2020 Vintage Off-Peak $0.10076 $0.10983 + $0.01 G-AL-TOU-M-P Winter Generation - 2020 Vintage On-Peak $0.38398 $0.41216 + $0.01 G-AL-TOU-M-P Winter Generation - 2020 Vintage Semi-Peak $0.16215 $0.17536 + $0.01 G-AL-TOU-M-P Winter Generation - 2020 Vintage Off-Peak $0.16213 $0.17535 + $0.01 G-AL-TOU-L-S Summer Demand - 2020 Vintage On-Peak $1.65 $1.77 G-AL-TOU-L-S Summer Generation - 2020 Vintage On-Peak $0.09592 $0.10466 + $0.01 G-AL-TOU-L-S Summer Generation - 2020 Vintage Semi-Peak $0.09559 $0.10431 + $0.01 G-AL-TOU-L-S Summer Generation - 2020 Vintage Off-Peak $0.09214 $0.10063 + $0.01 G-AL-TOU-L-S Winter Generation - 2020 Vintage On-Peak $0.35705 $0.38342 + $0.01 207
G-AL-TOU-L-S Winter Generation - 2020 Vintage Semi-Peak $0.14945 $0.16181 + $0.01 G-AL-TOU-L-S Winter Generation - 2020 Vintage Off-Peak $0.14944 $0.16179 + $0.01 G-AL-TOU-L-P Summer Demand - 2020 Vintage On-Peak $1.64 $1.76 G-AL-TOU-L-P Summer Generation - 2020 Vintage On-Peak $0.09523 $0.10393 + $0.01 G-AL-TOU-L-P Summer Generation - 2020 Vintage Semi-Peak $0.09491 $0.10359 + $0.01 G-AL-TOU-L-P Summer Generation - 2020 Vintage Off-Peak $0.09148 $0.09993 + $0.01 G-AL-TOU-L-P Winter Generation - 2020 Vintage On-Peak $0.35516 $0.38140 + $0.01 G-AL-TOU-L-P Winter Generation - 2020 Vintage Semi-Peak $0.14864 $0.16095 + $0.01 G-AL-TOU-L-P Winter Generation - 2020 Vintage Off-Peak $0.14863 $0.16093 + $0.01 G-AL-TOU-L-T Summer Demand - 2020 Vintage On-Peak $1.57 $1.68 G-AL-TOU-L-T Summer Generation - 2020 Vintage On-Peak $0.08952 $0.09783 + $0.01 G-AL-TOU-L-T Summer Generation - 2020 Vintage Semi-Peak $0.08922 $0.09751 + $0.01 G-AL-TOU-L-T Summer Generation - 2020 Vintage Off-Peak $0.08593 $0.09400 + $0.01 G-AL-TOU-L-T Winter Generation - 2020 Vintage On-Peak $0.33849 $0.36360 + $0.01 G-AL-TOU-L-T Winter Generation - 2020 Vintage Semi-Peak $0.14105 $0.15284 + $0.01 G-AL-TOU-L-T Winter Generation - 2020 Vintage Off-Peak $0.14103 $0.15282 + $0.01 G-DG-R-M-S Summer Generation - 2020 Vintage On-Peak $0.14057 $0.15233 + $0.01 G-DG-R-M-S Summer Generation - 2020 Vintage Semi-Peak $0.13536 $0.14677 + $0.01 G-DG-R-M-S Summer Generation - 2020 Vintage Off-Peak $0.13010 $0.14115 + $0.01 G-DG-R-M-S Winter Generation - 2020 Vintage On-Peak $0.34583 $0.37144 + $0.01 G-DG-R-M-S Winter Generation - 2020 Vintage Semi-Peak $0.14419 $0.15619 + $0.01 G-DG-R-M-S Winter Generation - 2020 Vintage Off-Peak $0.14417 $0.15617 + $0.01 G-DG-R-M-P Summer Generation - 2020 Vintage On-Peak $0.13969 $0.15139 + $0.01 G-DG-R-M-P Summer Generation - 2020 Vintage Semi-Peak $0.13448 $0.14583 + $0.01 G-DG-R-M-P Summer Generation - 2020 Vintage Off-Peak $0.12924 $0.14024 + $0.01 G-DG-R-M-P Winter Generation - 2020 Vintage On-Peak $0.34399 $0.36948 + $0.01 G-DG-R-M-P Winter Generation - 2020 Vintage Semi-Peak $0.14341 $0.15536 + $0.01 G-DG-R-M-P Winter Generation - 2020 Vintage Off-Peak $0.14339 $0.15534 + $0.01 G-DG-R-L-S Summer Generation - 2020 Vintage On-Peak $0.12927 $0.14027 + $0.01 208
G-DG-R-L-S Summer Generation - 2020 Vintage Semi-Peak $0.12406 $0.13470 + $0.01 G-DG-R-L-S Summer Generation - 2020 Vintage Off-Peak $0.11881 $0.12909 + $0.01 G-DG-R-L-S Winter Generation - 2020 Vintage On-Peak $0.31965 $0.34349 + $0.01 G-DG-R-L-S Winter Generation - 2020 Vintage Semi-Peak $0.13192 $0.14309 + $0.01 G-DG-R-L-S Winter Generation - 2020 Vintage Off-Peak $0.13190 $0.14308 + $0.01 G-DG-R-L-P Summer Generation - 2020 Vintage On-Peak $0.12845 $0.13939 + $0.01 G-DG-R-L-P Summer Generation - 2020 Vintage Semi-Peak $0.12324 $0.13383 + $0.01 G-DG-R-L-P Summer Generation - 2020 Vintage Off-Peak $0.11800 $0.12824 + $0.01 G-DG-R-L-P Winter Generation - 2020 Vintage On-Peak $0.31794 $0.34167 + $0.01 G-DG-R-L-P Winter Generation - 2020 Vintage Semi-Peak $0.13119 $0.14232 + $0.01 G-DG-R-L-P Winter Generation - 2020 Vintage Off-Peak $0.13117 $0.14230 + $0.01 G-DG-R-L-T Summer Generation - 2020 Vintage On-Peak $0.12155 $0.13203 + $0.01 G-DG-R-L-T Summer Generation - 2020 Vintage Semi-Peak $0.11636 $0.12648 + $0.01 G-DG-R-L-T Summer Generation - 2020 Vintage Off-Peak $0.11127 $0.12105 + $0.01 G-DG-R-L-T Winter Generation - 2020 Vintage On-Peak $0.30287 $0.32558 + $0.01 G-DG-R-L-T Winter Generation - 2020 Vintage Semi-Peak $0.12433 $0.13499 + $0.01 G-DG-R-L-T Winter Generation - 2020 Vintage Off-Peak $0.12431 $0.13497 + $0.01 G-A6-TOU-P Summer Demand - 2020 Vintage Total $1.64 $1.76 G-A6-TOU-P Summer Generation - 2020 Vintage On-Peak $0.09523 $0.10393 + $0.01 G-A6-TOU-P Summer Generation - 2020 Vintage Semi-Peak $0.09491 $0.10359 + $0.01 G-A6-TOU-P Summer Generation - 2020 Vintage Off-Peak $0.09148 $0.09993 + $0.01 G-A6-TOU-P Winter Generation - 2020 Vintage On-Peak $0.35516 $0.38140 + $0.01 G-A6-TOU-P Winter Generation - 2020 Vintage Semi-Peak $0.14864 $0.16095 + $0.01 G-A6-TOU-P Winter Generation - 2020 Vintage Off-Peak $0.14863 $0.16093 + $0.01 G-A6-TOU-T Summer Demand - 2020 Vintage Total $1.57 $1.68 G-A6-TOU-T Summer Generation - 2020 Vintage On-Peak $0.08952 $0.09783 + $0.01 G-A6-TOU-T Summer Generation - 2020 Vintage Semi-Peak $0.08922 $0.09751 + $0.01 G-A6-TOU-T Summer Generation - 2020 Vintage Off-Peak $0.08593 $0.09400 + $0.01 G-A6-TOU-T Winter Generation - 2020 Vintage On-Peak $0.33849 $0.36360 + $0.01 G-A6-TOU-T Winter Generation - 2020 Vintage Semi-Peak $0.14105 $0.15284 + $0.01 209
G-A6-TOU-T Winter Generation - 2020 Vintage Off-Peak $0.14103 $0.15282 + $0.01 G-PA-T-1-S Summer Demand - 2020 Vintage On-Peak $0.63 $0.67 G-PA-T-1-S Summer Generation - 2020 Vintage On-Peak $0.05564 $0.06148 + $0.01 G-PA-T-1-S Summer Generation - 2020 Vintage Semi-Peak $0.05541 $0.06123 + $0.01 G-PA-T-1-S Summer Generation - 2020 Vintage Off-Peak $0.05162 $0.05718 + $0.01 G-PA-T-1-S Winter Generation - 2020 Vintage On-Peak $0.21105 $0.22738 + $0.01 G-PA-T-1-S Winter Generation - 2020 Vintage Semi-Peak $0.08254 $0.09019 + $0.01 G-PA-T-1-S Winter Generation - 2020 Vintage Off-Peak $0.08252 $0.09017 + $0.01 G-PA-T-1-P Summer Demand - 2020 Vintage On-Peak $0.63 $0.67 G-PA-T-1-P Summer Generation - 2020 Vintage On-Peak $0.05066 $0.05616 + $0.01 G-PA-T-1-P Summer Generation - 2020 Vintage Semi-Peak $0.05042 $0.05591 + $0.01 G-PA-T-1-P Summer Generation - 2020 Vintage Off-Peak $0.04665 $0.05188 + $0.01 G-PA-T-1-P Winter Generation - 2020 Vintage On-Peak $0.20988 $0.22612 + $0.01 G-PA-T-1-P Winter Generation - 2020 Vintage Semi-Peak $0.08204 $0.08966 + $0.01 G-PA-T-1-P Winter Generation - 2020 Vintage Off-Peak $0.08201 $0.08963 + $0.01 G-PA-T-1-T Summer Demand - 2020 Vintage On-Peak $0.60 $0.65 G-PA-T-1-T Summer Generation - 2020 Vintage On-Peak $0.05138 $0.05692 + $0.01 G-PA-T-1-T Summer Generation - 2020 Vintage Semi-Peak $0.05116 $0.05670 + $0.01 G-PA-T-1-T Summer Generation - 2020 Vintage Off-Peak $0.04754 $0.05283 + $0.01 G-PA-T-1-T Winter Generation - 2020 Vintage On-Peak $0.20851 $0.22466 + $0.01 G-PA-T-1-T Winter Generation - 2020 Vintage Semi-Peak $0.08145 $0.08902 + $0.01 G-PA-T-1-T Winter Generation - 2020 Vintage Off-Peak $0.08142 $0.08900 + $0.01 G-TOU-PA-S < 20kW Summer Generation - 2020 Vintage On-Peak $0.31227 $0.33542 + $0.01 G-TOU-PA-S < 20kW Summer Generation - 2020 Vintage Semi-Peak $0.12289 $0.13326 + $0.01 G-TOU-PA-S < 20kW Summer Generation - 2020 Vintage Off-Peak $0.05761 $0.06358 + $0.01 G-TOU-PA-S < 20kW Winter Generation - 2020 Vintage On-Peak $0.11936 $0.12949 + $0.01 G-TOU-PA-S < 20kW Winter Generation - 2020 Vintage Semi-Peak $0.03956 $0.04431 + $0.01 G-TOU-PA-S < 20kW Winter Generation - 2020 Vintage Off-Peak $0.03954 $0.04429 + $0.01 G-TOU-PA-P < 20kW Summer Generation - 2020 Vintage On-Peak $0.31047 $0.33350 + $0.01 210
G-TOU-PA-P < 20kW Summer Generation - 2020 Vintage Semi-Peak $0.12208 $0.13240 + $0.01 G-TOU-PA-P < 20kW Summer Generation - 2020 Vintage Off-Peak $0.05714 $0.06307 + $0.01 G-TOU-PA-P < 20kW Winter Generation - 2020 Vintage On-Peak $0.11857 $0.12865 + $0.01 G-TOU-PA-P < 20kW Winter Generation - 2020 Vintage Semi-Peak $0.03919 $0.04391 + $0.01 G-TOU-PA-P < 20kW Winter Generation - 2020 Vintage Off-Peak $0.03917 $0.04389 + $0.01 G-TOU-PA-S >= 20kW Summer Demand - 2020 Vintage On-Peak $1.00 $1.06 G-TOU-PA-S >= 20kW Summer Generation - 2020 Vintage On-Peak $0.06205 $0.06832 + $0.01 G-TOU-PA-S >= 20kW Summer Generation - 2020 Vintage Semi-Peak $0.06100 $0.06719 + $0.01 G-TOU-PA-S >= 20kW Summer Generation - 2020 Vintage Off-Peak $0.05548 $0.06131 + $0.01 G-TOU-PA-S >= 20kW Winter Generation - 2020 Vintage On-Peak $0.23080 $0.24846 + $0.01 G-TOU-PA-S >= 20kW Winter Generation - 2020 Vintage Semi-Peak $0.09179 $0.10006 + $0.01 G-TOU-PA-S >= 20kW Winter Generation - 2020 Vintage Off-Peak $0.09177 $0.10004 + $0.01 G-TOU-PA-P >= 20kW Summer Demand - 2020 Vintage On-Peak $0.99 $1.05 G-TOU-PA-P >= 20kW Summer Generation - 2020 Vintage On-Peak $0.06159 $0.06783 + $0.01 G-TOU-PA-P >= 20kW Summer Generation - 2020 Vintage Semi-Peak $0.06053 $0.06670 + $0.01 G-TOU-PA-P >= 20kW Summer Generation - 2020 Vintage Off-Peak $0.05517 $0.06098 + $0.01 G-TOU-PA-P >= 20kW Winter Generation - 2020 Vintage On-Peak $0.22954 $0.24711 + $0.01 G-TOU-PA-P >= 20kW Winter Generation - 2020 Vintage Semi-Peak $0.09125 $0.09949 + $0.01 G-TOU-PA-P >= 20kW Winter Generation - 2020 Vintage Off-Peak $0.09124 $0.09947 + $0.01 EV-HP-S Summer Demand - 2020 Vintage On-Peak $8.26 $8.82 EV-HP-S Summer Generation - 2020 Vintage On-Peak $0.08526 $0.09328 + $0.01 EV-HP-S Summer Generation - 2020 Vintage Off-Peak $0.03782 $0.04264 + $0.01 EV-HP-S Summer Generation - 2020 Vintage Super Off-Peak $0.02916 $0.03339 + $0.01 EV-HP-S Winter Generation - 2020 Vintage On-Peak $0.09821 $0.10711 + $0.01 EV-HP-S Winter Generation - 2020 Vintage Off-Peak $0.04027 $0.04526 + $0.01 EV-HP-S Winter Generation - 2020 Vintage Super Off-Peak $0.02346 $0.02731 + $0.01 EV-HP-P Summer Demand - 2020 Vintage On-Peak $8.22 $8.77 EV-HP-P Summer Generation - 2020 Vintage On-Peak $0.08468 $0.09267 + $0.01 EV-HP-P Summer Generation - 2020 Vintage Off-Peak $0.03749 $0.04229 + $0.01 EV-HP-P Summer Generation - 2020 Vintage Super Off-Peak $0.02894 $0.03317 + $0.01 211
EV-HP-P Winter Generation - 2020 Vintage On-Peak $0.09761 $0.10647 + $0.01 EV-HP-P Winter Generation - 2020 Vintage Off-Peak $0.03996 $0.04493 + $0.01 EV-HP-P Winter Generation - 2020 Vintage Super Off-Peak $0.02327 $0.02711 + $0.01 TOU-ELEC Summer Generation - 2020 Vintage On-Peak $0.37019 $0.39760 + $0.01 TOU-ELEC Summer Generation - 2020 Vintage Off-Peak $0.07905 $0.08681 + $0.01 TOU-ELEC Summer Generation - 2020 Vintage Super Off-Peak $0.04074 $0.04593 + $0.01 TOU-ELEC Winter Generation - 2020 Vintage On-Peak $0.18010 $0.19469 + $0.01 TOU-ELEC Winter Generation - 2020 Vintage Off-Peak $0.06863 $0.07570 + $0.01 TOU-ELEC Winter Generation - 2020 Vintage Super Off-Peak $0.03380 $0.03851 + $0.01 CCA Rate Name Season Charge Type Time of Use Period PowerBase PowerOn Power100 ($/kWh) DR Summer Generation - 2021 Vintage Total $0.12684 $0.13780 + $0.01 DR Winter Generation - 2021 Vintage Total $0.12684 $0.13780 + $0.01 DR-LI-MB Summer Generation - 2021 Vintage Total $0.12684 $0.13780 + $0.01 DR-LI-MB Winter Generation - 2021 Vintage Total $0.12684 $0.13780 + $0.01 DR-SES Summer Generation - 2021 Vintage On-Peak $0.38242 $0.41063 + $0.01 DR-SES Summer Generation - 2021 Vintage Off-Peak $0.11828 $0.12866 + $0.01 DR-SES Summer Generation - 2021 Vintage Super Off-Peak $0.03680 $0.04168 + $0.01 DR-SES Winter Generation - 2021 Vintage On-Peak $0.14210 $0.15409 + $0.01 DR-SES Winter Generation - 2021 Vintage Off-Peak $0.09183 $0.10044 + $0.01 DR-SES Winter Generation - 2021 Vintage Super Off-Peak $0.03024 $0.03469 + $0.01 EV-TOU Summer Generation - 2021 Vintage On-Peak $0.38242 $0.41063 + $0.01 EV-TOU Summer Generation - 2021 Vintage Off-Peak $0.11828 $0.12866 + $0.01 EV-TOU Summer Generation - 2021 Vintage Super Off-Peak $0.03680 $0.04168 + $0.01 EV-TOU Winter Generation - 2021 Vintage On-Peak $0.14210 $0.15409 + $0.01 EV-TOU Winter Generation - 2021 Vintage Off-Peak $0.09183 $0.10044 + $0.01 EV-TOU Winter Generation - 2021 Vintage Super Off-Peak $0.03024 $0.03469 + $0.01 EV-TOU-2 Summer Generation - 2021 Vintage On-Peak $0.38242 $0.41063 + $0.01 EV-TOU-2 Summer Generation - 2021 Vintage Off-Peak $0.11828 $0.12866 + $0.01 212
EV-TOU-2 Summer Generation - 2021 Vintage Super Off-Peak $0.03680 $0.04168 + $0.01 EV-TOU-2 Winter Generation - 2021 Vintage On-Peak $0.14210 $0.15409 + $0.01 EV-TOU-2 Winter Generation - 2021 Vintage Off-Peak $0.09183 $0.10044 + $0.01 EV-TOU-2 Winter Generation - 2021 Vintage Super Off-Peak $0.03024 $0.03469 + $0.01 EV-TOU-5 Summer Generation - 2021 Vintage On-Peak $0.38242 $0.41063 + $0.01 EV-TOU-5 Summer Generation - 2021 Vintage Off-Peak $0.11828 $0.12866 + $0.01 EV-TOU-5 Summer Generation - 2021 Vintage Super Off-Peak $0.03680 $0.04168 + $0.01 EV-TOU-5 Winter Generation - 2021 Vintage On-Peak $0.14210 $0.15409 + $0.01 EV-TOU-5 Winter Generation - 2021 Vintage Off-Peak $0.09183 $0.10044 + $0.01 EV-TOU-5 Winter Generation - 2021 Vintage Super Off-Peak $0.03024 $0.03469 + $0.01 TOU-DR-1 Summer Generation - 2021 Vintage On-Peak $0.27484 $0.29579 + $0.01 TOU-DR-1 Summer Generation - 2021 Vintage Off-Peak $0.07864 $0.08635 + $0.01 TOU-DR-1 Summer Generation - 2021 Vintage Super Off-Peak $0.01000 $0.01000 + $0.01 TOU-DR-1 Winter Generation - 2021 Vintage On-Peak $0.20865 $0.22513 + $0.01 TOU-DR-1 Winter Generation - 2021 Vintage Off-Peak $0.13600 $0.14758 + $0.01 TOU-DR-1 Winter Generation - 2021 Vintage Super Off-Peak $0.05530 $0.06144 + $0.01 TOU-DR-2 Summer Generation - 2021 Vintage On-Peak $0.27484 $0.29579 + $0.01 TOU-DR-2 Summer Generation - 2021 Vintage Off-Peak $0.03933 $0.04439 + $0.01 TOU-DR-2 Winter Generation - 2021 Vintage On-Peak $0.20865 $0.22513 + $0.01 TOU-DR-2 Winter Generation - 2021 Vintage Off-Peak $0.08685 $0.09512 + $0.01 TOU-DR Summer Generation - 2021 Vintage On-Peak $0.16792 $0.18166 + $0.01 TOU-DR Summer Generation - 2021 Vintage Off-Peak $0.11557 $0.12578 + $0.01 TOU-DR Summer Generation - 2021 Vintage Super Off-Peak $0.06623 $0.07310 + $0.01 TOU-DR Winter Generation - 2021 Vintage On-Peak $0.20845 $0.22492 + $0.01 TOU-DR Winter Generation - 2021 Vintage Off-Peak $0.13585 $0.14743 + $0.01 TOU-DR Winter Generation - 2021 Vintage Super Off-Peak $0.05523 $0.06136 + $0.01 TOU-A-S Summer Generation - 2021 Vintage On-Peak $0.27406 $0.29427 + $0.01 TOU-A-S Summer Generation - 2021 Vintage Off-Peak $0.13837 $0.14941 + $0.01 TOU-A-S Winter Generation - 2021 Vintage On-Peak $0.14905 $0.16081 + $0.01 213
TOU-A-S Winter Generation - 2021 Vintage Off-Peak $0.06081 $0.06662 + $0.01 TOU-A-P Summer Generation - 2021 Vintage On-Peak $0.27256 $0.29266 + $0.01 TOU-A-P Summer Generation - 2021 Vintage Off-Peak $0.13755 $0.14854 + $0.01 TOU-A-P Winter Generation - 2021 Vintage On-Peak $0.14822 $0.15993 + $0.01 TOU-A-P Winter Generation - 2021 Vintage Off-Peak $0.06049 $0.06628 + $0.01 TOU-A-2-S Summer Generation - 2021 Vintage On-Peak $0.37800 $0.40522 + $0.01 TOU-A-2-S Summer Generation - 2021 Vintage Off-Peak $0.11368 $0.12307 + $0.01 TOU-A-2-S Summer Generation - 2021 Vintage Super Off-Peak $0.05266 $0.05793 + $0.01 TOU-A-2-S Winter Generation - 2021 Vintage On-Peak $0.13614 $0.14704 + $0.01 TOU-A-2-S Winter Generation - 2021 Vintage Off-Peak $0.06587 $0.07202 + $0.01 TOU-A-2-S Winter Generation - 2021 Vintage Super Off-Peak $0.04512 $0.04988 + $0.01 TOU-A-2-P Summer Generation - 2021 Vintage On-Peak $0.37606 $0.40314 + $0.01 TOU-A-2-P Summer Generation - 2021 Vintage Off-Peak $0.11304 $0.12238 + $0.01 TOU-A-2-P Summer Generation - 2021 Vintage Super Off-Peak $0.05241 $0.05765 + $0.01 TOU-A-2-P Winter Generation - 2021 Vintage On-Peak $0.13541 $0.14625 + $0.01 TOU-A-2-P Winter Generation - 2021 Vintage Off-Peak $0.06549 $0.07161 + $0.01 TOU-A-2-P Winter Generation - 2021 Vintage Super Off-Peak $0.04489 $0.04963 + $0.01 TOU-A-3-S Summer Generation - 2021 Vintage On-Peak $0.27706 $0.29747 + $0.01 TOU-A-3-S Summer Generation - 2021 Vintage Off-Peak $0.15906 $0.17150 + $0.01 TOU-A-3-S Summer Generation - 2021 Vintage Super Off-Peak $0.05375 $0.05909 + $0.01 TOU-A-3-S Winter Generation - 2021 Vintage On-Peak $0.13614 $0.14704 + $0.01 TOU-A-3-S Winter Generation - 2021 Vintage Off-Peak $0.06587 $0.07202 + $0.01 TOU-A-3-S Winter Generation - 2021 Vintage Super Off-Peak $0.04512 $0.04988 + $0.01 TOU-A-3-P Summer Generation - 2021 Vintage On-Peak $0.27560 $0.29591 + $0.01 TOU-A-3-P Summer Generation - 2021 Vintage Off-Peak $0.15817 $0.17055 + $0.01 TOU-A-3-P Summer Generation - 2021 Vintage Super Off-Peak $0.05338 $0.05869 + $0.01 TOU-A-3-P Winter Generation - 2021 Vintage On-Peak $0.13541 $0.14625 + $0.01 TOU-A-3-P Winter Generation - 2021 Vintage Off-Peak $0.06549 $0.07161 + $0.01 TOU-A-3-P Winter Generation - 2021 Vintage Super Off-Peak $0.04489 $0.04963 + $0.01 214
A-TC Summer Generation - 2021 Vintage Total $0.07167 $0.07821 + $0.01 A-TC Winter Generation - 2021 Vintage Total $0.07167 $0.07821 + $0.01 TOU-M Summer Generation - 2021 Vintage On-Peak $0.38927 $0.41775 + $0.01 TOU-M Summer Generation - 2021 Vintage Off-Peak $0.11252 $0.12233 + $0.01 TOU-M Summer Generation - 2021 Vintage Super Off-Peak $0.04542 $0.05070 + $0.01 TOU-M Winter Generation - 2021 Vintage On-Peak $0.13135 $0.14243 + $0.01 TOU-M Winter Generation - 2021 Vintage Off-Peak $0.05925 $0.06546 + $0.01 TOU-M Winter Generation - 2021 Vintage Super Off-Peak $0.03834 $0.04313 + $0.01 OL-TOU Summer Generation - 2021 Vintage On-Peak $0.53865 $0.57721 + $0.01 OL-TOU Summer Generation - 2021 Vintage Off-Peak $0.16585 $0.17925 + $0.01 OL-TOU Summer Generation - 2021 Vintage Super Off-Peak $0.06614 $0.07281 + $0.01 OL-TOU Winter Generation - 2021 Vintage On-Peak $0.17483 $0.18884 + $0.01 OL-TOU Winter Generation - 2021 Vintage Off-Peak $0.08363 $0.09148 + $0.01 OL-TOU Winter Generation - 2021 Vintage Super Off-Peak $0.05718 $0.06324 + $0.01 AL-TOU-M-S Summer Demand - 2021 Vintage On-Peak $17.06 $18.21 AL-TOU-M-S Summer Generation - 2021 Vintage On-Peak $0.21245 $0.22900 + $0.01 AL-TOU-M-S Summer Generation - 2021 Vintage Off-Peak $0.11521 $0.12519 + $0.01 AL-TOU-M-S Summer Generation - 2021 Vintage Super Off-Peak $0.09582 $0.10449 + $0.01 AL-TOU-M-S Winter Generation - 2021 Vintage On-Peak $0.23715 $0.25536 + $0.01 AL-TOU-M-S Winter Generation - 2021 Vintage Off-Peak $0.11857 $0.12878 + $0.01 AL-TOU-M-S Winter Generation - 2021 Vintage Super Off-Peak $0.08417 $0.09206 + $0.01 AL-TOU-M-P Summer Demand - 2021 Vintage On-Peak $16.98 $18.13 AL-TOU-M-P Summer Generation - 2021 Vintage On-Peak $0.21127 $0.22774 + $0.01 AL-TOU-M-P Summer Generation - 2021 Vintage Off-Peak $0.11452 $0.12446 + $0.01 AL-TOU-M-P Summer Generation - 2021 Vintage Super Off-Peak $0.09538 $0.10403 + $0.01 AL-TOU-M-P Winter Generation - 2021 Vintage On-Peak $0.23592 $0.25405 + $0.01 AL-TOU-M-P Winter Generation - 2021 Vintage Off-Peak $0.11794 $0.12811 + $0.01 AL-TOU-M-P Winter Generation - 2021 Vintage Super Off-Peak $0.08378 $0.09164 + $0.01 215
AL-TOU-L-S Summer Demand - 2021 Vintage On-Peak $16.34 $17.44 AL-TOU-L-S Summer Generation - 2021 Vintage On-Peak $0.20206 $0.21790 + $0.01 AL-TOU-L-S Summer Generation - 2021 Vintage Off-Peak $0.10898 $0.11855 + $0.01 AL-TOU-L-S Summer Generation - 2021 Vintage Super Off-Peak $0.09029 $0.09859 + $0.01 AL-TOU-L-S Winter Generation - 2021 Vintage On-Peak $0.22554 $0.24297 + $0.01 AL-TOU-L-S Winter Generation - 2021 Vintage Off-Peak $0.11205 $0.12182 + $0.01 AL-TOU-L-S Winter Generation - 2021 Vintage Super Off-Peak $0.07914 $0.08669 + $0.01 AL-TOU-L-P Summer Demand - 2021 Vintage On-Peak $16.27 $17.37 AL-TOU-L-P Summer Generation - 2021 Vintage On-Peak $0.20092 $0.21669 + $0.01 AL-TOU-L-P Summer Generation - 2021 Vintage Off-Peak $0.10833 $0.11785 + $0.01 AL-TOU-L-P Summer Generation - 2021 Vintage Super Off-Peak $0.08987 $0.09814 + $0.01 AL-TOU-L-P Winter Generation - 2021 Vintage On-Peak $0.22435 $0.24170 + $0.01 AL-TOU-L-P Winter Generation - 2021 Vintage Off-Peak $0.11146 $0.12119 + $0.01 AL-TOU-L-P Winter Generation - 2021 Vintage Super Off-Peak $0.07876 $0.08629 + $0.01 AL-TOU-L-T Summer Demand - 2021 Vintage On-Peak $15.57 $16.62 AL-TOU-L-T Summer Generation - 2021 Vintage On-Peak $0.19090 $0.20599 + $0.01 AL-TOU-L-T Summer Generation - 2021 Vintage Off-Peak $0.10233 $0.11144 + $0.01 AL-TOU-L-T Summer Generation - 2021 Vintage Super Off-Peak $0.08492 $0.09286 + $0.01 AL-TOU-L-T Winter Generation - 2021 Vintage On-Peak $0.21351 $0.23013 + $0.01 AL-TOU-L-T Winter Generation - 2021 Vintage Off-Peak $0.10553 $0.11487 + $0.01 AL-TOU-L-T Winter Generation - 2021 Vintage Super Off-Peak $0.07427 $0.08150 + $0.01 AL-TOU-2-S Summer Demand - 2021 Vintage On-Peak $29.15 $31.11 AL-TOU-2-S Summer Generation - 2021 Vintage On-Peak $0.18023 $0.19460 + $0.01 AL-TOU-2-S Summer Generation - 2021 Vintage Off-Peak $0.09592 $0.10461 + $0.01 AL-TOU-2-S Summer Generation - 2021 Vintage Super Off-Peak $0.07867 $0.08618 + $0.01 AL-TOU-2-S Winter Generation - 2021 Vintage On-Peak $0.20114 $0.21693 + $0.01 AL-TOU-2-S Winter Generation - 2021 Vintage Off-Peak $0.09838 $0.10723 + $0.01 AL-TOU-2-S Winter Generation - 2021 Vintage Super Off-Peak $0.06857 $0.07540 + $0.01 AL-TOU-2-P Summer Demand - 2021 Vintage On-Peak $29.01 $30.97 AL-TOU-2-P Summer Generation - 2021 Vintage On-Peak $0.17920 $0.19350 + $0.01 216
AL-TOU-2-P Summer Generation - 2021 Vintage Off-Peak $0.09533 $0.10397 + $0.01 AL-TOU-2-P Summer Generation - 2021 Vintage Super Off-Peak $0.07828 $0.08578 + $0.01 AL-TOU-2-P Winter Generation - 2021 Vintage On-Peak $0.20007 $0.21578 + $0.01 AL-TOU-2-P Winter Generation - 2021 Vintage Off-Peak $0.09784 $0.10665 + $0.01 AL-TOU-2-P Winter Generation - 2021 Vintage Super Off-Peak $0.06824 $0.07505 + $0.01 AL-TOU-2-T Summer Demand - 2021 Vintage On-Peak $27.77 $29.64 AL-TOU-2-T Summer Generation - 2021 Vintage On-Peak $0.17011 $0.18380 + $0.01 AL-TOU-2-T Summer Generation - 2021 Vintage Off-Peak $0.08987 $0.09814 + $0.01 AL-TOU-2-T Summer Generation - 2021 Vintage Super Off-Peak $0.07380 $0.08099 + $0.01 AL-TOU-2-T Winter Generation - 2021 Vintage On-Peak $0.19025 $0.20530 + $0.01 AL-TOU-2-T Winter Generation - 2021 Vintage Off-Peak $0.09247 $0.10092 + $0.01 AL-TOU-2-T Winter Generation - 2021 Vintage Super Off-Peak $0.06416 $0.07070 + $0.01 DG-R-M-S Summer Generation - 2021 Vintage On-Peak $0.53798 $0.57649 + $0.01 DG-R-M-S Summer Generation - 2021 Vintage Off-Peak $0.16623 $0.17965 + $0.01 DG-R-M-S Summer Generation - 2021 Vintage Super Off-Peak $0.06614 $0.07281 + $0.01 DG-R-M-S Winter Generation - 2021 Vintage On-Peak $0.17483 $0.18884 + $0.01 DG-R-M-S Winter Generation - 2021 Vintage Off-Peak $0.08363 $0.09148 + $0.01 DG-R-M-S Winter Generation - 2021 Vintage Super Off-Peak $0.05718 $0.06324 + $0.01 DG-R-M-P Summer Generation - 2021 Vintage On-Peak $0.53526 $0.57359 + $0.01 DG-R-M-P Summer Generation - 2021 Vintage Off-Peak $0.16532 $0.17869 + $0.01 DG-R-M-P Summer Generation - 2021 Vintage Super Off-Peak $0.06580 $0.07245 + $0.01 DG-R-M-P Winter Generation - 2021 Vintage On-Peak $0.17388 $0.18783 + $0.01 DG-R-M-P Winter Generation - 2021 Vintage Off-Peak $0.08315 $0.09097 + $0.01 DG-R-M-P Winter Generation - 2021 Vintage Super Off-Peak $0.05687 $0.06292 + $0.01 DG-R-L-S Summer Generation - 2021 Vintage On-Peak $0.51385 $0.55074 + $0.01 DG-R-L-S Summer Generation - 2021 Vintage Off-Peak $0.15789 $0.17075 + $0.01 DG-R-L-S Summer Generation - 2021 Vintage Super Off-Peak $0.06188 $0.06826 + $0.01 DG-R-L-S Winter Generation - 2021 Vintage On-Peak $0.16590 $0.17930 + $0.01 DG-R-L-S Winter Generation - 2021 Vintage Off-Peak $0.07862 $0.08614 + $0.01 DG-R-L-S Winter Generation - 2021 Vintage Super Off-Peak $0.05330 $0.05911 + $0.01 217
DG-R-L-P Summer Generation - 2021 Vintage On-Peak $0.51125 $0.54796 + $0.01 DG-R-L-P Summer Generation - 2021 Vintage Off-Peak $0.15701 $0.16982 + $0.01 DG-R-L-P Summer Generation - 2021 Vintage Super Off-Peak $0.06156 $0.06792 + $0.01 DG-R-L-P Winter Generation - 2021 Vintage On-Peak $0.16499 $0.17833 + $0.01 DG-R-L-P Winter Generation - 2021 Vintage Off-Peak $0.07816 $0.08564 + $0.01 DG-R-L-P Winter Generation - 2021 Vintage Super Off-Peak $0.05301 $0.05880 + $0.01 DG-R-L-T Summer Generation - 2021 Vintage On-Peak $0.48820 $0.52336 + $0.01 DG-R-L-T Summer Generation - 2021 Vintage Off-Peak $0.14901 $0.16128 + $0.01 DG-R-L-T Summer Generation - 2021 Vintage Super Off-Peak $0.05775 $0.06386 + $0.01 DG-R-L-T Winter Generation - 2021 Vintage On-Peak $0.15665 $0.16943 + $0.01 DG-R-L-T Winter Generation - 2021 Vintage Off-Peak $0.07361 $0.08078 + $0.01 DG-R-L-T Winter Generation - 2021 Vintage Super Off-Peak $0.04956 $0.05512 + $0.01 A6-TOU-P Summer Demand - 2021 Vintage Total $16.27 $17.37 A6-TOU-P Summer Generation - 2021 Vintage On-Peak $0.20092 $0.21669 + $0.01 A6-TOU-P Summer Generation - 2021 Vintage Off-Peak $0.10833 $0.11785 + $0.01 A6-TOU-P Summer Generation - 2021 Vintage Super Off-Peak $0.08987 $0.09814 + $0.01 A6-TOU-P Winter Generation - 2021 Vintage On-Peak $0.22435 $0.24170 + $0.01 A6-TOU-P Winter Generation - 2021 Vintage Off-Peak $0.11146 $0.12119 + $0.01 A6-TOU-P Winter Generation - 2021 Vintage Super Off-Peak $0.07876 $0.08629 + $0.01 A6-TOU-T Summer Demand - 2021 Vintage Total $15.57 $16.62 A6-TOU-T Summer Generation - 2021 Vintage On-Peak $0.19090 $0.20599 + $0.01 A6-TOU-T Summer Generation - 2021 Vintage Off-Peak $0.10233 $0.11144 + $0.01 A6-TOU-T Summer Generation - 2021 Vintage Super Off-Peak $0.08492 $0.09286 + $0.01 A6-TOU-T Winter Generation - 2021 Vintage On-Peak $0.21351 $0.23013 + $0.01 A6-TOU-T Winter Generation - 2021 Vintage Off-Peak $0.10553 $0.11487 + $0.01 A6-TOU-T Winter Generation - 2021 Vintage Super Off-Peak $0.07427 $0.08150 + $0.01 TOU-PA-S Summer Generation - 2021 Vintage On-Peak $0.23963 $0.25785 + $0.01 TOU-PA-S Summer Generation - 2021 Vintage Off-Peak $0.11881 $0.12888 + $0.01 TOU-PA-S Winter Generation - 2021 Vintage On-Peak $0.10974 $0.11919 + $0.01 218
TOU-PA-S Winter Generation - 2021 Vintage Off-Peak $0.03793 $0.04253 + $0.01 TOU-PA-P Summer Generation - 2021 Vintage On-Peak $0.23829 $0.25642 + $0.01 TOU-PA-P Summer Generation - 2021 Vintage Off-Peak $0.11807 $0.12808 + $0.01 TOU-PA-P Winter Generation - 2021 Vintage On-Peak $0.10908 $0.11848 + $0.01 TOU-PA-P Winter Generation - 2021 Vintage Off-Peak $0.03767 $0.04226 + $0.01 TOU-PA-2-S Summer Demand - 2021 Vintage On-Peak $11.24 $12.00 TOU-PA-2-S Summer Generation - 2021 Vintage On-Peak $0.11760 $0.12759 + $0.01 TOU-PA-2-S Summer Generation - 2021 Vintage Off-Peak $0.05932 $0.06537 + $0.01 TOU-PA-2-S Summer Generation - 2021 Vintage Super Off-Peak $0.04530 $0.05040 + $0.01 TOU-PA-2-S Winter Generation - 2021 Vintage On-Peak $0.12838 $0.13909 + $0.01 TOU-PA-2-S Winter Generation - 2021 Vintage Off-Peak $0.05866 $0.06467 + $0.01 TOU-PA-2-S Winter Generation - 2021 Vintage Super Off-Peak $0.03844 $0.04308 + $0.01 TOU-PA-2-P Summer Demand - 2021 Vintage On-Peak $11.19 $11.94 TOU-PA-2-P Summer Generation - 2021 Vintage On-Peak $0.11692 $0.12685 + $0.01 TOU-PA-2-P Summer Generation - 2021 Vintage Off-Peak $0.05892 $0.06494 + $0.01 TOU-PA-2-P Summer Generation - 2021 Vintage Super Off-Peak $0.04504 $0.05013 + $0.01 TOU-PA-2-P Winter Generation - 2021 Vintage On-Peak $0.12765 $0.13831 + $0.01 TOU-PA-2-P Winter Generation - 2021 Vintage Off-Peak $0.05829 $0.06427 + $0.01 TOU-PA-2-P Winter Generation - 2021 Vintage Super Off-Peak $0.03820 $0.04283 + $0.01 TOU-PA-3-S <20kW Summer Generation - 2021 Vintage On-Peak $0.27994 $0.30088 + $0.01 TOU-PA-3-S <20kW Summer Generation - 2021 Vintage Off-Peak $0.13754 $0.14886 + $0.01 TOU-PA-3-S <20kW Summer Generation - 2021 Vintage Super Off-Peak $0.04967 $0.05506 + $0.01 TOU-PA-3-S <20kW Winter Generation - 2021 Vintage On-Peak $0.09975 $0.10853 + $0.01 TOU-PA-3-S <20kW Winter Generation - 2021 Vintage Off-Peak $0.04261 $0.04753 + $0.01 TOU-PA-3-S <20kW Winter Generation - 2021 Vintage Super Off-Peak $0.02603 $0.02984 + $0.01 TOU-PA-3-P <20kW Summer Generation - 2021 Vintage On-Peak $0.27844 $0.29928 + $0.01 TOU-PA-3-P <20kW Summer Generation - 2021 Vintage Off-Peak $0.13673 $0.14800 + $0.01 TOU-PA-3-P <20kW Summer Generation - 2021 Vintage Super Off-Peak $0.04928 $0.05465 + $0.01 TOU-PA-3-P <20kW Winter Generation - 2021 Vintage On-Peak $0.09915 $0.10789 + $0.01 219
TOU-PA-3-P <20kW Winter Generation - 2021 Vintage Off-Peak $0.04231 $0.04721 + $0.01 TOU-PA-3-P <20kW Winter Generation - 2021 Vintage Super Off-Peak $0.02585 $0.02964 + $0.01 TOU-PA-3-S >=20kW Summer Demand - 2021 Vintage On-Peak $2.70 $2.89 TOU-PA-3-S >=20kW Summer Generation - 2021 Vintage On-Peak $0.25583 $0.27514 + $0.01 TOU-PA-3-S >=20kW Summer Generation - 2021 Vintage Off-Peak $0.12117 $0.13139 + $0.01 TOU-PA-3-S >=20kW Summer Generation - 2021 Vintage Super Off-Peak $0.04193 $0.04681 + $0.01 TOU-PA-3-S >=20kW Winter Generation - 2021 Vintage On-Peak $0.09381 $0.10219 + $0.01 TOU-PA-3-S >=20kW Winter Generation - 2021 Vintage Off-Peak $0.03928 $0.04398 + $0.01 TOU-PA-3-S >=20kW Winter Generation - 2021 Vintage Super Off-Peak $0.02345 $0.02708 + $0.01 TOU-PA-3-P >=20kW Summer Demand - 2021 Vintage On-Peak $2.69 $2.87 TOU-PA-3-P >=20kW Summer Generation - 2021 Vintage On-Peak $0.25447 $0.27369 + $0.01 TOU-PA-3-P >=20kW Summer Generation - 2021 Vintage Off-Peak $0.12046 $0.13063 + $0.01 TOU-PA-3-P >=20kW Summer Generation - 2021 Vintage Super Off-Peak $0.04158 $0.04644 + $0.01 TOU-PA-3-P >=20kW Winter Generation - 2021 Vintage On-Peak $0.09321 $0.10155 + $0.01 TOU-PA-3-P >=20kW Winter Generation - 2021 Vintage Off-Peak $0.03894 $0.04362 + $0.01 TOU-PA-3-P >=20kW Winter Generation - 2021 Vintage Super Off-Peak $0.02320 $0.02681 + $0.01 PA-T-1-S Summer Demand - 2021 Vintage On-Peak $6.29 $6.72 PA-T-1-S Summer Generation - 2021 Vintage On-Peak $0.12479 $0.13525 + $0.01 PA-T-1-S Summer Generation - 2021 Vintage Off-Peak $0.06376 $0.07011 + $0.01 PA-T-1-S Summer Generation - 2021 Vintage Super Off-Peak $0.05040 $0.05585 + $0.01 PA-T-1-S Winter Generation - 2021 Vintage On-Peak $0.13911 $0.15054 + $0.01 PA-T-1-S Winter Generation - 2021 Vintage Off-Peak $0.06468 $0.07109 + $0.01 PA-T-1-S Winter Generation - 2021 Vintage Super Off-Peak $0.04309 $0.04804 + $0.01 PA-T-1-P Summer Demand - 2021 Vintage On-Peak $6.26 $6.68 PA-T-1-P Summer Generation - 2021 Vintage On-Peak $0.12404 $0.13446 + $0.01 PA-T-1-P Summer Generation - 2021 Vintage Off-Peak $0.06332 $0.06964 + $0.01 PA-T-1-P Summer Generation - 2021 Vintage Super Off-Peak $0.05013 $0.05556 + $0.01 PA-T-1-P Winter Generation - 2021 Vintage On-Peak $0.13834 $0.14972 + $0.01 PA-T-1-P Winter Generation - 2021 Vintage Off-Peak $0.06429 $0.07068 + $0.01 PA-T-1-P Winter Generation - 2021 Vintage Super Off-Peak $0.04285 $0.04778 + $0.01 220
PA-T-1-T Summer Demand - 2021 Vintage On-Peak $5.99 $6.40 PA-T-1-T Summer Generation - 2021 Vintage On-Peak $0.11742 $0.12739 + $0.01 PA-T-1-T Summer Generation - 2021 Vintage Off-Peak $0.05933 $0.06538 + $0.01 PA-T-1-T Summer Generation - 2021 Vintage Super Off-Peak $0.04688 $0.05209 + $0.01 PA-T-1-T Winter Generation - 2021 Vintage On-Peak $0.13122 $0.14213 + $0.01 PA-T-1-T Winter Generation - 2021 Vintage Off-Peak $0.06041 $0.06653 + $0.01 PA-T-1-T Winter Generation - 2021 Vintage Super Off-Peak $0.03989 $0.04463 + $0.01 LS All Generation - 2021 Vintage Total $0.08020 $0.08740 + $0.01 OL-2 All Generation - 2021 Vintage Total $0.08020 $0.08740 + $0.01 LS-2-AD Summer Generation - 2021 Vintage On-Peak $0.27592 $0.29633 + $0.01 LS-2-AD Summer Generation - 2021 Vintage Off-Peak $0.15792 $0.17036 + $0.01 LS-2-AD Summer Generation - 2021 Vintage Super Off-Peak $0.05261 $0.05795 + $0.01 LS-2-AD Winter Generation - 2021 Vintage On-Peak $0.13500 $0.14590 + $0.01 LS-2-AD Winter Generation - 2021 Vintage Off-Peak $0.06473 $0.07088 + $0.01 LS-2-AD Winter Generation - 2021 Vintage Super Off-Peak $0.04398 $0.04874 + $0.01 G-TOU-M Summer Generation - 2021 Vintage On-Peak $0.16989 $0.18356 + $0.01 G-TOU-M Summer Generation - 2021 Vintage Semi-Peak $0.16466 $0.17798 + $0.01 G-TOU-M Summer Generation - 2021 Vintage Off-Peak $0.15941 $0.17237 + $0.01 G-TOU-M Winter Generation - 2021 Vintage On-Peak $0.16826 $0.18183 + $0.01 G-TOU-M Winter Generation - 2021 Vintage Semi-Peak $0.06146 $0.06782 + $0.01 G-TOU-M Winter Generation - 2021 Vintage Off-Peak $0.06144 $0.06780 + $0.01 G-OL-TOU Summer Generation - 2021 Vintage On-Peak $0.14218 $0.15398 + $0.01 G-OL-TOU Summer Generation - 2021 Vintage Semi-Peak $0.13590 $0.14728 + $0.01 G-OL-TOU Summer Generation - 2021 Vintage Off-Peak $0.13102 $0.14207 + $0.01 G-OL-TOU Winter Generation - 2021 Vintage On-Peak $0.34675 $0.37236 + $0.01 G-OL-TOU Winter Generation - 2021 Vintage Semi-Peak $0.14511 $0.15711 + $0.01 G-OL-TOU Winter Generation - 2021 Vintage Off-Peak $0.14509 $0.15709 + $0.01 221
G-TOU-A-S Summer Generation - 2021 Vintage On-Peak $0.31568 $0.33869 + $0.01 G-TOU-A-S Summer Generation - 2021 Vintage Semi-Peak $0.16918 $0.18231 + $0.01 G-TOU-A-S Summer Generation - 2021 Vintage Off-Peak $0.06375 $0.06976 + $0.01 G-TOU-A-S Winter Generation - 2021 Vintage On-Peak $0.17077 $0.18400 + $0.01 G-TOU-A-S Winter Generation - 2021 Vintage Semi-Peak $0.06749 $0.07375 + $0.01 G-TOU-A-S Winter Generation - 2021 Vintage Off-Peak $0.06701 $0.07324 + $0.01 G-TOU-A-P Summer Generation - 2021 Vintage On-Peak $0.31388 $0.33677 + $0.01 G-TOU-A-P Summer Generation - 2021 Vintage Semi-Peak $0.16816 $0.18122 + $0.01 G-TOU-A-P Summer Generation - 2021 Vintage Off-Peak $0.06329 $0.06927 + $0.01 G-TOU-A-P Winter Generation - 2021 Vintage On-Peak $0.16982 $0.18299 + $0.01 G-TOU-A-P Winter Generation - 2021 Vintage Semi-Peak $0.06708 $0.07331 + $0.01 G-TOU-A-P Winter Generation - 2021 Vintage Off-Peak $0.06660 $0.07280 + $0.01 G-AL-TOU-M-S Summer Demand - 2021 Vintage On-Peak $1.75 $1.87 G-AL-TOU-M-S Summer Generation - 2021 Vintage On-Peak $0.10617 $0.11554 + $0.01 G-AL-TOU-M-S Summer Generation - 2021 Vintage Semi-Peak $0.10584 $0.11519 + $0.01 G-AL-TOU-M-S Summer Generation - 2021 Vintage Off-Peak $0.10239 $0.11151 + $0.01 G-AL-TOU-M-S Winter Generation - 2021 Vintage On-Peak $0.38692 $0.41524 + $0.01 G-AL-TOU-M-S Winter Generation - 2021 Vintage Semi-Peak $0.16394 $0.17721 + $0.01 G-AL-TOU-M-S Winter Generation - 2021 Vintage Off-Peak $0.16392 $0.17720 + $0.01 G-AL-TOU-M-P Summer Demand - 2021 Vintage On-Peak $1.74 $1.86 G-AL-TOU-M-P Summer Generation - 2021 Vintage On-Peak $0.10544 $0.11476 + $0.01 G-AL-TOU-M-P Summer Generation - 2021 Vintage Semi-Peak $0.10511 $0.11441 + $0.01 G-AL-TOU-M-P Summer Generation - 2021 Vintage Off-Peak $0.10168 $0.11075 + $0.01 G-AL-TOU-M-P Winter Generation - 2021 Vintage On-Peak $0.38490 $0.41308 + $0.01 G-AL-TOU-M-P Winter Generation - 2021 Vintage Semi-Peak $0.16307 $0.17628 + $0.01 G-AL-TOU-M-P Winter Generation - 2021 Vintage Off-Peak $0.16305 $0.17627 + $0.01 G-AL-TOU-L-S Summer Demand - 2021 Vintage On-Peak $1.65 $1.77 G-AL-TOU-L-S Summer Generation - 2021 Vintage On-Peak $0.09684 $0.10558 + $0.01 G-AL-TOU-L-S Summer Generation - 2021 Vintage Semi-Peak $0.09651 $0.10523 + $0.01 G-AL-TOU-L-S Summer Generation - 2021 Vintage Off-Peak $0.09306 $0.10155 + $0.01 222
G-AL-TOU-L-S Winter Generation - 2021 Vintage On-Peak $0.35797 $0.38434 + $0.01 G-AL-TOU-L-S Winter Generation - 2021 Vintage Semi-Peak $0.15037 $0.16273 + $0.01 G-AL-TOU-L-S Winter Generation - 2021 Vintage Off-Peak $0.15036 $0.16271 + $0.01 G-AL-TOU-L-P Summer Demand - 2021 Vintage On-Peak $1.64 $1.76 G-AL-TOU-L-P Summer Generation - 2021 Vintage On-Peak $0.09615 $0.10485 + $0.01 G-AL-TOU-L-P Summer Generation - 2021 Vintage Semi-Peak $0.09583 $0.10451 + $0.01 G-AL-TOU-L-P Summer Generation - 2021 Vintage Off-Peak $0.09240 $0.10085 + $0.01 G-AL-TOU-L-P Winter Generation - 2021 Vintage On-Peak $0.35608 $0.38232 + $0.01 G-AL-TOU-L-P Winter Generation - 2021 Vintage Semi-Peak $0.14956 $0.16187 + $0.01 G-AL-TOU-L-P Winter Generation - 2021 Vintage Off-Peak $0.14955 $0.16185 + $0.01 G-AL-TOU-L-T Summer Demand - 2021 Vintage On-Peak $1.57 $1.68 G-AL-TOU-L-T Summer Generation - 2021 Vintage On-Peak $0.09044 $0.09875 + $0.01 G-AL-TOU-L-T Summer Generation - 2021 Vintage Semi-Peak $0.09014 $0.09843 + $0.01 G-AL-TOU-L-T Summer Generation - 2021 Vintage Off-Peak $0.08685 $0.09492 + $0.01 G-AL-TOU-L-T Winter Generation - 2021 Vintage On-Peak $0.33941 $0.36452 + $0.01 G-AL-TOU-L-T Winter Generation - 2021 Vintage Semi-Peak $0.14197 $0.15376 + $0.01 G-AL-TOU-L-T Winter Generation - 2021 Vintage Off-Peak $0.14195 $0.15374 + $0.01 G-DG-R-M-S Summer Generation - 2021 Vintage On-Peak $0.14149 $0.15325 + $0.01 G-DG-R-M-S Summer Generation - 2021 Vintage Semi-Peak $0.13628 $0.14769 + $0.01 G-DG-R-M-S Summer Generation - 2021 Vintage Off-Peak $0.13102 $0.14207 + $0.01 G-DG-R-M-S Winter Generation - 2021 Vintage On-Peak $0.34675 $0.37236 + $0.01 G-DG-R-M-S Winter Generation - 2021 Vintage Semi-Peak $0.14511 $0.15711 + $0.01 G-DG-R-M-S Winter Generation - 2021 Vintage Off-Peak $0.14509 $0.15709 + $0.01 G-DG-R-M-P Summer Generation - 2021 Vintage On-Peak $0.14061 $0.15231 + $0.01 G-DG-R-M-P Summer Generation - 2021 Vintage Semi-Peak $0.13540 $0.14675 + $0.01 G-DG-R-M-P Summer Generation - 2021 Vintage Off-Peak $0.13016 $0.14116 + $0.01 G-DG-R-M-P Winter Generation - 2021 Vintage On-Peak $0.34491 $0.37040 + $0.01 G-DG-R-M-P Winter Generation - 2021 Vintage Semi-Peak $0.14433 $0.15628 + $0.01 G-DG-R-M-P Winter Generation - 2021 Vintage Off-Peak $0.14431 $0.15626 + $0.01 223
G-DG-R-L-S Summer Generation - 2021 Vintage On-Peak $0.13019 $0.14119 + $0.01 G-DG-R-L-S Summer Generation - 2021 Vintage Semi-Peak $0.12498 $0.13562 + $0.01 G-DG-R-L-S Summer Generation - 2021 Vintage Off-Peak $0.11973 $0.13001 + $0.01 G-DG-R-L-S Winter Generation - 2021 Vintage On-Peak $0.32057 $0.34441 + $0.01 G-DG-R-L-S Winter Generation - 2021 Vintage Semi-Peak $0.13284 $0.14401 + $0.01 G-DG-R-L-S Winter Generation - 2021 Vintage Off-Peak $0.13282 $0.14400 + $0.01 G-DG-R-L-P Summer Generation - 2021 Vintage On-Peak $0.12937 $0.14031 + $0.01 G-DG-R-L-P Summer Generation - 2021 Vintage Semi-Peak $0.12416 $0.13475 + $0.01 G-DG-R-L-P Summer Generation - 2021 Vintage Off-Peak $0.11892 $0.12916 + $0.01 G-DG-R-L-P Winter Generation - 2021 Vintage On-Peak $0.31886 $0.34259 + $0.01 G-DG-R-L-P Winter Generation - 2021 Vintage Semi-Peak $0.13211 $0.14324 + $0.01 G-DG-R-L-P Winter Generation - 2021 Vintage Off-Peak $0.13209 $0.14322 + $0.01 G-DG-R-L-T Summer Generation - 2021 Vintage On-Peak $0.12247 $0.13295 + $0.01 G-DG-R-L-T Summer Generation - 2021 Vintage Semi-Peak $0.11728 $0.12740 + $0.01 G-DG-R-L-T Summer Generation - 2021 Vintage Off-Peak $0.11219 $0.12197 + $0.01 G-DG-R-L-T Winter Generation - 2021 Vintage On-Peak $0.30379 $0.32650 + $0.01 G-DG-R-L-T Winter Generation - 2021 Vintage Semi-Peak $0.12525 $0.13591 + $0.01 G-DG-R-L-T Winter Generation - 2021 Vintage Off-Peak $0.12523 $0.13589 + $0.01 G-A6-TOU-P Summer Demand - 2021 Vintage Total $1.64 $1.76 G-A6-TOU-P Summer Generation - 2021 Vintage On-Peak $0.09615 $0.10485 + $0.01 G-A6-TOU-P Summer Generation - 2021 Vintage Semi-Peak $0.09583 $0.10451 + $0.01 G-A6-TOU-P Summer Generation - 2021 Vintage Off-Peak $0.09240 $0.10085 + $0.01 G-A6-TOU-P Winter Generation - 2021 Vintage On-Peak $0.35608 $0.38232 + $0.01 G-A6-TOU-P Winter Generation - 2021 Vintage Semi-Peak $0.14956 $0.16187 + $0.01 G-A6-TOU-P Winter Generation - 2021 Vintage Off-Peak $0.14955 $0.16185 + $0.01 G-A6-TOU-T Summer Demand - 2021 Vintage Total $1.57 $1.68 G-A6-TOU-T Summer Generation - 2021 Vintage On-Peak $0.09044 $0.09875 + $0.01 G-A6-TOU-T Summer Generation - 2021 Vintage Semi-Peak $0.09014 $0.09843 + $0.01 G-A6-TOU-T Summer Generation - 2021 Vintage Off-Peak $0.08685 $0.09492 + $0.01 G-A6-TOU-T Winter Generation - 2021 Vintage On-Peak $0.33941 $0.36452 + $0.01 224
G-A6-TOU-T Winter Generation - 2021 Vintage Semi-Peak $0.14197 $0.15376 + $0.01 G-A6-TOU-T Winter Generation - 2021 Vintage Off-Peak $0.14195 $0.15374 + $0.01 G-PA-T-1-S Summer Demand - 2021 Vintage On-Peak $0.63 $0.67 G-PA-T-1-S Summer Generation - 2021 Vintage On-Peak $0.05617 $0.06201 + $0.01 G-PA-T-1-S Summer Generation - 2021 Vintage Semi-Peak $0.05594 $0.06176 + $0.01 G-PA-T-1-S Summer Generation - 2021 Vintage Off-Peak $0.05215 $0.05771 + $0.01 G-PA-T-1-S Winter Generation - 2021 Vintage On-Peak $0.21158 $0.22791 + $0.01 G-PA-T-1-S Winter Generation - 2021 Vintage Semi-Peak $0.08307 $0.09072 + $0.01 G-PA-T-1-S Winter Generation - 2021 Vintage Off-Peak $0.08305 $0.09070 + $0.01 G-PA-T-1-P Summer Demand - 2021 Vintage On-Peak $0.63 $0.67 G-PA-T-1-P Summer Generation - 2021 Vintage On-Peak $0.05119 $0.05669 + $0.01 G-PA-T-1-P Summer Generation - 2021 Vintage Semi-Peak $0.05095 $0.05644 + $0.01 G-PA-T-1-P Summer Generation - 2021 Vintage Off-Peak $0.04718 $0.05241 + $0.01 G-PA-T-1-P Winter Generation - 2021 Vintage On-Peak $0.21041 $0.22665 + $0.01 G-PA-T-1-P Winter Generation - 2021 Vintage Semi-Peak $0.08257 $0.09019 + $0.01 G-PA-T-1-P Winter Generation - 2021 Vintage Off-Peak $0.08254 $0.09016 + $0.01 G-PA-T-1-T Summer Demand - 2021 Vintage On-Peak $0.60 $0.65 G-PA-T-1-T Summer Generation - 2021 Vintage On-Peak $0.05191 $0.05745 + $0.01 G-PA-T-1-T Summer Generation - 2021 Vintage Semi-Peak $0.05169 $0.05723 + $0.01 G-PA-T-1-T Summer Generation - 2021 Vintage Off-Peak $0.04807 $0.05336 + $0.01 G-PA-T-1-T Winter Generation - 2021 Vintage On-Peak $0.20904 $0.22519 + $0.01 G-PA-T-1-T Winter Generation - 2021 Vintage Semi-Peak $0.08198 $0.08955 + $0.01 G-PA-T-1-T Winter Generation - 2021 Vintage Off-Peak $0.08195 $0.08953 + $0.01 G-TOU-PA-S < 20kW Summer Generation - 2021 Vintage On-Peak $0.31280 $0.33595 + $0.01 G-TOU-PA-S < 20kW Summer Generation - 2021 Vintage Semi-Peak $0.12342 $0.13379 + $0.01 G-TOU-PA-S < 20kW Summer Generation - 2021 Vintage Off-Peak $0.05814 $0.06411 + $0.01 G-TOU-PA-S < 20kW Winter Generation - 2021 Vintage On-Peak $0.11989 $0.13002 + $0.01 G-TOU-PA-S < 20kW Winter Generation - 2021 Vintage Semi-Peak $0.04009 $0.04484 + $0.01 G-TOU-PA-S < 20kW Winter Generation - 2021 Vintage Off-Peak $0.04007 $0.04482 + $0.01 225
G-TOU-PA-P < 20kW Summer Generation - 2021 Vintage On-Peak $0.31100 $0.33403 + $0.01 G-TOU-PA-P < 20kW Summer Generation - 2021 Vintage Semi-Peak $0.12261 $0.13293 + $0.01 G-TOU-PA-P < 20kW Summer Generation - 2021 Vintage Off-Peak $0.05767 $0.06360 + $0.01 G-TOU-PA-P < 20kW Winter Generation - 2021 Vintage On-Peak $0.11910 $0.12918 + $0.01 G-TOU-PA-P < 20kW Winter Generation - 2021 Vintage Semi-Peak $0.03972 $0.04444 + $0.01 G-TOU-PA-P < 20kW Winter Generation - 2021 Vintage Off-Peak $0.03970 $0.04442 + $0.01 G-TOU-PA-S >= 20kW Summer Demand - 2021 Vintage On-Peak $1.00 $1.06 G-TOU-PA-S >= 20kW Summer Generation - 2021 Vintage On-Peak $0.06258 $0.06885 + $0.01 G-TOU-PA-S >= 20kW Summer Generation - 2021 Vintage Semi-Peak $0.06153 $0.06772 + $0.01 G-TOU-PA-S >= 20kW Summer Generation - 2021 Vintage Off-Peak $0.05601 $0.06184 + $0.01 G-TOU-PA-S >= 20kW Winter Generation - 2021 Vintage On-Peak $0.23133 $0.24899 + $0.01 G-TOU-PA-S >= 20kW Winter Generation - 2021 Vintage Semi-Peak $0.09232 $0.10059 + $0.01 G-TOU-PA-S >= 20kW Winter Generation - 2021 Vintage Off-Peak $0.09230 $0.10057 + $0.01 G-TOU-PA-P >= 20kW Summer Demand - 2021 Vintage On-Peak $0.99 $1.05 G-TOU-PA-P >= 20kW Summer Generation - 2021 Vintage On-Peak $0.06212 $0.06836 + $0.01 G-TOU-PA-P >= 20kW Summer Generation - 2021 Vintage Semi-Peak $0.06106 $0.06723 + $0.01 G-TOU-PA-P >= 20kW Summer Generation - 2021 Vintage Off-Peak $0.05570 $0.06151 + $0.01 G-TOU-PA-P >= 20kW Winter Generation - 2021 Vintage On-Peak $0.23007 $0.24764 + $0.01 G-TOU-PA-P >= 20kW Winter Generation - 2021 Vintage Semi-Peak $0.09178 $0.10002 + $0.01 G-TOU-PA-P >= 20kW Winter Generation - 2021 Vintage Off-Peak $0.09177 $0.10000 + $0.01 EV-HP-S Summer Demand - 2021 Vintage On-Peak $8.26 $8.82 EV-HP-S Summer Generation - 2021 Vintage On-Peak $0.08618 $0.09420 + $0.01 EV-HP-S Summer Generation - 2021 Vintage Off-Peak $0.03874 $0.04356 + $0.01 EV-HP-S Summer Generation - 2021 Vintage Super Off-Peak $0.03008 $0.03431 + $0.01 EV-HP-S Winter Generation - 2021 Vintage On-Peak $0.09913 $0.10803 + $0.01 EV-HP-S Winter Generation - 2021 Vintage Off-Peak $0.04119 $0.04618 + $0.01 EV-HP-S Winter Generation - 2021 Vintage Super Off-Peak $0.02438 $0.02823 + $0.01 EV-HP-P Summer Demand - 2021 Vintage On-Peak $8.22 $8.77 EV-HP-P Summer Generation - 2021 Vintage On-Peak $0.08560 $0.09359 + $0.01 EV-HP-P Summer Generation - 2021 Vintage Off-Peak $0.03841 $0.04321 + $0.01 226
EV-HP-P Summer Generation - 2021 Vintage Super Off-Peak $0.02986 $0.03409 + $0.01 EV-HP-P Winter Generation - 2021 Vintage On-Peak $0.09853 $0.10739 + $0.01 EV-HP-P Winter Generation - 2021 Vintage Off-Peak $0.04088 $0.04585 + $0.01 EV-HP-P Winter Generation - 2021 Vintage Super Off-Peak $0.02419 $0.02803 + $0.01 TOU-ELEC Summer Generation - 2021 Vintage On-Peak $0.37060 $0.39801 + $0.01 TOU-ELEC Summer Generation - 2021 Vintage Off-Peak $0.07946 $0.08722 + $0.01 TOU-ELEC Summer Generation - 2021 Vintage Super Off-Peak $0.04115 $0.04634 + $0.01 TOU-ELEC Winter Generation - 2021 Vintage On-Peak $0.18051 $0.19510 + $0.01 TOU-ELEC Winter Generation - 2021 Vintage Off-Peak $0.06904 $0.07611 + $0.01 TOU-ELEC Winter Generation - 2021 Vintage Super Off-Peak $0.03421 $0.03892 + $0.01 CCA Rate Name Season Charge Type Time of Use Period PowerBase PowerOn Power100 ($/kWh) DR Summer Generation - 2022 Vintage Total $0.13243 $0.14339 + $0.01 DR Winter Generation - 2022 Vintage Total $0.13243 $0.14339 + $0.01 DR-LI-MB Summer Generation - 2022 Vintage Total $0.13243 $0.14339 + $0.01 DR-LI-MB Winter Generation - 2022 Vintage Total $0.13243 $0.14339 + $0.01 DR-SES Summer Generation - 2022 Vintage On-Peak $0.38801 $0.41622 + $0.01 DR-SES Summer Generation - 2022 Vintage Off-Peak $0.12387 $0.13425 + $0.01 DR-SES Summer Generation - 2022 Vintage Super Off-Peak $0.04239 $0.04727 + $0.01 DR-SES Winter Generation - 2022 Vintage On-Peak $0.14769 $0.15968 + $0.01 DR-SES Winter Generation - 2022 Vintage Off-Peak $0.09742 $0.10603 + $0.01 DR-SES Winter Generation - 2022 Vintage Super Off-Peak $0.03583 $0.04028 + $0.01 EV-TOU Summer Generation - 2022 Vintage On-Peak $0.38801 $0.41622 + $0.01 EV-TOU Summer Generation - 2022 Vintage Off-Peak $0.12387 $0.13425 + $0.01 EV-TOU Summer Generation - 2022 Vintage Super Off-Peak $0.04239 $0.04727 + $0.01 EV-TOU Winter Generation - 2022 Vintage On-Peak $0.14769 $0.15968 + $0.01 EV-TOU Winter Generation - 2022 Vintage Off-Peak $0.09742 $0.10603 + $0.01 EV-TOU Winter Generation - 2022 Vintage Super Off-Peak $0.03583 $0.04028 + $0.01 EV-TOU-2 Summer Generation - 2022 Vintage On-Peak $0.38801 $0.41622 + $0.01 227
EV-TOU-2 Summer Generation - 2022 Vintage Off-Peak $0.12387 $0.13425 + $0.01 EV-TOU-2 Summer Generation - 2022 Vintage Super Off-Peak $0.04239 $0.04727 + $0.01 EV-TOU-2 Winter Generation - 2022 Vintage On-Peak $0.14769 $0.15968 + $0.01 EV-TOU-2 Winter Generation - 2022 Vintage Off-Peak $0.09742 $0.10603 + $0.01 EV-TOU-2 Winter Generation - 2022 Vintage Super Off-Peak $0.03583 $0.04028 + $0.01 EV-TOU-5 Summer Generation - 2022 Vintage On-Peak $0.38801 $0.41622 + $0.01 EV-TOU-5 Summer Generation - 2022 Vintage Off-Peak $0.12387 $0.13425 + $0.01 EV-TOU-5 Summer Generation - 2022 Vintage Super Off-Peak $0.04239 $0.04727 + $0.01 EV-TOU-5 Winter Generation - 2022 Vintage On-Peak $0.14769 $0.15968 + $0.01 EV-TOU-5 Winter Generation - 2022 Vintage Off-Peak $0.09742 $0.10603 + $0.01 EV-TOU-5 Winter Generation - 2022 Vintage Super Off-Peak $0.03583 $0.04028 + $0.01 TOU-DR-1 Summer Generation - 2022 Vintage On-Peak $0.28043 $0.30138 + $0.01 TOU-DR-1 Summer Generation - 2022 Vintage Off-Peak $0.08423 $0.09194 + $0.01 TOU-DR-1 Summer Generation - 2022 Vintage Super Off-Peak $0.01000 $0.01000 + $0.01 TOU-DR-1 Winter Generation - 2022 Vintage On-Peak $0.21424 $0.23072 + $0.01 TOU-DR-1 Winter Generation - 2022 Vintage Off-Peak $0.14159 $0.15317 + $0.01 TOU-DR-1 Winter Generation - 2022 Vintage Super Off-Peak $0.06089 $0.06703 + $0.01 TOU-DR-2 Summer Generation - 2022 Vintage On-Peak $0.28043 $0.30138 + $0.01 TOU-DR-2 Summer Generation - 2022 Vintage Off-Peak $0.04492 $0.04998 + $0.01 TOU-DR-2 Winter Generation - 2022 Vintage On-Peak $0.21424 $0.23072 + $0.01 TOU-DR-2 Winter Generation - 2022 Vintage Off-Peak $0.09244 $0.10071 + $0.01 TOU-DR Summer Generation - 2022 Vintage On-Peak $0.17351 $0.18725 + $0.01 TOU-DR Summer Generation - 2022 Vintage Off-Peak $0.12116 $0.13137 + $0.01 TOU-DR Summer Generation - 2022 Vintage Super Off-Peak $0.07182 $0.07869 + $0.01 TOU-DR Winter Generation - 2022 Vintage On-Peak $0.21404 $0.23051 + $0.01 TOU-DR Winter Generation - 2022 Vintage Off-Peak $0.14144 $0.15302 + $0.01 TOU-DR Winter Generation - 2022 Vintage Super Off-Peak $0.06082 $0.06695 + $0.01 TOU-A-S Summer Generation - 2022 Vintage On-Peak $0.27889 $0.29910 + $0.01 TOU-A-S Summer Generation - 2022 Vintage Off-Peak $0.14320 $0.15424 + $0.01 228
TOU-A-S Winter Generation - 2022 Vintage On-Peak $0.15388 $0.16564 + $0.01 TOU-A-S Winter Generation - 2022 Vintage Off-Peak $0.06564 $0.07145 + $0.01 TOU-A-P Summer Generation - 2022 Vintage On-Peak $0.27739 $0.29749 + $0.01 TOU-A-P Summer Generation - 2022 Vintage Off-Peak $0.14238 $0.15337 + $0.01 TOU-A-P Winter Generation - 2022 Vintage On-Peak $0.15305 $0.16476 + $0.01 TOU-A-P Winter Generation - 2022 Vintage Off-Peak $0.06532 $0.07111 + $0.01 TOU-A-2-S Summer Generation - 2022 Vintage On-Peak $0.38283 $0.41005 + $0.01 TOU-A-2-S Summer Generation - 2022 Vintage Off-Peak $0.11851 $0.12790 + $0.01 TOU-A-2-S Summer Generation - 2022 Vintage Super Off-Peak $0.05749 $0.06276 + $0.01 TOU-A-2-S Winter Generation - 2022 Vintage On-Peak $0.14097 $0.15187 + $0.01 TOU-A-2-S Winter Generation - 2022 Vintage Off-Peak $0.07070 $0.07685 + $0.01 TOU-A-2-S Winter Generation - 2022 Vintage Super Off-Peak $0.04995 $0.05471 + $0.01 TOU-A-2-P Summer Generation - 2022 Vintage On-Peak $0.38089 $0.40797 + $0.01 TOU-A-2-P Summer Generation - 2022 Vintage Off-Peak $0.11787 $0.12721 + $0.01 TOU-A-2-P Summer Generation - 2022 Vintage Super Off-Peak $0.05724 $0.06248 + $0.01 TOU-A-2-P Winter Generation - 2022 Vintage On-Peak $0.14024 $0.15108 + $0.01 TOU-A-2-P Winter Generation - 2022 Vintage Off-Peak $0.07032 $0.07644 + $0.01 TOU-A-2-P Winter Generation - 2022 Vintage Super Off-Peak $0.04972 $0.05446 + $0.01 TOU-A-3-S Summer Generation - 2022 Vintage On-Peak $0.28189 $0.30230 + $0.01 TOU-A-3-S Summer Generation - 2022 Vintage Off-Peak $0.16389 $0.17633 + $0.01 TOU-A-3-S Summer Generation - 2022 Vintage Super Off-Peak $0.05858 $0.06392 + $0.01 TOU-A-3-S Winter Generation - 2022 Vintage On-Peak $0.14097 $0.15187 + $0.01 TOU-A-3-S Winter Generation - 2022 Vintage Off-Peak $0.07070 $0.07685 + $0.01 TOU-A-3-S Winter Generation - 2022 Vintage Super Off-Peak $0.04995 $0.05471 + $0.01 TOU-A-3-P Summer Generation - 2022 Vintage On-Peak $0.28043 $0.30074 + $0.01 TOU-A-3-P Summer Generation - 2022 Vintage Off-Peak $0.16300 $0.17538 + $0.01 TOU-A-3-P Summer Generation - 2022 Vintage Super Off-Peak $0.05821 $0.06352 + $0.01 TOU-A-3-P Winter Generation - 2022 Vintage On-Peak $0.14024 $0.15108 + $0.01 TOU-A-3-P Winter Generation - 2022 Vintage Off-Peak $0.07032 $0.07644 + $0.01 229
TOU-A-3-P Winter Generation - 2022 Vintage Super Off-Peak $0.04972 $0.05446 + $0.01 A-TC Summer Generation - 2022 Vintage Total $0.07650 $0.08304 + $0.01 A-TC Winter Generation - 2022 Vintage Total $0.07650 $0.08304 + $0.01 TOU-M Summer Generation - 2022 Vintage On-Peak $0.39741 $0.42589 + $0.01 TOU-M Summer Generation - 2022 Vintage Off-Peak $0.12066 $0.13047 + $0.01 TOU-M Summer Generation - 2022 Vintage Super Off-Peak $0.05356 $0.05884 + $0.01 TOU-M Winter Generation - 2022 Vintage On-Peak $0.13949 $0.15057 + $0.01 TOU-M Winter Generation - 2022 Vintage Off-Peak $0.06739 $0.07360 + $0.01 TOU-M Winter Generation - 2022 Vintage Super Off-Peak $0.04648 $0.05127 + $0.01 OL-TOU Summer Generation - 2022 Vintage On-Peak $0.54679 $0.58535 + $0.01 OL-TOU Summer Generation - 2022 Vintage Off-Peak $0.17399 $0.18739 + $0.01 OL-TOU Summer Generation - 2022 Vintage Super Off-Peak $0.07428 $0.08095 + $0.01 OL-TOU Winter Generation - 2022 Vintage On-Peak $0.18297 $0.19698 + $0.01 OL-TOU Winter Generation - 2022 Vintage Off-Peak $0.09177 $0.09962 + $0.01 OL-TOU Winter Generation - 2022 Vintage Super Off-Peak $0.06532 $0.07138 + $0.01 AL-TOU-M-S Summer Demand - 2022 Vintage On-Peak $17.06 $18.21 AL-TOU-M-S Summer Generation - 2022 Vintage On-Peak $0.22059 $0.23714 + $0.01 AL-TOU-M-S Summer Generation - 2022 Vintage Off-Peak $0.12335 $0.13333 + $0.01 AL-TOU-M-S Summer Generation - 2022 Vintage Super Off-Peak $0.10396 $0.11263 + $0.01 AL-TOU-M-S Winter Generation - 2022 Vintage On-Peak $0.24529 $0.26350 + $0.01 AL-TOU-M-S Winter Generation - 2022 Vintage Off-Peak $0.12671 $0.13692 + $0.01 AL-TOU-M-S Winter Generation - 2022 Vintage Super Off-Peak $0.09231 $0.10020 + $0.01 AL-TOU-M-P Summer Demand - 2022 Vintage On-Peak $16.98 $18.13 AL-TOU-M-P Summer Generation - 2022 Vintage On-Peak $0.21941 $0.23588 + $0.01 AL-TOU-M-P Summer Generation - 2022 Vintage Off-Peak $0.12266 $0.13260 + $0.01 AL-TOU-M-P Summer Generation - 2022 Vintage Super Off-Peak $0.10352 $0.11217 + $0.01 AL-TOU-M-P Winter Generation - 2022 Vintage On-Peak $0.24406 $0.26219 + $0.01 AL-TOU-M-P Winter Generation - 2022 Vintage Off-Peak $0.12608 $0.13625 + $0.01 AL-TOU-M-P Winter Generation - 2022 Vintage Super Off-Peak $0.09192 $0.09978 + $0.01 230
AL-TOU-L-S Summer Demand - 2022 Vintage On-Peak $16.34 $17.44 AL-TOU-L-S Summer Generation - 2022 Vintage On-Peak $0.21020 $0.22604 + $0.01 AL-TOU-L-S Summer Generation - 2022 Vintage Off-Peak $0.11712 $0.12669 + $0.01 AL-TOU-L-S Summer Generation - 2022 Vintage Super Off-Peak $0.09843 $0.10673 + $0.01 AL-TOU-L-S Winter Generation - 2022 Vintage On-Peak $0.23368 $0.25111 + $0.01 AL-TOU-L-S Winter Generation - 2022 Vintage Off-Peak $0.12019 $0.12996 + $0.01 AL-TOU-L-S Winter Generation - 2022 Vintage Super Off-Peak $0.08728 $0.09483 + $0.01 AL-TOU-L-P Summer Demand - 2022 Vintage On-Peak $16.27 $17.37 AL-TOU-L-P Summer Generation - 2022 Vintage On-Peak $0.20906 $0.22483 + $0.01 AL-TOU-L-P Summer Generation - 2022 Vintage Off-Peak $0.11647 $0.12599 + $0.01 AL-TOU-L-P Summer Generation - 2022 Vintage Super Off-Peak $0.09801 $0.10628 + $0.01 AL-TOU-L-P Winter Generation - 2022 Vintage On-Peak $0.23249 $0.24984 + $0.01 AL-TOU-L-P Winter Generation - 2022 Vintage Off-Peak $0.11960 $0.12933 + $0.01 AL-TOU-L-P Winter Generation - 2022 Vintage Super Off-Peak $0.08690 $0.09443 + $0.01 AL-TOU-L-T Summer Demand - 2022 Vintage On-Peak $15.57 $16.62 AL-TOU-L-T Summer Generation - 2022 Vintage On-Peak $0.19904 $0.21413 + $0.01 AL-TOU-L-T Summer Generation - 2022 Vintage Off-Peak $0.11047 $0.11958 + $0.01 AL-TOU-L-T Summer Generation - 2022 Vintage Super Off-Peak $0.09306 $0.10100 + $0.01 AL-TOU-L-T Winter Generation - 2022 Vintage On-Peak $0.22165 $0.23827 + $0.01 AL-TOU-L-T Winter Generation - 2022 Vintage Off-Peak $0.11367 $0.12301 + $0.01 AL-TOU-L-T Winter Generation - 2022 Vintage Super Off-Peak $0.08241 $0.08964 + $0.01 AL-TOU-2-S Summer Demand - 2022 Vintage On-Peak $29.15 $31.11 AL-TOU-2-S Summer Generation - 2022 Vintage On-Peak $0.18837 $0.20274 + $0.01 AL-TOU-2-S Summer Generation - 2022 Vintage Off-Peak $0.10406 $0.11275 + $0.01 AL-TOU-2-S Summer Generation - 2022 Vintage Super Off-Peak $0.08681 $0.09432 + $0.01 AL-TOU-2-S Winter Generation - 2022 Vintage On-Peak $0.20928 $0.22507 + $0.01 AL-TOU-2-S Winter Generation - 2022 Vintage Off-Peak $0.10652 $0.11537 + $0.01 AL-TOU-2-S Winter Generation - 2022 Vintage Super Off-Peak $0.07671 $0.08354 + $0.01 AL-TOU-2-P Summer Demand - 2022 Vintage On-Peak $29.01 $30.97 231
AL-TOU-2-P Summer Generation - 2022 Vintage On-Peak $0.18734 $0.20164 + $0.01 AL-TOU-2-P Summer Generation - 2022 Vintage Off-Peak $0.10347 $0.11211 + $0.01 AL-TOU-2-P Summer Generation - 2022 Vintage Super Off-Peak $0.08642 $0.09392 + $0.01 AL-TOU-2-P Winter Generation - 2022 Vintage On-Peak $0.20821 $0.22392 + $0.01 AL-TOU-2-P Winter Generation - 2022 Vintage Off-Peak $0.10598 $0.11479 + $0.01 AL-TOU-2-P Winter Generation - 2022 Vintage Super Off-Peak $0.07638 $0.08319 + $0.01 AL-TOU-2-T Summer Demand - 2022 Vintage On-Peak $27.77 $29.64 AL-TOU-2-T Summer Generation - 2022 Vintage On-Peak $0.17825 $0.19194 + $0.01 AL-TOU-2-T Summer Generation - 2022 Vintage Off-Peak $0.09801 $0.10628 + $0.01 AL-TOU-2-T Summer Generation - 2022 Vintage Super Off-Peak $0.08194 $0.08913 + $0.01 AL-TOU-2-T Winter Generation - 2022 Vintage On-Peak $0.19839 $0.21344 + $0.01 AL-TOU-2-T Winter Generation - 2022 Vintage Off-Peak $0.10061 $0.10906 + $0.01 AL-TOU-2-T Winter Generation - 2022 Vintage Super Off-Peak $0.07230 $0.07884 + $0.01 DG-R-M-S Summer Generation - 2022 Vintage On-Peak $0.54612 $0.58463 + $0.01 DG-R-M-S Summer Generation - 2022 Vintage Off-Peak $0.17437 $0.18779 + $0.01 DG-R-M-S Summer Generation - 2022 Vintage Super Off-Peak $0.07428 $0.08095 + $0.01 DG-R-M-S Winter Generation - 2022 Vintage On-Peak $0.18297 $0.19698 + $0.01 DG-R-M-S Winter Generation - 2022 Vintage Off-Peak $0.09177 $0.09962 + $0.01 DG-R-M-S Winter Generation - 2022 Vintage Super Off-Peak $0.06532 $0.07138 + $0.01 DG-R-M-P Summer Generation - 2022 Vintage On-Peak $0.54340 $0.58173 + $0.01 DG-R-M-P Summer Generation - 2022 Vintage Off-Peak $0.17346 $0.18683 + $0.01 DG-R-M-P Summer Generation - 2022 Vintage Super Off-Peak $0.07394 $0.08059 + $0.01 DG-R-M-P Winter Generation - 2022 Vintage On-Peak $0.18202 $0.19597 + $0.01 DG-R-M-P Winter Generation - 2022 Vintage Off-Peak $0.09129 $0.09911 + $0.01 DG-R-M-P Winter Generation - 2022 Vintage Super Off-Peak $0.06501 $0.07106 + $0.01 DG-R-L-S Summer Generation - 2022 Vintage On-Peak $0.52199 $0.55888 + $0.01 DG-R-L-S Summer Generation - 2022 Vintage Off-Peak $0.16603 $0.17889 + $0.01 DG-R-L-S Summer Generation - 2022 Vintage Super Off-Peak $0.07002 $0.07640 + $0.01 DG-R-L-S Winter Generation - 2022 Vintage On-Peak $0.17404 $0.18744 + $0.01 DG-R-L-S Winter Generation - 2022 Vintage Off-Peak $0.08676 $0.09428 + $0.01 232
DG-R-L-S Winter Generation - 2022 Vintage Super Off-Peak $0.06144 $0.06725 + $0.01 DG-R-L-P Summer Generation - 2022 Vintage On-Peak $0.51939 $0.55610 + $0.01 DG-R-L-P Summer Generation - 2022 Vintage Off-Peak $0.16515 $0.17796 + $0.01 DG-R-L-P Summer Generation - 2022 Vintage Super Off-Peak $0.06970 $0.07606 + $0.01 DG-R-L-P Winter Generation - 2022 Vintage On-Peak $0.17313 $0.18647 + $0.01 DG-R-L-P Winter Generation - 2022 Vintage Off-Peak $0.08630 $0.09378 + $0.01 DG-R-L-P Winter Generation - 2022 Vintage Super Off-Peak $0.06115 $0.06694 + $0.01 DG-R-L-T Summer Generation - 2022 Vintage On-Peak $0.49634 $0.53150 + $0.01 DG-R-L-T Summer Generation - 2022 Vintage Off-Peak $0.15715 $0.16942 + $0.01 DG-R-L-T Summer Generation - 2022 Vintage Super Off-Peak $0.06589 $0.07200 + $0.01 DG-R-L-T Winter Generation - 2022 Vintage On-Peak $0.16479 $0.17757 + $0.01 DG-R-L-T Winter Generation - 2022 Vintage Off-Peak $0.08175 $0.08892 + $0.01 DG-R-L-T Winter Generation - 2022 Vintage Super Off-Peak $0.05770 $0.06326 + $0.01 A6-TOU-P Summer Demand - 2022 Vintage Total $16.27 $17.37 A6-TOU-P Summer Generation - 2022 Vintage On-Peak $0.20906 $0.22483 + $0.01 A6-TOU-P Summer Generation - 2022 Vintage Off-Peak $0.11647 $0.12599 + $0.01 A6-TOU-P Summer Generation - 2022 Vintage Super Off-Peak $0.09801 $0.10628 + $0.01 A6-TOU-P Winter Generation - 2022 Vintage On-Peak $0.23249 $0.24984 + $0.01 A6-TOU-P Winter Generation - 2022 Vintage Off-Peak $0.11960 $0.12933 + $0.01 A6-TOU-P Winter Generation - 2022 Vintage Super Off-Peak $0.08690 $0.09443 + $0.01 A6-TOU-T Summer Demand - 2022 Vintage Total $15.57 $16.62 A6-TOU-T Summer Generation - 2022 Vintage On-Peak $0.19904 $0.21413 + $0.01 A6-TOU-T Summer Generation - 2022 Vintage Off-Peak $0.11047 $0.11958 + $0.01 A6-TOU-T Summer Generation - 2022 Vintage Super Off-Peak $0.09306 $0.10100 + $0.01 A6-TOU-T Winter Generation - 2022 Vintage On-Peak $0.22165 $0.23827 + $0.01 A6-TOU-T Winter Generation - 2022 Vintage Off-Peak $0.11367 $0.12301 + $0.01 A6-TOU-T Winter Generation - 2022 Vintage Super Off-Peak $0.08241 $0.08964 + $0.01 TOU-PA-S Summer Generation - 2022 Vintage On-Peak $0.24383 $0.26205 + $0.01 TOU-PA-S Summer Generation - 2022 Vintage Off-Peak $0.12301 $0.13308 + $0.01 233
TOU-PA-S Winter Generation - 2022 Vintage On-Peak $0.11394 $0.12339 + $0.01 TOU-PA-S Winter Generation - 2022 Vintage Off-Peak $0.04213 $0.04673 + $0.01 TOU-PA-P Summer Generation - 2022 Vintage On-Peak $0.24249 $0.26062 + $0.01 TOU-PA-P Summer Generation - 2022 Vintage Off-Peak $0.12227 $0.13228 + $0.01 TOU-PA-P Winter Generation - 2022 Vintage On-Peak $0.11328 $0.12268 + $0.01 TOU-PA-P Winter Generation - 2022 Vintage Off-Peak $0.04187 $0.04646 + $0.01 TOU-PA-2-S Summer Demand - 2022 Vintage On-Peak $11.24 $12.00 TOU-PA-2-S Summer Generation - 2022 Vintage On-Peak $0.12180 $0.13179 + $0.01 TOU-PA-2-S Summer Generation - 2022 Vintage Off-Peak $0.06352 $0.06957 + $0.01 TOU-PA-2-S Summer Generation - 2022 Vintage Super Off-Peak $0.04950 $0.05460 + $0.01 TOU-PA-2-S Winter Generation - 2022 Vintage On-Peak $0.13258 $0.14329 + $0.01 TOU-PA-2-S Winter Generation - 2022 Vintage Off-Peak $0.06286 $0.06887 + $0.01 TOU-PA-2-S Winter Generation - 2022 Vintage Super Off-Peak $0.04264 $0.04728 + $0.01 TOU-PA-2-P Summer Demand - 2022 Vintage On-Peak $11.19 $11.94 TOU-PA-2-P Summer Generation - 2022 Vintage On-Peak $0.12112 $0.13105 + $0.01 TOU-PA-2-P Summer Generation - 2022 Vintage Off-Peak $0.06312 $0.06914 + $0.01 TOU-PA-2-P Summer Generation - 2022 Vintage Super Off-Peak $0.04924 $0.05433 + $0.01 TOU-PA-2-P Winter Generation - 2022 Vintage On-Peak $0.13185 $0.14251 + $0.01 TOU-PA-2-P Winter Generation - 2022 Vintage Off-Peak $0.06249 $0.06847 + $0.01 TOU-PA-2-P Winter Generation - 2022 Vintage Super Off-Peak $0.04240 $0.04703 + $0.01 TOU-PA-3-S <20kW Summer Generation - 2022 Vintage On-Peak $0.28414 $0.30508 + $0.01 TOU-PA-3-S <20kW Summer Generation - 2022 Vintage Off-Peak $0.14174 $0.15306 + $0.01 TOU-PA-3-S <20kW Summer Generation - 2022 Vintage Super Off-Peak $0.05387 $0.05926 + $0.01 TOU-PA-3-S <20kW Winter Generation - 2022 Vintage On-Peak $0.10395 $0.11273 + $0.01 TOU-PA-3-S <20kW Winter Generation - 2022 Vintage Off-Peak $0.04681 $0.05173 + $0.01 TOU-PA-3-S <20kW Winter Generation - 2022 Vintage Super Off-Peak $0.03023 $0.03404 + $0.01 TOU-PA-3-P <20kW Summer Generation - 2022 Vintage On-Peak $0.28264 $0.30348 + $0.01 TOU-PA-3-P <20kW Summer Generation - 2022 Vintage Off-Peak $0.14093 $0.15220 + $0.01 TOU-PA-3-P <20kW Summer Generation - 2022 Vintage Super Off-Peak $0.05348 $0.05885 + $0.01 234
TOU-PA-3-P <20kW Winter Generation - 2022 Vintage On-Peak $0.10335 $0.11209 + $0.01 TOU-PA-3-P <20kW Winter Generation - 2022 Vintage Off-Peak $0.04651 $0.05141 + $0.01 TOU-PA-3-P <20kW Winter Generation - 2022 Vintage Super Off-Peak $0.03005 $0.03384 + $0.01 TOU-PA-3-S >=20kW Summer Demand - 2022 Vintage On-Peak $2.70 $2.89 TOU-PA-3-S >=20kW Summer Generation - 2022 Vintage On-Peak $0.26003 $0.27934 + $0.01 TOU-PA-3-S >=20kW Summer Generation - 2022 Vintage Off-Peak $0.12537 $0.13559 + $0.01 TOU-PA-3-S >=20kW Summer Generation - 2022 Vintage Super Off-Peak $0.04613 $0.05101 + $0.01 TOU-PA-3-S >=20kW Winter Generation - 2022 Vintage On-Peak $0.09801 $0.10639 + $0.01 TOU-PA-3-S >=20kW Winter Generation - 2022 Vintage Off-Peak $0.04348 $0.04818 + $0.01 TOU-PA-3-S >=20kW Winter Generation - 2022 Vintage Super Off-Peak $0.02765 $0.03128 + $0.01 TOU-PA-3-P >=20kW Summer Demand - 2022 Vintage On-Peak $2.69 $2.87 TOU-PA-3-P >=20kW Summer Generation - 2022 Vintage On-Peak $0.25867 $0.27789 + $0.01 TOU-PA-3-P >=20kW Summer Generation - 2022 Vintage Off-Peak $0.12466 $0.13483 + $0.01 TOU-PA-3-P >=20kW Summer Generation - 2022 Vintage Super Off-Peak $0.04578 $0.05064 + $0.01 TOU-PA-3-P >=20kW Winter Generation - 2022 Vintage On-Peak $0.09741 $0.10575 + $0.01 TOU-PA-3-P >=20kW Winter Generation - 2022 Vintage Off-Peak $0.04314 $0.04782 + $0.01 TOU-PA-3-P >=20kW Winter Generation - 2022 Vintage Super Off-Peak $0.02740 $0.03101 + $0.01 PA-T-1-S Summer Demand - 2022 Vintage On-Peak $6.29 $6.72 PA-T-1-S Summer Generation - 2022 Vintage On-Peak $0.12899 $0.13945 + $0.01 PA-T-1-S Summer Generation - 2022 Vintage Off-Peak $0.06796 $0.07431 + $0.01 PA-T-1-S Summer Generation - 2022 Vintage Super Off-Peak $0.05460 $0.06005 + $0.01 PA-T-1-S Winter Generation - 2022 Vintage On-Peak $0.14331 $0.15474 + $0.01 PA-T-1-S Winter Generation - 2022 Vintage Off-Peak $0.06888 $0.07529 + $0.01 PA-T-1-S Winter Generation - 2022 Vintage Super Off-Peak $0.04729 $0.05224 + $0.01 PA-T-1-P Summer Demand - 2022 Vintage On-Peak $6.26 $6.68 PA-T-1-P Summer Generation - 2022 Vintage On-Peak $0.12824 $0.13866 + $0.01 PA-T-1-P Summer Generation - 2022 Vintage Off-Peak $0.06752 $0.07384 + $0.01 PA-T-1-P Summer Generation - 2022 Vintage Super Off-Peak $0.05433 $0.05976 + $0.01 PA-T-1-P Winter Generation - 2022 Vintage On-Peak $0.14254 $0.15392 + $0.01 PA-T-1-P Winter Generation - 2022 Vintage Off-Peak $0.06849 $0.07488 + $0.01 235
PA-T-1-P Winter Generation - 2022 Vintage Super Off-Peak $0.04705 $0.05198 + $0.01 PA-T-1-T Summer Demand - 2022 Vintage On-Peak $5.99 $6.40 PA-T-1-T Summer Generation - 2022 Vintage On-Peak $0.12162 $0.13159 + $0.01 PA-T-1-T Summer Generation - 2022 Vintage Off-Peak $0.06353 $0.06958 + $0.01 PA-T-1-T Summer Generation - 2022 Vintage Super Off-Peak $0.05108 $0.05629 + $0.01 PA-T-1-T Winter Generation - 2022 Vintage On-Peak $0.13542 $0.14633 + $0.01 PA-T-1-T Winter Generation - 2022 Vintage Off-Peak $0.06461 $0.07073 + $0.01 PA-T-1-T Winter Generation - 2022 Vintage Super Off-Peak $0.04409 $0.04883 + $0.01 LS All Generation - 2022 Vintage Total $0.08554 $0.09274 + $0.01 OL-2 All Generation - 2022 Vintage Total $0.08554 $0.09274 + $0.01 LS-2-AD Summer Generation - 2022 Vintage On-Peak $0.28126 $0.30167 + $0.01 LS-2-AD Summer Generation - 2022 Vintage Off-Peak $0.16326 $0.17570 + $0.01 LS-2-AD Summer Generation - 2022 Vintage Super Off-Peak $0.05795 $0.06329 + $0.01 LS-2-AD Winter Generation - 2022 Vintage On-Peak $0.14034 $0.15124 + $0.01 LS-2-AD Winter Generation - 2022 Vintage Off-Peak $0.07007 $0.07622 + $0.01 LS-2-AD Winter Generation - 2022 Vintage Super Off-Peak $0.04932 $0.05408 + $0.01 G-TOU-M Summer Generation - 2022 Vintage On-Peak $0.17803 $0.19170 + $0.01 G-TOU-M Summer Generation - 2022 Vintage Semi-Peak $0.17280 $0.18612 + $0.01 G-TOU-M Summer Generation - 2022 Vintage Off-Peak $0.16755 $0.18051 + $0.01 G-TOU-M Winter Generation - 2022 Vintage On-Peak $0.17640 $0.18997 + $0.01 G-TOU-M Winter Generation - 2022 Vintage Semi-Peak $0.06960 $0.07596 + $0.01 G-TOU-M Winter Generation - 2022 Vintage Off-Peak $0.06958 $0.07594 + $0.01 G-OL-TOU Summer Generation - 2022 Vintage On-Peak $0.15032 $0.16212 + $0.01 G-OL-TOU Summer Generation - 2022 Vintage Semi-Peak $0.14404 $0.15542 + $0.01 G-OL-TOU Summer Generation - 2022 Vintage Off-Peak $0.13916 $0.15021 + $0.01 G-OL-TOU Winter Generation - 2022 Vintage On-Peak $0.35489 $0.38050 + $0.01 G-OL-TOU Winter Generation - 2022 Vintage Semi-Peak $0.15325 $0.16525 + $0.01 G-OL-TOU Winter Generation - 2022 Vintage Off-Peak $0.15323 $0.16523 + $0.01 236
G-TOU-A-S Summer Generation - 2022 Vintage On-Peak $0.32051 $0.34352 + $0.01 G-TOU-A-S Summer Generation - 2022 Vintage Semi-Peak $0.17401 $0.18714 + $0.01 G-TOU-A-S Summer Generation - 2022 Vintage Off-Peak $0.06858 $0.07459 + $0.01 G-TOU-A-S Winter Generation - 2022 Vintage On-Peak $0.17560 $0.18883 + $0.01 G-TOU-A-S Winter Generation - 2022 Vintage Semi-Peak $0.07232 $0.07858 + $0.01 G-TOU-A-S Winter Generation - 2022 Vintage Off-Peak $0.07184 $0.07807 + $0.01 G-TOU-A-P Summer Generation - 2022 Vintage On-Peak $0.31871 $0.34160 + $0.01 G-TOU-A-P Summer Generation - 2022 Vintage Semi-Peak $0.17299 $0.18605 + $0.01 G-TOU-A-P Summer Generation - 2022 Vintage Off-Peak $0.06812 $0.07410 + $0.01 G-TOU-A-P Winter Generation - 2022 Vintage On-Peak $0.17465 $0.18782 + $0.01 G-TOU-A-P Winter Generation - 2022 Vintage Semi-Peak $0.07191 $0.07814 + $0.01 G-TOU-A-P Winter Generation - 2022 Vintage Off-Peak $0.07143 $0.07763 + $0.01 G-AL-TOU-M-S Summer Demand - 2022 Vintage On-Peak $1.75 $1.87 G-AL-TOU-M-S Summer Generation - 2022 Vintage On-Peak $0.11431 $0.12368 + $0.01 G-AL-TOU-M-S Summer Generation - 2022 Vintage Semi-Peak $0.11398 $0.12333 + $0.01 G-AL-TOU-M-S Summer Generation - 2022 Vintage Off-Peak $0.11053 $0.11965 + $0.01 G-AL-TOU-M-S Winter Generation - 2022 Vintage On-Peak $0.39506 $0.42338 + $0.01 G-AL-TOU-M-S Winter Generation - 2022 Vintage Semi-Peak $0.17208 $0.18535 + $0.01 G-AL-TOU-M-S Winter Generation - 2022 Vintage Off-Peak $0.17206 $0.18534 + $0.01 G-AL-TOU-M-P Summer Demand - 2022 Vintage On-Peak $1.74 $1.86 G-AL-TOU-M-P Summer Generation - 2022 Vintage On-Peak $0.11358 $0.12290 + $0.01 G-AL-TOU-M-P Summer Generation - 2022 Vintage Semi-Peak $0.11325 $0.12255 + $0.01 G-AL-TOU-M-P Summer Generation - 2022 Vintage Off-Peak $0.10982 $0.11889 + $0.01 G-AL-TOU-M-P Winter Generation - 2022 Vintage On-Peak $0.39304 $0.42122 + $0.01 G-AL-TOU-M-P Winter Generation - 2022 Vintage Semi-Peak $0.17121 $0.18442 + $0.01 G-AL-TOU-M-P Winter Generation - 2022 Vintage Off-Peak $0.17119 $0.18441 + $0.01 G-AL-TOU-L-S Summer Demand - 2022 Vintage On-Peak $1.65 $1.77 G-AL-TOU-L-S Summer Generation - 2022 Vintage On-Peak $0.10498 $0.11372 + $0.01 G-AL-TOU-L-S Summer Generation - 2022 Vintage Semi-Peak $0.10465 $0.11337 + $0.01 237
G-AL-TOU-L-S Summer Generation - 2022 Vintage Off-Peak $0.10120 $0.10969 + $0.01 G-AL-TOU-L-S Winter Generation - 2022 Vintage On-Peak $0.36611 $0.39248 + $0.01 G-AL-TOU-L-S Winter Generation - 2022 Vintage Semi-Peak $0.15851 $0.17087 + $0.01 G-AL-TOU-L-S Winter Generation - 2022 Vintage Off-Peak $0.15850 $0.17085 + $0.01 G-AL-TOU-L-P Summer Demand - 2022 Vintage On-Peak $1.64 $1.76 G-AL-TOU-L-P Summer Generation - 2022 Vintage On-Peak $0.10429 $0.11299 + $0.01 G-AL-TOU-L-P Summer Generation - 2022 Vintage Semi-Peak $0.10397 $0.11265 + $0.01 G-AL-TOU-L-P Summer Generation - 2022 Vintage Off-Peak $0.10054 $0.10899 + $0.01 G-AL-TOU-L-P Winter Generation - 2022 Vintage On-Peak $0.36422 $0.39046 + $0.01 G-AL-TOU-L-P Winter Generation - 2022 Vintage Semi-Peak $0.15770 $0.17001 + $0.01 G-AL-TOU-L-P Winter Generation - 2022 Vintage Off-Peak $0.15769 $0.16999 + $0.01 G-AL-TOU-L-T Summer Demand - 2022 Vintage On-Peak $1.57 $1.68 G-AL-TOU-L-T Summer Generation - 2022 Vintage On-Peak $0.09858 $0.10689 + $0.01 G-AL-TOU-L-T Summer Generation - 2022 Vintage Semi-Peak $0.09828 $0.10657 + $0.01 G-AL-TOU-L-T Summer Generation - 2022 Vintage Off-Peak $0.09499 $0.10306 + $0.01 G-AL-TOU-L-T Winter Generation - 2022 Vintage On-Peak $0.34755 $0.37266 + $0.01 G-AL-TOU-L-T Winter Generation - 2022 Vintage Semi-Peak $0.15011 $0.16190 + $0.01 G-AL-TOU-L-T Winter Generation - 2022 Vintage Off-Peak $0.15009 $0.16188 + $0.01 G-DG-R-M-S Summer Generation - 2022 Vintage On-Peak $0.14963 $0.16139 + $0.01 G-DG-R-M-S Summer Generation - 2022 Vintage Semi-Peak $0.14442 $0.15583 + $0.01 G-DG-R-M-S Summer Generation - 2022 Vintage Off-Peak $0.13916 $0.15021 + $0.01 G-DG-R-M-S Winter Generation - 2022 Vintage On-Peak $0.35489 $0.38050 + $0.01 G-DG-R-M-S Winter Generation - 2022 Vintage Semi-Peak $0.15325 $0.16525 + $0.01 G-DG-R-M-S Winter Generation - 2022 Vintage Off-Peak $0.15323 $0.16523 + $0.01 G-DG-R-M-P Summer Generation - 2022 Vintage On-Peak $0.14875 $0.16045 + $0.01 G-DG-R-M-P Summer Generation - 2022 Vintage Semi-Peak $0.14354 $0.15489 + $0.01 G-DG-R-M-P Summer Generation - 2022 Vintage Off-Peak $0.13830 $0.14930 + $0.01 G-DG-R-M-P Winter Generation - 2022 Vintage On-Peak $0.35305 $0.37854 + $0.01 G-DG-R-M-P Winter Generation - 2022 Vintage Semi-Peak $0.15247 $0.16442 + $0.01 G-DG-R-M-P Winter Generation - 2022 Vintage Off-Peak $0.15245 $0.16440 + $0.01 238
G-DG-R-L-S Summer Generation - 2022 Vintage On-Peak $0.13833 $0.14933 + $0.01 G-DG-R-L-S Summer Generation - 2022 Vintage Semi-Peak $0.13312 $0.14376 + $0.01 G-DG-R-L-S Summer Generation - 2022 Vintage Off-Peak $0.12787 $0.13815 + $0.01 G-DG-R-L-S Winter Generation - 2022 Vintage On-Peak $0.32871 $0.35255 + $0.01 G-DG-R-L-S Winter Generation - 2022 Vintage Semi-Peak $0.14098 $0.15215 + $0.01 G-DG-R-L-S Winter Generation - 2022 Vintage Off-Peak $0.14096 $0.15214 + $0.01 G-DG-R-L-P Summer Generation - 2022 Vintage On-Peak $0.13751 $0.14845 + $0.01 G-DG-R-L-P Summer Generation - 2022 Vintage Semi-Peak $0.13230 $0.14289 + $0.01 G-DG-R-L-P Summer Generation - 2022 Vintage Off-Peak $0.12706 $0.13730 + $0.01 G-DG-R-L-P Winter Generation - 2022 Vintage On-Peak $0.32700 $0.35073 + $0.01 G-DG-R-L-P Winter Generation - 2022 Vintage Semi-Peak $0.14025 $0.15138 + $0.01 G-DG-R-L-P Winter Generation - 2022 Vintage Off-Peak $0.14023 $0.15136 + $0.01 G-DG-R-L-T Summer Generation - 2022 Vintage On-Peak $0.13061 $0.14109 + $0.01 G-DG-R-L-T Summer Generation - 2022 Vintage Semi-Peak $0.12542 $0.13554 + $0.01 G-DG-R-L-T Summer Generation - 2022 Vintage Off-Peak $0.12033 $0.13011 + $0.01 G-DG-R-L-T Winter Generation - 2022 Vintage On-Peak $0.31193 $0.33464 + $0.01 G-DG-R-L-T Winter Generation - 2022 Vintage Semi-Peak $0.13339 $0.14405 + $0.01 G-DG-R-L-T Winter Generation - 2022 Vintage Off-Peak $0.13337 $0.14403 + $0.01 G-A6-TOU-P Summer Demand - 2022 Vintage Total $1.64 $1.76 G-A6-TOU-P Summer Generation - 2022 Vintage On-Peak $0.10429 $0.11299 + $0.01 G-A6-TOU-P Summer Generation - 2022 Vintage Semi-Peak $0.10397 $0.11265 + $0.01 G-A6-TOU-P Summer Generation - 2022 Vintage Off-Peak $0.10054 $0.10899 + $0.01 G-A6-TOU-P Winter Generation - 2022 Vintage On-Peak $0.36422 $0.39046 + $0.01 G-A6-TOU-P Winter Generation - 2022 Vintage Semi-Peak $0.15770 $0.17001 + $0.01 G-A6-TOU-P Winter Generation - 2022 Vintage Off-Peak $0.15769 $0.16999 + $0.01 G-A6-TOU-T Summer Demand - 2022 Vintage Total $1.57 $1.68 G-A6-TOU-T Summer Generation - 2022 Vintage On-Peak $0.09858 $0.10689 + $0.01 G-A6-TOU-T Summer Generation - 2022 Vintage Semi-Peak $0.09828 $0.10657 + $0.01 G-A6-TOU-T Summer Generation - 2022 Vintage Off-Peak $0.09499 $0.10306 + $0.01 239
G-A6-TOU-T Winter Generation - 2022 Vintage On-Peak $0.34755 $0.37266 + $0.01 G-A6-TOU-T Winter Generation - 2022 Vintage Semi-Peak $0.15011 $0.16190 + $0.01 G-A6-TOU-T Winter Generation - 2022 Vintage Off-Peak $0.15009 $0.16188 + $0.01 G-PA-T-1-S Summer Demand - 2022 Vintage On-Peak $0.63 $0.67 G-PA-T-1-S Summer Generation - 2022 Vintage On-Peak $0.06037 $0.06621 + $0.01 G-PA-T-1-S Summer Generation - 2022 Vintage Semi-Peak $0.06014 $0.06596 + $0.01 G-PA-T-1-S Summer Generation - 2022 Vintage Off-Peak $0.05635 $0.06191 + $0.01 G-PA-T-1-S Winter Generation - 2022 Vintage On-Peak $0.21578 $0.23211 + $0.01 G-PA-T-1-S Winter Generation - 2022 Vintage Semi-Peak $0.08727 $0.09492 + $0.01 G-PA-T-1-S Winter Generation - 2022 Vintage Off-Peak $0.08725 $0.09490 + $0.01 G-PA-T-1-P Summer Demand - 2022 Vintage On-Peak $0.63 $0.67 G-PA-T-1-P Summer Generation - 2022 Vintage On-Peak $0.05539 $0.06089 + $0.01 G-PA-T-1-P Summer Generation - 2022 Vintage Semi-Peak $0.05515 $0.06064 + $0.01 G-PA-T-1-P Summer Generation - 2022 Vintage Off-Peak $0.05138 $0.05661 + $0.01 G-PA-T-1-P Winter Generation - 2022 Vintage On-Peak $0.21461 $0.23085 + $0.01 G-PA-T-1-P Winter Generation - 2022 Vintage Semi-Peak $0.08677 $0.09439 + $0.01 G-PA-T-1-P Winter Generation - 2022 Vintage Off-Peak $0.08674 $0.09436 + $0.01 G-PA-T-1-T Summer Demand - 2022 Vintage On-Peak $0.60 $0.65 G-PA-T-1-T Summer Generation - 2022 Vintage On-Peak $0.05611 $0.06165 + $0.01 G-PA-T-1-T Summer Generation - 2022 Vintage Semi-Peak $0.05589 $0.06143 + $0.01 G-PA-T-1-T Summer Generation - 2022 Vintage Off-Peak $0.05227 $0.05756 + $0.01 G-PA-T-1-T Winter Generation - 2022 Vintage On-Peak $0.21324 $0.22939 + $0.01 G-PA-T-1-T Winter Generation - 2022 Vintage Semi-Peak $0.08618 $0.09375 + $0.01 G-PA-T-1-T Winter Generation - 2022 Vintage Off-Peak $0.08615 $0.09373 + $0.01 G-TOU-PA-S < 20kW Summer Generation - 2022 Vintage On-Peak $0.31700 $0.34015 + $0.01 G-TOU-PA-S < 20kW Summer Generation - 2022 Vintage Semi-Peak $0.12762 $0.13799 + $0.01 G-TOU-PA-S < 20kW Summer Generation - 2022 Vintage Off-Peak $0.06234 $0.06831 + $0.01 G-TOU-PA-S < 20kW Winter Generation - 2022 Vintage On-Peak $0.12409 $0.13422 + $0.01 G-TOU-PA-S < 20kW Winter Generation - 2022 Vintage Semi-Peak $0.04429 $0.04904 + $0.01 G-TOU-PA-S < 20kW Winter Generation - 2022 Vintage Off-Peak $0.04427 $0.04902 + $0.01 240
G-TOU-PA-P < 20kW Summer Generation - 2022 Vintage On-Peak $0.31520 $0.33823 + $0.01 G-TOU-PA-P < 20kW Summer Generation - 2022 Vintage Semi-Peak $0.12681 $0.13713 + $0.01 G-TOU-PA-P < 20kW Summer Generation - 2022 Vintage Off-Peak $0.06187 $0.06780 + $0.01 G-TOU-PA-P < 20kW Winter Generation - 2022 Vintage On-Peak $0.12330 $0.13338 + $0.01 G-TOU-PA-P < 20kW Winter Generation - 2022 Vintage Semi-Peak $0.04392 $0.04864 + $0.01 G-TOU-PA-P < 20kW Winter Generation - 2022 Vintage Off-Peak $0.04390 $0.04862 + $0.01 G-TOU-PA-S >= 20kW Summer Demand - 2022 Vintage On-Peak $1.00 $1.06 G-TOU-PA-S >= 20kW Summer Generation - 2022 Vintage On-Peak $0.06678 $0.07305 + $0.01 G-TOU-PA-S >= 20kW Summer Generation - 2022 Vintage Semi-Peak $0.06573 $0.07192 + $0.01 G-TOU-PA-S >= 20kW Summer Generation - 2022 Vintage Off-Peak $0.06021 $0.06604 + $0.01 G-TOU-PA-S >= 20kW Winter Generation - 2022 Vintage On-Peak $0.23553 $0.25319 + $0.01 G-TOU-PA-S >= 20kW Winter Generation - 2022 Vintage Semi-Peak $0.09652 $0.10479 + $0.01 G-TOU-PA-S >= 20kW Winter Generation - 2022 Vintage Off-Peak $0.09650 $0.10477 + $0.01 G-TOU-PA-P >= 20kW Summer Demand - 2022 Vintage On-Peak $0.99 $1.05 G-TOU-PA-P >= 20kW Summer Generation - 2022 Vintage On-Peak $0.06632 $0.07256 + $0.01 G-TOU-PA-P >= 20kW Summer Generation - 2022 Vintage Semi-Peak $0.06526 $0.07143 + $0.01 G-TOU-PA-P >= 20kW Summer Generation - 2022 Vintage Off-Peak $0.05990 $0.06571 + $0.01 G-TOU-PA-P >= 20kW Winter Generation - 2022 Vintage On-Peak $0.23427 $0.25184 + $0.01 G-TOU-PA-P >= 20kW Winter Generation - 2022 Vintage Semi-Peak $0.09598 $0.10422 + $0.01 G-TOU-PA-P >= 20kW Winter Generation - 2022 Vintage Off-Peak $0.09597 $0.10420 + $0.01 EV-HP-S Summer Demand - 2022 Vintage On-Peak $8.26 $8.82 EV-HP-S Summer Generation - 2022 Vintage On-Peak $0.09432 $0.10234 + $0.01 EV-HP-S Summer Generation - 2022 Vintage Off-Peak $0.04688 $0.05170 + $0.01 EV-HP-S Summer Generation - 2022 Vintage Super Off-Peak $0.03822 $0.04245 + $0.01 EV-HP-S Winter Generation - 2022 Vintage On-Peak $0.10727 $0.11617 + $0.01 EV-HP-S Winter Generation - 2022 Vintage Off-Peak $0.04933 $0.05432 + $0.01 EV-HP-S Winter Generation - 2022 Vintage Super Off-Peak $0.03252 $0.03637 + $0.01 EV-HP-P Summer Demand - 2022 Vintage On-Peak $8.22 $8.77 EV-HP-P Summer Generation - 2022 Vintage On-Peak $0.09374 $0.10173 + $0.01 241
EV-HP-P Summer Generation - 2022 Vintage Off-Peak $0.04655 $0.05135 + $0.01 EV-HP-P Summer Generation - 2022 Vintage Super Off-Peak $0.03800 $0.04223 + $0.01 EV-HP-P Winter Generation - 2022 Vintage On-Peak $0.10667 $0.11553 + $0.01 EV-HP-P Winter Generation - 2022 Vintage Off-Peak $0.04902 $0.05399 + $0.01 EV-HP-P Winter Generation - 2022 Vintage Super Off-Peak $0.03233 $0.03617 + $0.01 TOU-ELEC Summer Generation - 2022 Vintage On-Peak $0.37619 $0.40360 + $0.01 TOU-ELEC Summer Generation - 2022 Vintage Off-Peak $0.08505 $0.09281 + $0.01 TOU-ELEC Summer Generation - 2022 Vintage Super Off-Peak $0.04674 $0.05193 + $0.01 TOU-ELEC Winter Generation - 2022 Vintage On-Peak $0.18610 $0.20069 + $0.01 TOU-ELEC Winter Generation - 2022 Vintage Off-Peak $0.07463 $0.08170 + $0.01 TOU-ELEC Winter Generation - 2022 Vintage Super Off-Peak $0.03980 $0.04451 + $0.01 *Power100 cost = (Usage*PowerOn Rate) + (Usage*Power100 Adder) Generation is assessed at $/kWh
Demand is assessed at $/kW
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SAN DIEGO COMMUNITY POWER
Staff Report – Item 15
To: Board of Directors
From: Jack Clark, Chief Operating Officer
Lee Friedman, Associate Director Strategic Initiatives
Via: Karin Burns, Chief Executive Officer
Subject: Receive and File Local Development Strategy
Date: April 23, 2026
Recommendation
Receive and File Informational Update on San Diego Community Power’s Local Development Strategy.

Background
San Diego Community Power’s Strategic Plan includes a goal of developing one gigawatt (GW) of local renewable and clean energy capacity by 2035.

As part of this effort, Community Power has established a goal of procuring 300 megawatts (MW) of this local energy capacity through distributed energy resources (DERs).

Of that 300 MW goal, the Power Services Department is responsible for procuring 150 MW through local development of renewable energy projects.

The Local Development Strategy provides a framework to guide Power Services’ efforts to achieve this 150 MW goal while balancing feasibility, affordability, and community benefits.

Analysis and Discussion
The Local Development Strategy establishes a framework to guide how the Power Services Department will pursue Community Power’s 150 MW distributed energy resource procurement goal through local development efforts. The strategy is not intended to prescribe specific procurements, but rather to provide a holistic and consistent approach for evaluating opportunities, prioritizing projects, and selecting procurement pathways in a constrained and evolving market.
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Vision and Guiding Principles
The strategy defines “local” development as projects sited within San Diego and Imperial Counties (inclusive of Tribal lands located in San Diego County). It identifies guiding principles that inform staff decision‑making across all local development activities, including transparency in procurement, workforce development and labor standards, feasibility and deliverability, ratepayer protection, equity and community benefit, and alignment with system reliability needs. These principles are intended to balance project viability and cost competitiveness with broader public and community objectives.

Local Development Opportunity Areas
Drawing on prior solicitations, market engagement, and project development experience, the strategy summarizes where local development opportunities are most likely to emerge and the barriers that currently limit project success. Key challenges identified include grid interconnection limitations, operational constraints, and restricted valuation of distributed resources under existing regulatory and utility frameworks. In response, the strategy emphasizes coordinated policy engagement and collaboration with state and federal agencies, SDG&E, other Community Choice Aggregators, and industry stakeholders to improve long‑term conditions for local development.

Sector Analysis and Project Evaluation
The strategy outlines a sector‑based approach for assessing local development opportunities, including commercial and industrial sites, member agencies, public agencies, and Tribal Nations. Projects are evaluated using Community Power’s Energy Proposal Evaluation Criteria (EPEC), which applies a holistic lens that considers both quantitative and qualitative factors.

Key evaluation considerations include, but are not limited to:
• Project price and overall cost competitiveness
• Impacts on customer rates
• Project viability and development readiness, including site control and interconnection status
• Resource adequacy and capacity contributions
• Contribution to system and community resilience
• Workforce development commitments and local economic impacts • Environmental impacts and siting considerations
• Co‑benefits to Community Power and the communities in which projects are located This framework is intended to support consistent, transparent, and best value‑focused comparison across a diverse and evolving project pipeline. 244
Community and Stakeholder Engagement
Recognizing that local projects vary in size, siting context, and potential community impact, the strategy establishes an approach to stakeholder engagement that is proportional and project‑specific. Developers are generally expected to lead engagement efforts where appropriate, while Community Power staff may provide limited support consistent with its role as a public agency. Early coordination with affected communities, member agencies, and internal teams is emphasized to reduce development risk, avoid unnecessary delays, and support alignment with local priorities.

Implementation Through Procurement Pathways
The strategy identifies multiple procurement pathways through which local development projects may advance, each with distinct characteristics, timelines, and risk profiles. These pathways include:
• Behind‑the‑Meter (BTM):

Projects located on the customer side of the utility meter, typically developed at host sites such as commercial facilities, schools, or public agencies. Community Power contracts for energy and capacity while leveraging lower interconnection risk and potential resilience benefits.
• Front‑of‑the‑Meter (FTM):

Projects interconnected directly to the utility distribution or transmission system that provide energy, capacity, and compliance attributes through standard procurement mechanisms. These projects often involve longer development timelines and greater interconnection complexity.
• Feed‑in Tariff (FIT):

A standardized procurement option for eligible small and community‑scale front‑of‑the‑meter renewable projects that sell energy to Community Power under predefined pricing and contract terms, without participation in a competitive solicitation.
• Solar Advantage
Supports community‑scale renewable development in or near disadvantaged communities and provides bill credits to CARE/FERA customers in select disadvantaged communities.
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• Public‑Private Partnerships:

Strategic collaborations that leverage private or philanthropic capital to advance projects that may not be feasible through traditional procurement alone, while maintaining public oversight, transparency, and alignment with Community Power’s mission.

Fiscal Impact
N/A
Committee Review
The Draft Local Development Strategy was presented at the April 9 Community Advisory Committee meeting. Committee members received and filed the update.

Strategic Plan
The Draft Local Development Strategy supports the Community Power strategic goal of development of 1 Gigawatt of local renewable and clean energy capacity by 2035, of which 300 MW will be DERs enabled by Community Power programs, tariffs, and procurement.

Of that 300 MW, Power Services is responsible for the procurement of 150 MW.

Attachments
A: Draft Local Development Strategy
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ITEM 15

ATTACHMENT A
247
San Diego Community Power Local
Development Strategy
Introduction
San Diego Community Power (Community Power) is a Community Choice Aggregator (CCA) formed via a Joint Power’s Authority in 2019 by the cities of San Diego, Chula Vista, Encinitas, La Mesa and Imperial Beach. In 2021, National City and the County of San Diego also joined Community Power, which now delivers service to nearly one million customers throughout the San Diego Region.

Formed to help its member agencies meet their respective climate action goals and bring choice in energy to its residents, Community Power’s mission is to provide 100% clean and renewable power by 2035 or sooner while supporting good paying local jobs and reinvesting excess revenue back into the communities we serve through innovative programs and projects that address the needs of our customers.

Community Power has set a strategic goal for the development of 300 megawatts (MW) through distributed energy resources. Of that 300 MW, 150 MW would be through the deployment and procurement of local, distributed renewable energy resources like solar and storage projects managed by the Powers Services department while the other 150 MW is expected to be covered by the implementation of programmatic efforts, such as the Solar Battery Savings program and managed by the Program department1.

The purpose of this Local Development Strategy is to outline the ways in which Community Power staff intend to accomplish the procurement of the non-programmatic 150 MW goal by 2035 while adhering to our commitments to community benefits, stakeholder engagement, rate competitiveness, affordability, and local workforce development. Central to this strategy is the enhancement of existing and development of new procurement pathways that expand opportunities for contracting with Community Power. Further, Community Power’s comprehensive and transparent methodology to assess and value potential projects will help ensure that the agency is making procurement decisions with intentionality and in alignment with Community Power’s mission.

Community Power must also understand the systemic and project-specific hurdles to successful project development and viability (e.g. technical, interconnection, regulatory, 1 Community Power’s strategic goal does not specifically distinguish between nameplate capacity or enrolled capacity to reduce peak demand. For the purposes of this document, the 150 MW goal under the purview of the Power Services department currently reflects nameplate capacity. 248
political) so that Community Power can continue to take an active role in mitigating and reducing such barriers. Key activities for this work include coordination and collaboration with state regulatory agencies like the California Public Utilities Commission (CPUC), California Energy Commission (CEC) and California Independent System Operator (CAISO), stakeholders, developers, member agencies and internal staff as well as engagement and advocacy at the local, regional, state and national policy level.

Ultimately, Community Power’s Local Development Strategy will need to remain flexible and iterative to ensure Community Power staff can adapt and adjust to its power portfolio gaps and opportunities, new energy technologies, funding opportunities, workforce requirements, member agency needs or other unknowns as the local development and energy space remains a dynamic one.
249
Table of Contents:

1. Vision & Guiding Principles

2. Local Development Opportunity Areas

3. Community & Stakeholder Engagement

4. Implementation through Procurement Pathways

5. Glossary of Key Terms
250
Vision & Guiding Principles
To accurately capture the vision of local development, it is critical to first define what “local” means. To meet the established 150 MW goal, new projects will have to be sited within the following geographic boundaries:
• San Diego County
o Inclusive of the 17 federally recognized Tribes located within San Diego County • Imperial County
Local development efforts are also guided by the following principles:

Transparency
Community Power will adhere to a transparent procurement process for local development Projects, including but not limited to publicly issued Requests for Offers (RFOs) and clearly defined evaluation criteria as currently established through Community Power’s standard energy procurement process. Project selections will be presented to the Board of Directors for approval. Community Power will also provide periodic updates on project status and key milestones to the Community Advisory Committee or Board of Directors at their request to maintain accountability and public visibility.

Workforce Development
Projects are expected to create high quality local jobs in this sector that support healthy families and vibrant communities. Therefore, as outlined in Community Power’s Inclusive and Sustainable Workforce Policy, projects are incentivized to commit to the highest of workforce standards through the explicit evaluation of workforce commitments in competitive solicitations via the Energy Proposal Evaluation Criteria (EPEC). Developers can secure higher rankings if they commit to executing project labor agreements (PLAs) or meeting certain thresholds of union labor, local hiring, veteran employed/owned, etc.

Energy Capacity
Local development projects should support system reliability and resource adequacy needs while aligning with Community Power’s operational, financial, and staffing capacity.

Feasibility
Community Power prioritizes projects that demonstrate higher project viability while also balancing efforts to encourage development of strategic projects that may need additional advocacy, infrastructure investment or funding. Key indicators of project viability include site control status, financing pathways, whether applications for permitting have been submitted, and progress on interconnection & deliverability.
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Ratepayer Protection
Local development projects should offer competitive pricing and guarantee certain energy and capacity benefits for Community Power’s ratepayers. Additional evaluative consideration is given for distributed local projects that contribute toward the CPUC’s local resource adequacy requirements, displacing the need to procure resource adequacy in the short-term markets.

Equity and Community Benefit
Projects should deliver meaningful benefits to the communities in which they are located, particularly in our Communities of Concern.

Community Scale
Community scale distributed renewable energy projects offer a unique and complementary form of value. Because they are typically sited close to load and within existing developed areas, these projects can be deployed more quickly, create opportunities for a diverse workforce, and strengthen resilience by supporting critical facilities and reducing reliance on distant generation. Their smaller footprint and use of existing infrastructure can also lessen environmental impacts, integrate more seamlessly into communities, and reduce community disruption relative to larger greenfield development. 252
Local Development Opportunity Areas
Community Power has spent a considerable amount of time and resources exploring the distributed resource landscape in effort to understand where the best opportunities are likely to present and to identify obstacles that hinder local development opportunities. This was accomplished largely through running solicitations, receiving dozens of offers from a broad spectrum of developers, and running these offers through both our long-term financial models as well as our holistic Energy Proposal Evaluation Criteria.

With the support of Community Power leadership and our Energy Contracts Working Group, staff recommended and advanced a handful of projects through board approval and contract execution. Additionally, through the collection and analysis of market price datapoints staff has identified a number of foundational constraints that warrant immediate attention, as these constraints present a major roadblock to project viability. These vulnerabilities can be broadly categorized as grid interconnection, operational limitations and restricted resource valuation, generally a result of state and investor-owned utility policies and practices that have not prioritized distributed resources. In response to these realities, Community Power has identified several opportunities to increase project viability and value, including engagement on the policy and advocacy front in partnership with other Community Choice Aggregators and industry stakeholders. Having identified many of these challenges as relatively unique to front-of-the-meter resources, Community Power has also started exploring alternative wholesale procurement vehicles that leverage behind-the-meter resources, akin to how Community Power’s Programs team invests in behind-the-meter resources to support and provide value to our electrical grid. As a result, staff is engaged on both fronts, actively managing a robust and diverse pipeline of local front-of-the-meter opportunities, while paving the way for alternative pathways of local development that would provide more certainty of project success with currently unrealized value streams.

Integral to the front-of-the-meter effort will be continued engagement directly with SDG&E on mitigating cost prohibitive barriers to successful interconnection and deliverability within its territory.

Local development opportunities span a wide range of sectors across San Diego and Imperial Valley. While many potential projects are likely to come from commercial and industrial sites, projects may emerge from Member Agencies, schools (both k-12 and higher education), healthcare facilities, public utilities (e.g. irrigation or water), as well as Tribes, nonprofit organizations, private property, agricultural operations, and housing providers. Each of these sectors has their own unique and varied energy needs and priorities.

Recognizing the diversity of sectors and the opportunities they could present, the Local Development Strategy is designed to remain flexible while grounded in operational and 253
market realities. Cultivating a broad and diverse pipeline of potential projects must also take a long-term view that recognizes the role of future interconnection upgrades, policy advocacy, partnerships, and new funding opportunities for projects that may not yet be fully feasible.

Sector Analysis & Energy Proposal Evaluation Criteria Evaluation A sector-based analysis provides one way to understand the range of local development opportunities. By examining opportunities by sector, Community Power can better assess differing load profiles, siting constraints, site host eagerness and expediency, development readiness, and potential co-benefits.

The graphic below represents a small selection of sectors Community Power could engage with and general descriptions of opportunities and risks attributes on their partnership potential.

Commercial & Industrial Member Agencies Public Agencies Tribal Nations Real Estate Opportunity Large footprint regionally with diverse range of partnerships
Collectively large, but with
potential real estate allocation
challenges
Varies with certain agencies (eg
airport, port, schools, water
districts) offering unique
opportunity
Extensive but limited based on
proximity and sovereignty
sensitivity
Ease and Expediency of
Transactions
Relative ease due to general
autonomy of corporate decision
processes
Likely more complicated and
longer term, especially in early
stages, due to process and
stakeholder engagement
Varies by agency, but likely
relative ease with agencies that
have energy project experience
and/or are highly motivated
Unknown due to relative
nascence of engagement with
tribal nations on energy projects
Site Turnover Risk Relatively high risk due to nature
of private industry
Very low Very low Unknown but likely varies
Resilience and Other Energy
Drivers
Depending on industry, likely
driven by some combination of
energy cost savings and
resilience
Large appetite for resilience at
certain critical facilities
Varies, but high desire for
resilience at sites that can serve
as community resilience hubs
Likely high desire for resilience
particularly in areas that
experience grid disruptions
Further analysis of specific sectors can yield additional information:

Warehouse Rooftops REITs / Commercial Real Estate Data Centers School Districts, Port of San Diego, Airport, others
Additional
Considerations:
• Large, unobstructed
rooftop potential
• Generally smaller
electricity usage if not
cold storage
• Industrial zoned locations
less vulnerable to
neighbor protest
• REITs with large
portfolios offers
scalability
• Electricity usage
dependent on site
• REITs particularly
interested in
predictable
financial benefits
• Very large electricity
usage, likely on new or
upgraded circuits
• Data centers may prefer
or be required to
provide their own
generation resources
• Certain public
agencies already
have substantial
renewable
portfolios
• These projects that
are PV only are
prime candidates
for added storage
which benefit
Community Power
but wouldn’t
otherwise pencil
Strategic Evaluation – Energy Proposal Evaluation Criteria Determining which projects merit investment requires the establishment of clear, measurable criteria that balance project viability with overall value to Community Power and its customers. For this reason, Community Power staff evaluate local development projects utilizing the Energy Proposal Evaluation Criteria (EPEC) framework. The EPEC framework 254
identifies not only a project’s forecasted costs, revenue and compliance value, but also additional co-benefits that extend beyond wholesale markets and regulatory compliance.

These benefits may include enhanced grid and community resilience, improved local air quality, job creation, and broader local economic development.

Community Power has established a set of evaluation criteria to guide the review and comparison of local development project opportunities. These criteria are intended to provide a consistent and transparent basis for assessing projects across sectors and development types:
• Co-benefits to Community Power and its customers
• Contribution to system and community resilience
• Impacts on customer rates
• Project price and cost competitiveness
• Viability and overall project readiness
• Environmental impacts
• Workforce development and local economic impacts
• Resource adequacy and capacity contributions
As a result, projects are rated through a holistic lens which recognizes the best and total value projects may bring to Community Power and ratepayers.
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Community and Stakeholder Engagement
To meet the 150 MW goal, Community Power staff is expecting to procure energy from numerous projects located throughout San Diego and Imperial County. These projects could range in size from small behind-the-meter storage projects located at a neighborhood community center to larger front-of-meter solar and storage projects that span across multiple large commercial rooftops, parking lots, or open land.

Community Power is committed through its procurement decisions to be thoughtful of the surrounding communities. As future procurement pathways are developed and implemented, Community Power will work to create specific community and stakeholder engagement strategies based on the level of impact on interested stakeholders. These community and stakeholder strategies may assess the proximity to sensitive receptors for any proposed project and may require that the developer educate and inform the immediately surrounding businesses and residents on the proposed project to mitigate or avoid adverse effects on the community. The purpose of this engagement will be twofold - ensure that proposed projects are meeting the needs of the communities they are in while preventing unnecessary delays to project construction.

While the specific engagement strategies will be developed to satisfy the uniqueness of each potential procurement pathway, below are recommendations for outreach that could be required of a project developer:

Stakeholder Identification and Analysis
• Identify affected and interested stakeholders, including nearby residents, businesses, community-based organizations, local governments, and Tribal entities (if applicable). • Assess stakeholder interests, potential concerns, and appropriate engagement methods.

Early and Ongoing Engagement
• When appropriate, initiate outreach early in the project development process, prior to key permitting or construction milestones.
• Maintain regular communication as the project advances to address questions, concerns, and changes.

Targeted Community Presentations
• Conduct informational presentations or briefings for local civic groups, neighborhood associations, business organizations, and other community leaders. 256
• Provide clear, accessible information on project scope, timeline, benefits, and potential impacts.

This outreach and engagement is also critical for the municipal staff members in development services, permitting departments and the elected officials they report to. The alignment of decarbonization and Climate Action Plan initiatives with Community Power’s local development and programmatic goals prevents duplicative efforts and wasted resources.

While developers remain primarily responsible for conducting stakeholder engagement, Community Power will provide limited support consistent with its role as a public agency.

Community Power support may include:

Responsiveness and Role Clarity
• Serve as a point of contact for questions related to Community Power policies, procurement processes, and program objectives.

Public Information
• Maintain current, publicly accessible information on Community Power’s website regarding local development priorities, procurement processes, and solicitation FAQs.

Facilitating Appropriate Connections
• Assist in facilitating introductions to and between relevant Member Agency staff, local government representatives, or other appropriate stakeholders, where appropriate and consistent with public agency requirements.

In addition to external stakeholder engagement, Community Power will ensure its internal processes support effective coordination and decision making as local development projects advance. Community Power staff will maintain alignment and information sharing across teams to ensure that as projects enter the development or procurement queue, all relevant staff are informed early and equipped to assess any potential project implications. 257
Implementation through Procurement Pathways
Local development projects may advance through a variety of procurement pathways, each with distinct characteristics related to their origination source, value-stack, siting, ownership, risk, and community benefit. Generally, projects originate through either a competitive solicitation process or through a distinct board approved program or initiative. Any project that Community Power might contract with will be connected to the local distribution grid in one of two ways, either behind-the-meter (BTM) or front-of-the-meter (FTM).

There are a few specific pathways that are worth noting, due to their relative unique attributes, including feed-in tariff supported projects (FIT), Solar Advantage projects, and public private partnerships. Additionally, Community Power may establish procurement initiatives that benefit from the prequalification of a pool of developers who would address the market within a specific and predetermined framework.

Together, these procurement pathways provide flexibility to support a diverse range of project types across diverse sectors. Not all pathways are appropriate for all projects, and selection of a development pathway will likely depend on project specific conditions, financial requirements, space availability, siting requirements, and other various determinants.

Additionally, Community Power maintains an active Request for Information (RFI) for Local Renewable Energy and Energy Storage. Submissions for this RFI are accepted on a rolling basis and allow Community Power to partner with developers on new and existing, wholesale renewable energy projects delivering renewable energy within San Diego and Imperial Counties.

Behind-the-Meter (BTM)
Community Power is currently designing a behind-the-meter (BTM) initiative where a renewable energy and/or battery storage project is developed and installed behind-the-meter at a host customer site, with Community Power directly contracting for the energy and capacity provided by the project. The site host provides access to physical space (such as rooftops, parking structures, or land) and receives compensation for use of the site, which may take the form of lease payments and/or bill discounts.

Project ownership and operation most commonly falls under the responsibility of a third-party developer, while Community Power contracts for the delivery of energy from the project and any battery attributes. Projects that interconnect behind-the-meter are also more likely to be approved for interconnection, and additionally, grid benefits are monetized through SDG&E’s tariffs and Community Power resource adequacy benefits are realized through a reduction in our total load served. This structure allows Community Power to 258
secure local generation and the associated benefits with less risk and greater financial benefit, while enabling site hosts to realize financial value without assuming development or operational risk or responsibilities. Also, batteries deployed through BTM procurement pathways provide host sites with the fundamental equipment needed to potentially offer resilience solutions, providing backup power during an outage.

Front-of-the-Meter (FTM)
Under the FTM development pathway, renewable energy projects are interconnected directly to the distribution grid on the utility side of any customer meters and provide CAISO market revenues as well as providing necessary compliance attributes. Community Power procures energy, capacity, and associated attributes from these projects through standard contracting mechanisms, consistent with typical load serving entity procurement practices. FTM procurement is the typical configuration for any projects that a load serving entity (LSE) would historically contract with, most of which are utility-scale, making it the more established and tested pathway.

The largest distributed projects have historically been and will likely continue to generally be FTM resources, presenting attractive economies of scale and the ability to achieve Community Power’s MW target with fewer overall projects. And larger FTM projects present unique opportunities for collaboration with key partners, such as the US military or other large institutions in the San Diego region, including community microgrid projects.

Developers wishing to present local FTM opportunities to Community Power can do so utilizing the Local Request for Information (RFI), which currently accepts proposals on a rolling basis.

Feed-in Tariff (FIT)
Under the FIT development pathway, eligible small and community-scale front-of-the-meter distributed renewable energy projects may sell energy to Community Power pursuant to an adopted FIT schedule and a standard, simplified form Power Purchase Agreement. This pathway is intended to provide a transparent, streamlined option for qualifying projects to deliver renewable energy to Community Power without participation in a competitive solicitation.

Projects participating in the FIT pathway must meet defined eligibility requirements and are subject to applicable program terms, pricing, and capacity limits. Community Power retains discretion over program design and implementation, including the right to revise the FIT schedule, application materials, contract terms, and is not obligated to enter into a FIT Power Purchase Agreement unless and until an agreement is duly executed. FIT projects are 259
evaluated primarily on eligibility and compliance with program requirements, while remaining subject to feasibility, interconnection, and deliverability considerations.

Solar Advantage
Under the Solar Advantage pathway (otherwise known as the Disadvantaged Communities Green Tariff) community-scale, front-of-meter solar projects located in or near disadvantaged communities are developed to deliver renewable energy directly to Community Power and provide targeted energy bill benefits to qualifying low-income residential customers. These projects are procured through a dedicated competitive process that invites qualified developers to propose eligible projects.

Once operational, Solar Advantage projects are expected to deliver renewable energy into the grid while eligible customers receive a 20% discount on their electricity bill for up to 20 years.

Community Power has issued two RFO’s and is expecting to issue a third RFO in Spring 2026.

Community Power’s total allocation of capacity for this program is 20.16 MW with an intended enrollment of 9,600 households.

Public-Private Partnerships
Community Power has established a strong foundation for public-private partnerships in support of the clean energy transition through its Clean Energy Grants program in collaboration with the San Diego Foundation. Across the region, there is growing interest among funders in supporting resilience focused programs and capital investments that deliver long term sustainability benefits, especially in rural areas, with the military, for school districts, and in Communities of Concern. Public private partnerships offer an opportunity to strategically align Community Power’s local development goals with private and philanthropic resources.

Community Power will consider public private partnerships as a strategic tool to advance local development opportunities that may not be achievable through traditional procurement. Partnerships will be evaluated based on their ability to align Community Power’s local development goals with private or philanthropic capital while adhering to Community’s Power governance structure and public agency procurement rules.

Key considerations for public private partnerships include:
• Alignment with Public Purpose: Partnerships should advance Community Power’s mission, policy goals, and community benefit objectives, including affordability, resilience, and sustainability.
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• Leverage of External Capital: Projects should meaningfully leverage private or philanthropic funding to reduce reliance on ratepayer dollars and improve overall project viability.
• Risk and Governance: Roles, responsibilities, and risks should be clearly defined and appropriately allocated among partners, with Community Power retaining oversight consistent with its governance and regulatory obligations. • Feasibility and Deliverability: Projects must demonstrate realistic development pathways, including interconnection, permitting, and operational readiness, even when supported by external funding.
• Transparency and Accountability: Partnership arrangements should be subject to public review and approval where required, with clear reporting on project status, use of funds, and outcomes.

Of particular interest are potential partnerships with the military. Military installations, as large and energy-intensive facilities with unique resilience needs, present a significant opportunity for renewable generation, microgrids, and energy storage development. Partnerships between Community Power and the military offer a pathway to align local development goals with federal resources and long-term energy demand.

Priorities
Each of the pathways previously discussed carries different timelines, risk profiles, and development requirements, and should be applied where it is most likely to deliver best value for our ratepayers. To meet the 150 MW goal by 2035, Community Power should consider each of these pathways in a purposeful and strategic manner. • Prioritize engagement with SDG&E on interconnection & deliverability. The viability of local development projects will depend not only on site control, permitting, and economics, but on the ability to secure timely and cost-effective paths to interconnection and deliverability. Early, direct engagement with SDG&E is therefore critical to identify circuit constraints, upgrade needs, and feasible points of interconnection before significant time and resources are committed. • Prioritize BTM development as a near-term opportunity. BTM projects often leverage existing power infrastructure, face fewer permitting and interconnection challenges, and can be deployed more quickly at lower cost while delivering additional value. This pathway is well suited for early action, particularly with public agencies, schools, and commercial and industrial customers, and can deliver immediate co-benefits. 261
• Selectively approach FTM opportunities that meet certain feasibility criteria. FTM projects typically involve longer development timelines including more complex interconnection processes that may result in increased project costs or project infeasibility. As a result, this pathway is best aligned with projects that demonstrate strong deliverability, approved interconnection, and have strong financial backing. • Consider public private partnerships to unlock more complex opportunities. Public private partnerships may be appropriate where projects require additional capital, shared risk, or long-term coordination across multiple stakeholders.

In order for Community Power to be best positioned to advance viable local development opportunities, proactive engagement is necessary. This includes, but is not limited to, the following actions:
• Assessing appropriate procurement pathways early in project development (e.g., behind-the-meter, front-of-meter, Feed-in Tariff, Solar Advantage, or partnership models) to align project structure with Community Power power resource portfolio needs, site conditions, interconnection feasibility, and development readiness. • Designing and piloting new procurement pathway(s) that mitigate risks to viability and extract maximum project value to Community Power and its ratepayers • Conducting a robust and comprehensive assessment of regional opportunities and constraints in regard to interconnection and deliverability conditions and develop a “heatmap” of high priority development areas
• Educating decision makers on key project considerations and various procurement pathways, including information about behind-the-meter and front-of-meter development options
• Monitoring policy, regulatory, and funding developments that may unlock future local development opportunities, including local, state and federal grants/incentives • Facilitating early-stage coordination among stakeholders to help identify common barriers, shared infrastructure needs, and potential partnership models As Community Power staff implements the Local Development Strategy through these and future designed procurement pathways, regular assessments of these procurement pathways will be conducted to ensure available capacity and resources are being directed appropriately. 262
Glossary of Key Terms
Battery Energy Storage Systems (BESS): Battery Energy Storage Systems are technologies that store electrical energy for later use and discharge it to support grid reliability, energy shifting, and other operational needs. BESS can be deployed at various scales and locations, including front-of-meter and behind-the-meter applications.

Behind-the-meter: Behind-the-meter refers to energy resources located on the customer side of the utility meter. These resources primarily serve on-site load and may also provide grid services where permitted.

Climate Action Plans: Climate Action Plans are local or regional policy documents that outline strategies to reduce greenhouse gas emissions and increase climate resilience. They often include targets, implementation measures, and timelines adopted by governing bodies.

Communities of Concern: Communities identified by California Climate Investments (Assembly Bill 1550 and Senate Bill 535) that includes disadvantaged communities identified by CalEnviroScreen 4.0 and low-income communities and households with incomes either at or below 80% of the statewide median or below a threshold designated as low-income by the Department of Housing and Community Development, as well as the additional census tracts identified by the cities of San Diego and Chula Vista through their Climate Equity Index reports.

Community Scale – used in Community Power's workforce standards to distinguish the evaluation of projects under 10 MW versus projects sized 10+ MW, which are defined as "utility-scale". A minimum size threshold has not been established for this definition, but practically speaking, this is referring to anything that’s not a residential resource as the floor.

Deliverability: The certification of a resource to be counted against RA obligations, and a product of technical studies performed by CAISO to confirm that a resource can deliver energy to the grid during stressed, high-demand conditions. Similar to interconnection, deliverability is a generally difficult to obtain, especially for distributed resources in the San Diego region.

Distributed Energy Resource (DER):

1. Any resource, either BTM or FTM, that is connected to SDG&E's distribution network, adhering to the CEC's definition of a DER, or

2. For the purposes of Community’s Power’s goal, resources connected to SDG&E’s transmission network if the resource is located in an urban or suburban area as defined by SANDAG's Census Urban Areas database
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Energy Proposal Evaluation Criteria (EPEC): The set of criteria Community Power uses for the evaluation of energy and capacity proposals received via solicitations. These criteria include an assessment of project location, quantitative value, project development, community benefits, workforce standards and environmental stewardship.

Front-of-meter: Front-of-meter refers to energy resources located on the utility side of the meter and interconnected directly to the distribution or transmission system. These resources primarily serve grid-level functions rather than individual customer load.

Greenfield Development: Greenfield development refers to projects sited on previously undeveloped or minimally disturbed land. These projects may face greater permitting, environmental review, and infrastructure development requirements.

Infill Development: Infill development refers to projects located within already developed or previously disturbed areas, such as rooftops, parking facilities, or industrial sites. Infill projects often leverage existing infrastructure and may reduce land-use and environmental impacts.

Interconnection: Interconnection is the process of physically and electrically connecting an energy resource to the utility distribution or transmission system. Front-of-the-meter interconnections are regulated by FERC at the federal level, while behind-the-meter interconnections are regulated by the CPUC at the California state level, each having a distinct set of requirements.

Load Serving Entity (LSE): Any entity, including a load aggregator or power marketer, that serves end-users within a control area and has been granted the authority or has an obligation pursuant to state or local law, regulation, or franchise to sell electric energy to end-users located within the control area Long-duration energy storage: Long-duration energy storage refers to storage resources capable of discharging energy for extended periods, typically eight hours or more. These resources can support grid reliability during prolonged periods of high demand or low renewable generation.

Member Agencies: Member Agencies are the local governments that jointly govern and participate in Community Power. These agencies provide policy direction through representation on the San Diego Community Power Board of Directors. Community Power has seven active member agencies: the Cities of San Diego, Chula Vista, Encinitas, La Mesa, Imperial Beach and National City and the County of San Diego.

Renewable Energy Project: A Renewable Energy Project is a facility or system that generates electricity from renewable resources such as solar, wind, geothermal, biomass, or eligible hydroelectric sources. Will often be referred to as “project” throughout this document. 264
Resource Adequacy: A capacity-based compliance requirement that all CA load serving entities (LSEs) are subject to, and a fairly crucial element of renewable and storage project value. RA requirements are determined based on each LSE’s load served.

Sensitive Receptors - Specific populations, locations, or facilities that are highly susceptible to adverse health effects from environmental stressors, such as air pollution, noise, or hazardous materials. They typically include, but are not limited to, residential areas, schools, daycare centers, hospitals, and nursing homes
Short-duration energy storage: Short-duration energy storage refers to storage resources capable of discharging energy for limited periods, typically less than eight hours. These resources are commonly used for peak shaving, load shifting, and ancillary services. 265
Glossary
AB – Assembly Bill: An Assembly Bill is a piece of legislation that is introduced in the Assembly. In other words, the Assembly (rather than the Senate) is the bill’s house of origin in the Legislature. In California, it is common for legislation to be referred to by its house of origin number even after it becomes law. However, because bill numbers “reset” and start again from 1 in each legislative session, it is less confusing to include chapter and statute information when referring to a bill that has become law; for example, SB 350 (Chapter 547, Statutes of 2015).

AL - Advice Letter: An Advice Letter is a request by a California Public Utilities Commission (CPUC) jurisdictional entity for Commission approval, authorization or other relief.

ALJ – Administrative Law Judge: ALJs preside over CPUC cases to develop the evidentiary record and draft proposed decisions for Commission action.

ARB – Air Resources Board: The California Air Resources Board (CARB or ARB) is the “clean air agency” in the state government of California. CARB is charged with protecting the public from the harmful effects of air pollution and developing programs and actions to fight climate change.

AReM – Alliance for Retail Energy Markets: AReM is a not-for-profit corporation that advocates for continued development of successful customer choice in retail energy markets and provides a focused voice for competitive energy retailers and their customers in select public policy forums at the state level. It represents direct access providers such as Constellation NewEnergy and Direct Energy.

BayREN – Bay Area Regional Energy Network: BayREN offers regionwide energy programs, services and resources to members of the public by promoting energy efficient buildings, reducing carbon emissions and building government capacity.

CAISO – California Independent System Operator: CAISO is a nonprofit public benefit corporation that oversees the operation of the California bulk electric power system, transmission lines and electricity market generated and transmitted by its members (approximately 80% of California’s electric flow). Its stated mission is to “operate the grid reliably and efficiently, provide fair and open transmission access, promote environmental stewardship and facilitate effective markets and promote infrastructure development.” CAISO is regulated by the Federal Energy Regulatory Commission (FERC) and governed by a five-member governing board appointed by the governor.

CalCCA – California Community Choice Association: CalCCA is a statewide association, made up of Community Choice Aggregators (CCAs), that represents the interests of California’s community choice electricity providers.
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CALSEIA – California Solar Energy Industries Association: CALSEIA represents more than 200 companies doing solar-related business in California, including manufacturers, distributors, installation contractors, consultants and educators. Members’ annual dues support professional staff and a lobbyist who represents the common interests of California’s solar industry at the Legislature, Governor’s Office and state and local agencies.

CALSLA – California City-County Street Light Association: CALSLA is a statewide association representing cities, counties and towns before the CPUC that is committed to maintaining fair and equitable streetlight electricity rates and facilities charges and disseminating streetlight-related information.

CAM – Cost Allocation Mechanism: CAM is the cost recovery mechanism to cover procurement costs incurred in serving the central procurement function.

CARB – California Air Resources Board: The CARB is charged with protecting the public from the harmful effects of air pollution and developing programs and actions to fight climate change in California.

CARE – California Alternative Rates for Energy: CARE is a state program for low-income households that provides a 30% discount on monthly energy bills and a 20% discount on natural gas bills. It is funded through a rate surcharge paid by all other utility customers.

CBE – Communities for a Better Environment: CBE is an environmental justice organization that was founded in 1978. The mission of CBE is to build people’s power in California’s communities of color and low-income communities to achieve environmental health and justice by preventing and reducing pollution and building green, healthy and sustainable communities and environments.

CCA – Community Choice Aggregator: A community choice aggregator, sometimes referred to as community choice aggregation, is an entity of local governments that procure power on behalf of their residents, businesses and municipal accounts from an alternative supplier while still receiving transmission and distribution service from their existing utility provider. CCAs are an attractive option for communities that want more local control over their electricity sources, more green power than is offered by the default utility, and/or lower electricity prices. By aggregating demand, communities gain leverage to negotiate better rates with competitive suppliers and choose greener power sources.

CCSF – City and County of San Francisco: The City and County of San Francisco often engage in joint advocacy before the CPUC. San Francisco operates CleanPowerSF, a CCA.

CEC – California Energy Commission: The CEC is the primary energy policy and planning agency for California, whose core responsibilities include advancing state energy policy, achieving energy efficiency, investing in energy innovation, developing renewable energy, transforming transportation, overseeing energy infrastructure and preparing for energy emergencies.

CEE – Coalition for Energy Efficiency: CEE is a nonprofit composed of U.S. and Canadian energy-efficiency administrators working together to accelerate the development and availability of energy-efficient products and services.
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CLECA – California Large Energy Consumers Association: CLECA is an organization of large, high-load factor industrial customers located throughout the state; its members are in the cement, steel, industrial gas, pipeline, beverage, cold storage, food packaging and mining industries and their electricity costs comprise a significant portion of their costs of production. Some members are bundled customers, others are Direct Access (DA) customers, and some are served by Community Choice Aggregators (CCAs); a few members have onsite renewable generation.

CPUC – California Public Utility Commission: The CPUC is a state agency that regulates privately owned electric, natural gas, telecommunications, water, railroad, rail transit and passenger transportation companies, in addition to authorizing video franchises.

C&I – Commercial and Industrial: C&I customers are business customers who generally consume much higher volumes of electricity and gas. Many utilities segment their C&I customers by energy consumption (small, medium and large).

CP – Compliance Period: A Compliance Period is the time period to become Renewables Portfolio Standard (RPS) compliant, set by the California Public Utilities Commission (CPUC).

DA – Direct Access: Direct Access is an option that allows eligible customers to purchase their electricity directly from third-party providers known as Electric Service Providers (ESPs).

DA Cap: The DA Cap is the maximum amount of electric usage that may be allocated to Direct Access customers in California or, more specifically, within an investor-owned utility service territory.

DACC – Direct Access Customer Coalition: DACC is a regulatory advocacy group composed of educational, governmental, commercial and industrial customers that utilize direct access for all or a portion of their electrical energy requirements.

DA Lottery: The DA Lottery is a random drawing by which DA waitlist customers become eligible to enroll in DA service under the currently applicable Direct Access Cap.

DA Waitlist: The DA Waitlist consists of customers that have officially registered their interest in becoming a DA customer but are not yet able to enroll in service because of DA cap limitations.

DAC – Disadvantaged Community: “Disadvantaged communities” refers to the areas throughout California that most suffer from a combination of economic, health and environmental burdens.

These burdens include poverty, high unemployment, air and water pollution and the presence of hazardous wastes as well as high incidences of asthma and heart disease. One way that the state identifies these areas is by collecting and analyzing information from communities statewide.

CalEnviroScreen, an analytical tool created by the California Environmental Protection Agency (CalEPA), combines different types of census tract-specific information into a score to determine which communities are the most burdened or “disadvantaged.” DASR – Direct Access Service Request: DASR is a request submitted by C&I customers to become direct access eligible.
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Demand: Demand refers to the rate at which electric energy is delivered to or by a system or part of a system, generally expressed in kilowatts (kW), megawatts (MW) or gigawatts (GW), at a given instant or averaged over any designated interval of time. Demand should not be confused with Load or Energy.

DER – Distributed Energy Resource: A DER is a small-scale physical or virtual asset (e.g., EV charger, smart thermostat, behind-the-meter solar/storage, energy efficiency) that operates locally and is connected to a larger power grid at the distribution level.

Distribution: Distribution refers to the delivery of electricity to the retail customer’s home or business through low-voltage distribution lines.

DLAP – Default Load Aggregation Point: In the CAISO’s electricity optimization model, DLAP is the node at which all bids for demand should be submitted and settled.

DR – Demand Response: DR is an opportunity for consumers to play a significant role in the operation of the electric grid by reducing or shifting their electricity usage during peak periods in response to time-based rates or other forms of financial incentives.

DRP – Distributed Resource Plans: Distributed Resource Plans are required by statute and intended to identify optimal locations for the deployment of distributed resources.

DWR – Department of Water Resources: DWR is the state agency charged with managing California’s water resources, systems and infrastructure in a responsible, sustainable way.

ECR – Enhanced Community Renewable: ECR is an IOU (Investor-Owned Utility) program that reflects the “Community Solar” model of renewable energy purchasing. Customers sign up to purchase a portion of a local solar project directly from a developer at a level that meets at least 25% and up to 100% of their monthly electricity demand. The customer pays the developer for the subscribed output and receives a credit on their utility bill that reflects their enrollment level.

ED – Energy Division: The CPUC’s Energy Division develops and administers energy policy and programs to serve the public interest, advise the Commission and ensure compliance with Commission decisions and statutory Mandates.

EE – Energy Efficiency: Energy Efficiency refers to the use of less energy to perform the same task or produce the same result. Energy-efficient homes and buildings use less energy to heat and cool and run appliances and electronics, and energy-efficient manufacturing facilities use less energy.

ELCC – Effective Load Carrying Capacity: ELCC is the additional load met by an incremental generator while maintaining the same level of system reliability. For solar and wind resources, the ELCC is the amount of capacity that can be counted for Resource Adequacy purposes.

EPIC – Electric Program Investment Charge: The EPIC program was created by the CPUC to support investments in clean energy technologies that provide benefits to the electricity ratepayers of Pacific Gas and Electric (PG&E), San Diego Gas & Electric Company (SDG&E) and Southern California Edison Company (SCE).
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ERRA – Energy Resource Recovery Account: ERRA proceedings are used to determine fuel and purchased power costs that can be recovered in rates. The utilities do not earn a rate of return on these costs and recover only actual costs. The costs are forecast for the year ahead. If the actual costs are lower than forecast, then the utility gives money back, and vice versa.

ES – Energy Storage: Energy Storage is the capture of energy produced at one time for use at a later time to reduce imbalances between energy demand and energy production.

ESA – Energy Storage Agreement: An ESA refers to a battery services contract, a capacity contract, demand response contract or similar agreement.

ESP – Energy Service Provider: An Energy Service Provider is an energy entity that provides service to a retail or end-use customer.

EV – Electric Vehicle: An EV is a vehicle that uses one or more electric motors for propulsion.

FCR – Flexible Capacity Requirements: “Flexible capacity need” is defined as the quantity of resources needed by the CAISO to manage grid reliability during the greatest three-hour continuous ramp in each month. Resources will be considered as “flexible capacity” if they can sustain or increase output or reduce ramping needs during the hours of “flexible need.” FCR means the flexible capacity requirements established for LSEs by the CPUC pursuant to the CPUC decisions.

GHG – Greenhouse gas: Water vapor, carbon dioxide, tropospheric ozone, nitrous oxide, methane and chlorofluorocarbons (CFCs) are gases that cause the atmosphere to trap heat radiating from the earth. The most common GHG is carbon dioxide.

GRC – General Rate Case: General Rate Cases are proceedings used to address the costs of operating and maintaining the utility system and the allocation of those costs among customer classes. For California’s three large IOUs, the GRCs are parsed into two phases. Phase I of a GRC determines the total amount the utility is authorized to collect, while Phase II determines the share of the cost each customer class is responsible for and the rate schedules for each class. Each large electric utility files a GRC application every three years for review by the Public Advocate’s Office and interested parties and for approval by the CPUC.

GTSR – Green Tariff Shared Renewables: The GTSR program enables customers to receive 50 to 100 percent of their electricity demand from renewable sources. The GTSR program has two components:
the Green Tariff (GT) component and the Enhanced Community Renewables (ECR) component.

Through GT, a customer may pay the difference between their current generation charge and the cost of procuring 50 to 100 percent renewables. With ECR, a customer agrees to purchase a share of a community renewable (typically solar) project directly from a developer and in exchange will receive a credit from their utility for the customer’s avoided generation procurement.

GWh – Gigawatt-hour: This is the unit of energy equal to that expended in one hour at a rate of one billion watts. One GWh equals 1,000 megawatt-hours.
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ICA – Integration Capacity Analysis: The enhanced integrated capacity and locational net benefit analysis quantify the capability of the system to integrate Distributed Energy Resources (DERs) within the distribution system. Results are dependent on the most limiting element of the various power system criteria such as thermal ratings, power quality, system protection limits and safety standards of existing equipment.

IDER – Integrated Distributed Energy Resources: A CPUC proceeding that aims to more effectively coordinate the integration of demand-side resources in order to better meet customer and grid needs, while enabling California to attain its greenhouse gas reduction goals.

IDSM – Integrated Demand-Side Management: This is an approach that joins together all the resources utilities have at their disposal to plan, generate and supply electricity in the most efficient manner possible.

IEPA – Independent Energy Producers Association: IEPA is California’s oldest and leading nonprofit trade association, representing the interest of developers and operators of independent energy facilities and independent power marketers.

IMD – Independent Marketing Division: Under state law, IOUs are prohibited from lobbying or marketing on community choice unless the IOU forms an independent marketing division funded by shareholders rather than ratepayers. SDG&E and its parent company Sempra were permitted by the CPUC to create such an independent marketing division, which allowed SDG&E to lobby against plans to create a CCA program.

IOU – Investor-Owned Utility: An IOU is a private electricity and natural gas provider, such as SDG&E, PG&E or SCE, which are the three largest IOUs in California.

IRP – Integrated Resource Plan: An Integrated Resource Plan outlines an electric utility’s resource needs in order to meet expected electricity demand long-term. kW – Kilowatt: This is a measure of power where power (watts) = voltage (volts) x amperage (amps) and 1 kW = 1,000 watts.
kWh – Kilowatt-hour: This is a measure of consumption. It is the amount of electricity that is used over some period of time, typically a one-month period for billing purposes. Customers are charged a rate per kWh of electricity used.

LCE – Lancaster Choice Energy: LCE is the CCA that serves the City of Lancaster, California.

LCFS – Low Carbon Fuel Standard: This is a CARB program designed to encourage the use of cleaner low-carbon fuels in California, encourage the production of those fuels and, therefore, reduce greenhouse gas emissions.

LCR – Local (RA) Capacity Requirements: This is the amount of Resource Adequacy capacity required to be demonstrated in a specific location or zone.
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LMP – Locational Marginal Price: Each generator unit and load pocket is assigned a node in the CAISO optimization model. The model will assign a LMP to the node in both the day-ahead and real-time market as it balances the system using the least cost. The LMP is composed of three components: the marginal cost of energy, congestion and losses. The LMP is used to financially settle transactions in the CAISO.

LNBA – Locational Net Benefits Analysis: This is a cost-benefit analysis of distributed resources that incorporates location-specific net benefits to the electric grid.

Load: Load refers to an end-use device or customer that receives power from an energy delivery system. Load should not be confused with Demand, which is the measure of power that a load receives or requires. See Demand.

LSE – Load-serving Entity: Load-serving Entities have been granted authority by state, local law or regulation to serve their own load directly through wholesale energy purchases and have chosen to exercise that authority.

LTPP – Long-Term Procurement Rulemaking: This is an “umbrella” proceeding to consider, in an integrated fashion, all of the CPUC’s electric procurement policies and Programs.

MCE – Marin Clean Energy: MCE was the first CCA in California and began serving customers in 2010.

It serves customers in Contra Costa, Marin, Napa and Solano counties in Northern California.

MEO – Marketing Education and Outreach: This is a term generally used to describe various strategies to inform customers, such as to motivate consumers to take action on energy efficiency or conservation measures and change their behavior.

MW – Megawatt: A megawatt hour (Mwh) is equal to 1,000 Kilowatt hours (Kwh) or 1,000 kilowatts of electricity used continuously for one hour.

MWH – Megawatt-hour: This is a measure of energy.

NAESCO – National Association of Energy Service Companies: NAESCO is an advocacy and accreditation organization for energy service companies (ESCOs). Energy service companies contract with private and public-sector energy users to provide cost-effective energy efficiency retrofits across a wide spectrum of client facilities.

NBC – Non-Bypassable Charge: Non-Bypassable Charges are fees that are paid on every kilowatt-hour of electricity that is consumed from the grid. These charges can be used to fund things like energy assistance programs for low-income households and energy efficiency programs. These charges apply even if customers buy grid-supplied power from an outside power company such as a CCA.

NDA – Non-Disclosure Agreement: An NDA is a contract by which one or more parties agree not to disclose confidential information that they have shared with each other. 7 272
NEM – Net Energy Metering: NEM is a program in which solar customers receive credit for excess electricity generated by solar panels.

NRDC – Natural Resources Defense Council: NRDC is a nonprofit international environmental advocacy group.

NP-15 – North Path 15: NP-15 is a CAISO pricing zone usually used to approximate wholesale electricity prices in Northern California in PG&E’s service territory.

OIR – Order Instituting Rulemaking: An OIR is a procedural document that is issued by the CPUC to start a formal proceeding. A draft OIR is issued for comment by interested parties and made final by vote of the five commissioners of the CPUC.

OSC – Order to Show Cause: OSC is an order requiring an individual or entity to explain, justify or prove something.

ORA – Office of Ratepayer Advocates: The ORA is an independent consumer advocate within the CPUC, now called the Public Advocates Office.

PA – Program Administrator (for EE Business Plans): IOUs and local government agencies can be authorized to implement CPUC-directed energy efficiency programs.

PCE – Peninsula Clean Energy Authority: PCE is the CCA serving San Mateo County and all 20 of its cities and towns as well as the City of Los Banos.

PCC1 – RPS Portfolio Content Category 1: RPS Portfolio Content Category 1 includes bundled renewables where the energy and Renewable Energy Certificate (REC) are dynamically scheduled into a California Balancing Authority (CBA) such as the CAISO, also known as “in-state” renewables.

PCC2 – RPS Portfolio Content Category 2: RPS Portfolio Content Category 2 includes bundled renewables where the energy and Renewable Energy Certificate (REC) are from out of state and not dynamically scheduled to a CBA.

PCC3 – RPS Portfolio Content Category 3: RPS Portfolio Content Category 3 includes Unbundled Renewable Energy Certificate (REC).

PCIA or “exit fee” – Power Charge Indifference Adjustment: The Power Charge Indifference Adjustment (PCIA) is an “exit fee” based on stranded costs of utility generation set by the California Public Utilities Commission. It is calculated annually and assessed to customers of CCAs and paid to the IOU that lost those customers as a result of the formation of a CCA.

PCL – Power Content Label: The PCL is a user-friendly way of displaying information to California consumers about the energy resources used to generate the electricity they sell, as required by AB 162 (Chapter 313, Statutes of 2009) and SB 1305 (Chapter 796, Statutes of 1997). 8 273
PD – Proposed Decision: A PD is a procedural document in a CPUC Rulemaking that is formally commented on by parties to the proceeding. A PD is a precursor to a final decision voted on by the five commissioners of the CPUC.

PG&E – Pacific Gas & Electric: PG&E is the IOU that serves 16 million people over a 70,000-square-mile service area in Northern California.

PHC – Prehearing Conference: A PHC is a CPUC hearing to discuss the scope of a proceeding, among other matters. Interested stakeholders can request party status during these conferences.

Pnode – Pricing Node: In the CAISO optimization model, this is a point where a physical injection or withdrawal of energy is modeled and for which an LMP is calculated.

PPA – Power Purchase Agreement: A PPA is a contract used to purchase the energy, capacity and attributes from a renewable resource project.

PRP – Priority Review Project: These are transportation electrification pilot projects approved by the CPUC pursuant to SB 350 (Chapter 547, Statutes of 2015).

PRRR – Progress on Residential Rate Reform: Pursuant to a CPUC decision, the IOUs must submit to the CPUC and other parties periodic updates on the progress of their efforts to assist customers with residential rate design changes related to rate reform, including tier collapse and transition to a default time of use rate.

PUC – Public Utilities Code: The PUC is a California statute that contains 33 divisions; the range of topics within this code includes natural gas restructuring, private energy producers, telecommunication services, and specific municipal utility districts and transit authorities; the primary statute for governance of utilities as well as CCAs in California.

PURPA – Public Utilities Regulatory Policy Act: The PURPA is a federal statute passed in 1978 by Congress in response to the 1973 energy crisis to encourage fuel diversity via alternative energy sources and to introduce competition into the electric sector. It was intended to promote energy conservation (reduce demand) and promote greater use of domestic energy and renewable energy (increase supply).

RA – Resource Adequacy: Under its Resource Adequacy (RA) program, the California Public Utilities Commission (CPUC) requires load-serving entities — investor-owned utilities, electricity service providers and CCAs — to demonstrate in both monthly and annual filings that they have purchased capacity commitments of no less than 115% of their peak loads.

RAM – Renewables Auction Mechanism: This is a procurement program the investor-owned utilities (IOUs) may use to procure RPS eligible generation. The IOUs may use RAM to satisfy authorized procurement needs, for example, system Resource Adequacy needs, local Resource Adequacy needs, RPS needs, reliability needs, Local Capacity Requirements, Green Tariff Shared Renewables needs and any need arising from commission or legislative mandates. 9 274
RE – Renewable Energy: Renewable energy is energy from a source that is not depleted when used, such as wind or solar power.

REC - Renewable Energy Certificate: A REC is the property right to the environmental benefits associated with generating renewable electricity. For instance, homeowners who generate solar electricity are credited with 1 solar REC for every megawatt-hour of electricity they produce. Utilities obligated to fulfill an RPS requirement can purchase these RECs on the open market.

RES-BCT – Renewables Energy Self-Generation Bill Credit Transfer: This program enables local governments and universities to share generation credits from a system located on one government-owned property with billing accounts at other government-owned properties. The system size limit under RES-BCT is 5 MW, and bill credits are applied at the generation-only portion of a customer’s retail rate.

RFO – Request for Offers: This is a competitive procurement process used by organizations to solicit the submission of proposals from interested parties in response to a scope of services.

RPS - Renewable Portfolio Standard: RPS is a law that requires California utilities and other load-serving entities (including CCAs) to provide an escalating percentage of California qualified renewable power (culminating at 33% by 2020) in their annual energy portfolio.

SB – Senate Bill: A Senate Bill is a piece of legislation that is introduced in the Senate. In other words, the Senate, rather than the Assembly, is the house of origin in the Legislature for the Legislation.

SBP – Solar Billing Plan: The Solar Billing Plan, also known as the Net Billing Tariff or NEM 3.0, is the new method of compensating customer-sited renewable energy self-generation, intended to promote grid reliability and incentivize solar and battery storage.

SCE – Southern California Edison: SCE is the large IOU that serves the Los Angeles and Orange County area.

SCP – Sonoma Clean Power Authority: SCP is the CCA serving Sonoma County and surrounding areas in Northern California.

SDG&E – San Diego Gas & Electric: SDG&E is the IOU that serves San Diego County and owns the infrastructure that delivers Community Power energy to our customers.

SGIP – Self-Generation Incentive Program: SGIP is a program that provides incentives to support existing, new and emerging distributed energy resources (storage, wind turbines, waste heat to power technologies, etc.).

SUE – Super User Electric: This is an electric surcharge intended to penalize consumers for excessive energy use.

SVCE – Silicon Valley Clean Energy: SVCE is the CCA serving the communities in Santa Clara County. 10 275
TCR EPS Protocol – The Climate Registry Electric Power Sector Protocol: This refers to online tools and resources provided by The Climate Registry to assist organizations to measure, report and reduce carbon emissions.

TE – Transportation Electrification: For the transportation sector, electrification means replacing fossil fuels with electricity as the means of powering light-duty vehicles and medium- and heavy-duty trucks and buses. The primary goal is to reduce greenhouse gas (GHG) emissions and, ultimately, contribute to mitigating the effects of climate change on the planet.

Time-of-Use (TOU) Rates: TOU Rates refers to the pricing of delivered electricity based on the estimated cost of electricity during a particular time block. Time-of-use rates are usually divided into three or four time blocks per 24 hour period (on-peak, mid-peak, off-peak and sometimes super off-peak) and by seasons of the year (summer and winter). Real-time pricing differs from TOU rates in that it is based on actual (as opposed to forecasted) prices that may fluctuate many times a day and are weather sensitive, rather than varying with a fixed schedule.

TM – Tree Mortality: This is a term that refers to the death of forest trees and provides a measure of forest health. In the context of energy, as part of the Governor’s Tree Mortality Emergency Proclamation, the CPUC is tasked with utilizing its authority to extend contracts and take actions to authorize new contracts on bioenergy facilities that receive feedstock from high hazard zones.

TURN – The Utility Reform Network: TURN is a ratepayer advocacy group charged with ensuring that California IOUs implement just and reasonable rates.

Unbundled RECs: Unbundled RECs are renewable energy certificates that verify a purchase of a MWH unit of renewable power where the actual power and the certificate are “unbundled” and sold to different buyers.

VPP – Virtual Power Plant: A Virtual Power Plant is a cloud-based network that leverages an aggregation of distributed energy resources (DERs) to shift energy demand or provide services to the grid. For example, thousands of EV chargers could charge at a slower speed and hundreds of home batteries could discharge to the grid during a demand peak to significantly reduce the procurement of traditional supply resources.

VAMO – Voluntary Allocation, Market Offer: VAMO is the process for SDG&E to allocate a proportional share of its renewable portfolio to Community Power and other LSEs within the service territory.
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San Diego Community Power Board of DirectorsApril 23, 2026

San Diego Community Power Board of Directors
April 23, 2026