Agenda packet — Ava Community Energy Board of Directors, September 20, 2023 (part 1 of 2)

Board of Directors Meeting
Wednesday, September 20, 2023
6:00 pm
In Person
The Lake Merritt Room
Cal State East Bay - the Oakland Center
In the Transpacific Centre
1000 Broadway, Suite 109
Oakland, CA 94607
Or from the following locations:
• Wells Fargo Building - 2140 Shattuck Avenue, Floor 6, Berkeley, CA 94704 • City of Fremont, Human Resource Training Room, 3300 Capitol Avenue Building B, Fremont, CA 94538
• Sacramento Convention Center West Lobby, 1st Fl. 1400 J St., Sacramento, CA 95814 • Hyatt Regency Sacramento Business Center - 1209 L Street, CA 95814 • 1755 Harvest Landing Lane, Tracy, CA 95376
• Grand Sheraton lobby - 1230 J St, Sacramento, CA 95814 Via Zoom:
https://ebce-org.zoom.us/j/87023071843
Dial(for higher quality, dial a number based on your current location): US: +1 669 900 6833 or +1 346 248 7799 or +1 253 215 8782 or +1 929 205 6099 or +1 301 715 8592 or 888 475 4499 (Toll Free) or 877 853 5257 (Toll Free)
Webinar ID: 870 2307 1843
Meetings are accessible to people with disabilities. Individuals who need special assistance or a disability-related modification or accommodation to participate in this meeting, or who have a disability and wish to request an alternative format for the meeting materials, should contact the Clerk of the Board at least 2 working days before the meeting at (510) 906-0491 or [email protected].

If you have anything that you wish to be distributed to the Board of Directors, please email it to the clerk by 5:00 pm the day prior to the meeting.

1. Welcome & Roll Call

2. Pledge of Allegiance

3. Public Comment
East Bay Community Energy
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This item is reserved for persons wishing to address the Board on any EBCE-related matters that are not otherwise on this meeting agenda. Public comments on matters listed on the agenda shall be heard at the time the matter is called. As with all public comment, members of the public who wish to address the Board are customarily limited to two minutes per speaker and must complete an electronic speaker slip. The Board Chair may increase or decrease the time allotted to each speaker.

CONSENT AGENDA

4. Approval of Minutes from July 13, 2023 and July 19, 2023

5. Contracts Entered into (Informational Item)

6. Energy Prepay #3 Summary
Energy Prepay Transaction #3 Summary of Results

7. ARUP Contract Amendment
Increase funding and scope for Transportation Electrification consulting

8. MRP Incremental BESS
Consent to correct the record

REGULAR AGENDA

9. CEO Report

10. CAC Chair Report

11. Inclusion of New Communities: City of Lathrop (Action Item) Consider City of Lathrop EBCE/JPA membership

12. Update on Brand (Informational Item)
Share logo, updated timeline, list of items that will change on 10/24, overview of how we are supporting Muni-Pals

14. Update on Planning for Net Billing Tariff (NBT) (Informational Item) Brief review of NBT planning and overview of status

15. CAC Structure per Ad Hoc Board Committee Recommendation (Discussion Item) Discussion of Restructure CAC per Ad Hoc recommendation

16. Memorial Comments in Honor of Al Weinrub
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17. Board Member and Staff Announcements including requests to place items on future Board agendas

18. Closed Session
• Public Employee Performance Evaluation pursuant to Government Code § 54957:

Chief Executive Officer.

19. General Report Out of Closed Session

20.Adjourn
The next Board of Directors meeting will be held on Wednesday, October 18, 2023 at 6:00 pm.

Board of Directors Meeting
Community Advisory Committee Annotations
Wednesday, September 20, 2023
6:00 pm
In Person
The Lake Merritt Room
Cal State East Bay - the Oakland Center
In the Transpacific Centre
1000 Broadway, Suite 109
Oakland, CA 94607
Or from the following locations:
● Wells Fargo Building - 2140 Shattuck Avenue, Floor 6, Berkeley, CA 94704 ● City of Fremont, Human Resource Training Room, 3300 Capitol Avenue Building B, Fremont, CA 94538
● Sacramento Convention Center West Lobby, 1st Fl. 1400 J St., Sacramento, CA 95814 ● Hyatt Regency Sacramento Business Center - 1209 L Street, CA 95814 ● 1755 Harvest Landing Lane, Tracy, CA 95376
● Grand Sheraton lobby - 1230 J St, Sacramento, CA 95814 Via Zoom:
https://ebce-org.zoom.us/j/87023071843
Dial(for higher quality, dial a number based on your current location): US: +1 669 900 6833 or +1 346 248 7799 or +1 253 215 8782 or +1 929 205 6099 or +1 301 715 8592 or 888 475 4499 (Toll Free) or 877 853 5257 (Toll Free)
Webinar ID: 870 2307 1843
Meetings are accessible to people with disabilities. Individuals who need special assistance or a disability-related modification or accommodation to participate in this meeting, or who have a disability and wish to request an alternative format for the meeting materials, should contact the Clerk of the Board at least 2 working days before the meeting at (510) 906-0491 or [email protected].

If you have anything that you wish to be distributed to the Board of Directors, please email it to the clerk by 5:00 pm the day prior to the meeting.

1. Welcome & Roll Call

2. Pledge of Allegiance
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CONSENT AGENDA

4. Approval of Minutes from July 13, 2023 and July 19, 2023

5. Contracts Entered into (Informational Item)

6. Energy Prepay #3 Summary
Energy Prepay Transaction #3 Summary of Results

7. ARUP Contract Amendment
Increase funding and scope for Transportation Electrification consulting

8. MRP Incremental BESS
Consent to correct the record

REGULAR AGENDA

9. CEO Report

10. CAC Chair Report
A. Al Weinrub
B. Staff Response to the Sustainability and Climate Action Plan City Staff and EBCE Coordination Report
C. CalCCA filing in the CPUC Diablo Canyon extension proceeding D. Comments on Agenda Item 14. Update on Planning for Net Billing Tariff

11. Inclusion of New Communities: City of Lathrop (Action Item) Consider City of Lathrop EBCE/JPA membership
Excited for the solar and battery and EV potential of the new community.

12. Update on Brand (Informational Item)
Share logo, updated timeline, list of items that will change on 10/24, overview of how we are supporting Muni-Pals

13. 2022 Power Source Disclosure Annual Report and Power Content Label (Informational Item)
Requesting the Board to accept and attest to the 2022 Power Source Disclosure Report and Power Content Label
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Would like to see EBCE average as opposed to only the individual product offerings.

14. Update on Planning for Net Billing Tariff (NBT) (Informational Item) Brief review of NBT planning and overview of status
- Further explore the other benefits of adding batteries locally (congestion reduction, etc), and how to value those benefits for our customers, so that we may take those values into consideration and place batteries strategically through our territory instead of off in Fresno.
- look at the use of electric vehicles (vehicle to grid) - look at independent pricing structure instead of trying to mirror CPUC NBT

15. CAC Structure per Ad Hoc Board Committee Recommendation (Discussion Item) Discussion of Restructure CAC per Ad Hoc recommendation CAC has not been consulted on this change prior to this meeting. As staff is not recommending the board take a final decision, rather looking for direction, the CAC recommends the following direction.

Support maintaining regional representation with some modifications ● Original structure had the constituent group allocation. ○ CAC would like to propose constituent group and allocation for consideration
○ Don't want to lose our existing members, including the at-large members. Notably, they both regularly attend.
○ consider future expansion of CAC seats if the body keeps growing. ● Alternates: don't get rid of them, regularly move alternates into CA seats, often wouldn't make quorum without them. Do lose some from lack of engagement.
○ 1 Alternate per region, but function as at-large and can sub for any vacancy. Utilize like a pool, and rotate who is given the voting slot. ○ give stipend even if not voting.

Want the CAC to help the Board hear the concerns and the ideas from the community that the Board may not otherwise hear. We take time, have meetings, and report to constituent groups
Evaluate other types of structures for getting people onto the CAC and bringing in diverse voices with other opinions. CAC would like to bring some suggestions for consideration.

16. Memorial Comments in Honor of Al Weinrub

17. Board Member and Staff Announcements including requests to place items on future Board agendas

18. Closed Session
● Public Employee Performance Evaluation pursuant to Government Code § 54957:

Chief Executive Officer.

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19. General Report Out of Closed Session

20. Adjourn
The next Board of Directors meeting will be held on Wednesday, October 18, 2023 at 6:00 pm.

Draft Minutes
Board of Directors
Special Board Retreat
Analytics
Thursday, July 13, 2023
11am
In person:

The Montclair Room
Cal State East Bay - the Oakland Center
In the Transpacific Centre
1000 Broadway, Suite 109
Oakland, CA 94607
Or from the following locations:
• Wells Fargo Building - 2140 Shattuck Avenue, Floor 6, Berkeley, CA 94704 • Dublin City Hall - 100 Civic Plaza, Dublin, CA 94568
• Clipper Club, 5 Captain Drive, Emeryville, CA 94608
• Hayward City Hall, 777 B St, Hayward, CA 94541
• Hyatt Regency Newport Beach, 1107 Jamboree Rd. Newport Beach, CA 92660 • 1755 Harvest Landing Ln., Tracy, CA, 95376
• 10598 SE 32nd Ave, Milwaukie, OR 97222
• Balch Enterprises, Inc. 30960 Huntwood Avenue, Hayward, CA 94544 Via Zoom:
https://us02web.zoom.us/j/87023071843
Dial(for higher quality, dial a number based on your current location): US: +1 669 900 6833 or +1 346 248 7799 or +1 253 215 8782 or +1 929 205 6099 or +1 301 715 8592 or 888 475 4499 (Toll Free) or 877 853 5257 (Toll Free)
Webinar ID: 870 2307 1843
Meetings are accessible to people with disabilities. Individuals who need special assistance or a disability-related modification or accommodation to participate in this meeting, or who have a disability and wish to request an alternative format for the meeting materials, should contact the Clerk of the Board at least 2 working days before the meeting at (510) 906-0491 or [email protected].

If you have anything that you wish to be distributed to the Board of Directors, please email it to the clerk by 5:00 pm the day prior to the meeting.

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Welcome & Roll Call

Present: Directors: Kaur (Emeryville), Roche (Hayward), Jorgens (Newark), Andersen (Piedmont), Gonzalez (San Leandro), Wright (Stockton), Bedolla (Tracy), Patino (Union City), Eldred (Community Advisory Committee), Vice-Chair Balch (Pleasanton) and Chair Marquez (Alameda County)
Excused: Directors: Tiedemann (Albany), Bartlett (Berkeley) Hu (Dublin), Cox (Fremont), Barrientos (Livermore) and Kalb (Oakland)
Director Kaur served as the alternate for Director Bauters (Emeryville)

1. Pledge of Allegiance
Chair Marquez led the body in reciting the Pledge of Allegiance.

2. Public Comment
This item is reserved for persons wishing to address the Board on any EBCE-related matters that are not otherwise on this meeting agenda. Public comments on matters listed on the agenda shall be heard at the time the matter is called. As with all public comment, members of the public who wish to address the Board are customarily limited to two minutes per speaker and must complete an electronic speaker slip. The Board Chair may increase or decrease the time allotted to each speaker.

There was no public comment.

3. Analytics Update (Informational Item)
Receive update on Analytics activities.
(14:40) Chair Marquz (Alameda County) inquired about the use of tax assessor data and about PG&E billing determinants.
(22:49) Chair Marquez asked about the energy consumption related to data storage. (23:51) Member Roche inquired about the security and reliability of the data stored in the cloud, specifically concerning potential hacker attacks and the possibility of data migration to ensure uninterrupted service.
(30:40) Member Andersen asked about the sources and accuracy of weather forecasts. (33:01) Chair Marquez inquired about how weather forecasting accounts for regional variations, especially considering the temperature differences between coastal areas and valleys.
(34:20) Member Gonzalez asked about the granularity of the load forecasting, particularly whether the forecast is made on an individual meter basis or in aggregate.

Member Gonzalez further inquired about the years of meter load data staff to which staff has access. Addressing the influence of weather on forecasting, Member Gonzalez asked about the granularity of EBCE’s weather data. To conclude, Member Gonzalez emphasized the importance of leveraging historical research in load forecasting, East Bay Community Energy
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suggesting that while advancements have been made, it's essential to tap into the collective wisdom of the past.
(43:36) Vice-Chair Balch inquired about the accuracy of data used in load forecasting. (50:44) Member Gonzalez inquired about the primary revenue risk. Member Gonzalez emphasized the need to understand the PCIA risk, considering that it is tied to PG&E rates which EBCE cannot control. Member Gonzalez also requested that the board be informed about PCIA risks in detail to better understand EBCE’s exposure and be able to provide input on the level of risk that Board members are willing to accept. (1:06:05) CAC Chair Eldred inquired about the granularity of customer data, referencing an original bid with 15-minute intervals.
(1:13:11) Member Andersen inquired about potential collaborations between other Community Choice Aggregations (CCAs) and UC Berkeley's new data science college.

4. Board Member and Staff Announcements including requests to place items on future Board agendas
• Member Gonzalez asked for the Board to discuss PCIA rates as soon as the information becomes available.
• Per the electric bike program, Chair Marquez asked when Board members will be informed about the locations to rent bikes. Chair Marquez asked that this information be provided either at the next board meeting or via an email update.

5. Adjourned at 12:20pm.

Board of Directors Meeting
Wednesday, July 19, 2023
6:00 pm
In Person
The Lake Merritt Room
Cal State East Bay - the Oakland Center
In the Transpacific Centre
1000 Broadway, Suite 109
Oakland, CA 94607
Or from the following locations:
• Wells Fargo Building - 2140 Shattuck Avenue, Floor 6, Berkeley, CA 94704 • City of Dublin City Hall, 100 Civic Plaza, Dublin, CA 94568 • Fremont City Hall 3300 Capitol Ave, Fremont, CA 94538 • Margaret Troke Library 502 W Benjamin Holt Dr., Stockton, CA 95207 • 1755 Harvest Landing Lane, Tracy, CA 95376
Via Zoom:
https://ebce-org.zoom.us/j/87023071843
Dial(for higher quality, dial a number based on your current location): US: +1 669 900 6833 or +1 346 248 7799 or +1 253 215 8782 or +1 929 205 6099 or +1 301 715 8592 or 888 475 4499 (Toll Free) or 877 853 5257 (Toll Free)
Webinar ID: 870 2307 1843
Meetings are accessible to people with disabilities. Individuals who need special assistance or a disability-related modification or accommodation to participate in this meeting, or who have a disability and wish to request an alternative format for the meeting materials, should contact the Clerk of the Board at least 2 working days before the meeting at (510) 906-0491 or [email protected].

If you have anything that you wish to be distributed to the Board of Directors, please email it to the clerk by 5:00 pm the day prior to the meeting.

1. Welcome & Roll Call

Present: Directors: Tiedemann (Albany), Hu (Dublin), Bauters (Emeryville), Cox (Fremont), Roche (Hayward), Barrientos (Livermore), Kalb (Oakland), Andersen (Piedmont), Gonzalez (San Leandro), Wright (Stockton), Bedolla (Tracy), Eldred (Community Advisory Committee), Vice-Chair Balch (Pleasanton) and Chair Marquez (Alameda County)
Excused: Directors: Bartlett (Berkeley), Jorgens (Newark) and Patino (Union City) East Bay Community Energy
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Member Cox (Fremont) and Member Hu (Dublin) joined the meeting at 6:10pm, immediately after roll call.

2. Pledge of Allegiance

3. Public Comment
This item is reserved for persons wishing to address the Board on any EBCE-related matters that are not otherwise on this meeting agenda. Public comments on matters listed on the agenda shall be heard at the time the matter is called. As with all public comment, members of the public who wish to address the Board are customarily limited to two minutes per speaker and must complete an electronic speaker slip. The Board Chair may increase or decrease the time allotted to each speaker. (6:07) Jon Hungerford, a Stockton resident, inquired about EBCE's Net Energy Metering (NEM) program. He noted that Stockton will soon be using EBCE's services, but currently, Stockton residents are being registered with NEM3 type programs under PG&E. He asked if EBCE plans to maintain offering retail credits for monthly energy overproduction once they switch from PG&E.
(7:46) Tom Kelly mentioned that it was challenging to hear speakers in the Oakland Center. He noted that speakers in remote locations were more audible and hoped the issue could be resolved.
(9:49) Audrey Ichinose asked if public comment was being taken on consent agenda items.
(10:15) Jessica Tovar, speaking on behalf of the East Bay Clean Power Alliance, expressed concerns about the allocation and clarity surrounding the $15 million Healthy Communities fund initially associated with UCSF Benioff. She noted that the board approved $5 million from this fund last month, but there are still uncertainties, including claims of secured money from an unnamed foundation, a lack of information about the study's purpose, and how the $5 million will be used. She also mentioned that no partner for the study had been identified. Jessica Tovar emphasized that this $15 million has been a contentious legal issue in the past, and that she had previously requested a public workshop or detailed discussion on this matter. Jessica Tovar reminded the board of their responsibility to ensure public funds are used appropriately and transparently for the community's benefit.

The clerk read a public comment letter from Jessica Tovar on behalf of Local Clean Energy Alliance. The following is a summary of that letter:
(12:26) Jessica Tovar of the Local Clean Energy Alliance urged removing Consent Agenda Item #9, “Authorization to Execute Vehicle Lease and Consulting Agreement”, from the consent calendar for public debate. Jessica Tovar argued that funds for the $85,000 electric vehicle research and development pilot would be better spent offering free short-term EV leases to low-income communities. She stated that feedback from low-income residents would be more valuable for the $6 million EV adoption program than EBCE staff experiences.

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CONSENT AGENDA

4. Approval of Minutes from June 21, 2023

5. Contracts Entered into (Informational Item)

6. Amendment to Non-standard Rate Policy
Revise policy to expand eligibility to beneficial electrification projects on municipal buildings

7. Approval Request for Agreement Amendment with Thrive Mind Collaborative Approval Request for Agreement Amendment with Thrive Mind Collaborative to provide coaching and consulting services to EBCE Staff.

8. Authorization to pay for postage
Authorize the CEO to approve the funding of EBCE’s accounts with the USPS in the amount of up to $400,000.

9. Authorization to Execute Vehicle Lease and Consulting Agreement Authorize the CEO to execute a lease and Agreement for EBCE’s Drive and Charge Research & Development Initiative

10. Treasurer’s Report
Report on EBCE’s cash position as of June 30, 2023
(15:21) Chair Marquez recognized Jessica Tovar’s request to pull Consent Item #9, “Authorization to Execute Vehicle Lease and Consulting Agreement” from the Consent Agenda.
(15:32) Member Gonzalez requested to pull Consent Item #6, “Amendment to Non-standard Rate Policy” from the Consent Agenda. (16:18) Chair Marquez recognized Tom Kelly’s request to pull Consent Item #10, “Treasurer’s Report” from the Consent Agenda.
(17:08) Member Gonzalez moved to approve Consent Agenda Items 4, 5, 7 and 8.

Member Bauters seconded the motion which passed unanimously by all members present:

Yes: 13
No: 0
Abstain:0
Excused: 3
(19:06) Tom Kelly, speaking to Consent Item #6, “Amendment to Non-standard Rate Policy”:

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Tom Kelly suggested that if the Board is going to provide rate discounts for commercial customers to prevent them from switching to direct access, those customers should be offered rates for the Renewable 100 option instead of Bright Choice. Tom Kelly emphasized commercial entities consume a considerable amount of electricity, and offering them discounts on the less clean power option (Bright Choice) is contrary to the EBCE’s mission. Tom Kelly proposed that any amendment should advocate for a discount on the cleaner Renewable 100 power option.
(20:30) Jessica Tovar, speaking to Consent Item #5, “Contracts Entered into”:

Noting contract C-2023-054 “Port of Oakland, West Oakland Environmental Indicators Project, Earthjustice, etc.”, Jessica Tovar requested more information about the collaborative working group with the Port of Oakland and others, and to see the contract.
(21:57) Member Gonzalez, speaking to Consent Item #6, “Amendment to Non-standard Rate Policy”, asked for staff to provide its reasoning for its proposed amendment to the non-standard pricing rate and billing agreement policy. (30:05) Member Roche, speaking to Consent Item #6, “Amendment to Non-standard Rate Policy”, requested for staff to respond to Tom Kelly’s public comment recommendation that discounts should be provided for Renewable 100 rather than Bright Choice.
(31:14) Member Gonzalez moved to approve Consent Item #6. Vice-Chair Balch seconded the motion which passed unanimously by all members present:

Yes: 13
No: 0
Abstain: 0
Excused: 3
(32:56) Audrey Ichinose, speaking to Consent Item #9, “Authorization to Execute Vehicle Lease and Consulting Agreement”
Audrey Ichinose expressed concerns about the Leasing and Consulting Services for EBCE’s Drive and Charge initiative. She stated that the initiative's design demonstrates challenges for EBCE in how it engages with its member jurisdictions, especially with moderate and low-income communities and renters. Audrey Ichinose criticized EBCE’s approach, suggesting that staff intends to design and test the program mainly using its own employees, with minimal involvement from the target communities. She referenced the CAC meeting where member Jim Lutz highlighted that sustainability managers of member jurisdictions desired early and coordinated engagement with EBCE on program design. Audrey emphasized the importance of establishing more effective collaboration methods, especially as EBCE plans to expand beyond Alameda County. (35:05) Barbara Stebbins, speaking to Consent Item #9, “Authorization to Execute Vehicle Lease and Consulting Agreement”
Barbara Stebbins expressed confusion about EBCE staff driving EVs for a two-week duration and then providing feedback on their experiences. She questioned how this method would increase EV adoption, particularly in low-income areas and locations East Bay Community Energy
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with affordable multi-family housing units where EBCE has funded charging infrastructure. Barbara Stebbins emphasized the need to directly engage residents from these communities, offering them firsthand experiences with EVs to gather relevant feedback. She also highlighted that cost is a significant deterrent for many people, including herself, from transitioning to EVs, even if they recognize the environmental benefits.
(37:10) CAC Chair Eldred, speaking to Consent Item #9, “Authorization to Execute Vehicle Lease and Consulting Agreement”, recommended that staff adopt with a program design with increased direct engagement with targeted populations and demographics, and to partner with organizations in the electric vehicle space. (38:52) Member Roche, speaking to Consent Item #9, “Authorization to Execute Vehicle Lease and Consulting Agreement” asked for staff to explain why staff and their passengers were chosen to complete surveys about driving/riding experience rather than community residents.
(39:39) Chair Marquez, speaking to Consent Item #9, “Authorization to Execute Vehicle Lease and Consulting Agreement” asked if the survey could require staff to drive in census tracks of differing income levels as a means of gathering information about the experience of EV driving across multiple communities. (47:10) Member Bauters, speaking to Consent Item #9, “Authorization to Execute Vehicle Lease and Consulting Agreement” expressed concern that staff might not notice design decisions that could impact lower-income residents. Member Bauters cited the necessity of credit card access to operate an electric vehicle for example. (55:49) Member Gonzalez, speaking to Consent Item #9, “Authorization to Execute Vehicle Lease and Consulting Agreement” asked for staff to provide a clear statement of the problem that it would like to address (for example, is staff trying to get data on how easy it is to charge the car or to drive it?).
(57:06) Member Gonzalez motioned to approve Consent Item #9. Member Roche seconded the motion, which was approved unanimously by all members present:

Yes: 13
No: 0
Abstain: 0
Excused: 3
(1:00:18) Tom Kelly, speaking to Consent Item #10, “Treasurer’s Report”:

Tom Kelly expressed difficulty in comprehending the budget documents and financial reports, particularly in discerning if there is a carryover of net position from one budget year to the next. Tom Kelly also raised concerns about the organization's financial and ethical choices, highlighting that over half a million dollars are invested with Wells Fargo, a bank known for investing in fossil fuels and facing multiple scandals. By referencing the City of Berkeley's decision to withdraw accounts from Wells Fargo, Tom Kelly encouraged the Board to consider partnering with more a community-oriented financial institution such as the Community Bank of the Bay in Oakland East Bay Community Energy
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(1:02:52) Member Bauters moved to approve Consent Item #10 and Member Gonzalez seconded. The motion was passed unanimously by all members present:

Yes: 13
No: 0
Abstain: 0
Excused: 3

REGULAR AGENDA

11. CEO Report
(1:04:37) CEO Chaset’s CEO Report covered Board meetings, branding progress, potential expansion to Lathrop, and new staff members:
• The July Executive Committee meeting was canceled. The next one is September

6. • The Finance, Administration and Procurement Subcommittee met on July 12 to discuss upcoming agenda items, overview the 2023 resource RFO, and review the third energy prepay transaction.
• A Special Board Retreat on Analytics was held on July 13. • Brand identity work is underway following approval of the name change to Ava Community Energy. Visual assets will come to the Board as an informational item in September.
• The City of Lathrop voted to seek EBCE membership and service area expansion.

Next steps involve Lathrop finalizing its ordinance to join, EBCE analyzing its ability to serve Lathrop's load, Board approval, CPUC implementation plan update, and Lathrop enrollment in early 2025 with Stockton.
• Additional next steps include finalizing the Ava Community Energy visual identity and evaluating Lathrop's membership request.
• Christa Davis joined EBCE as Account Services Manager. Pulak Dugar joined as a Data and Analytics Intern.
(1:09:58) Tom Kelly inquired about the implications of the City of Lathrop joining EBCE in the upcoming year. Specifically, he questioned whether, upon Lathrop's inclusion and the subsequent signing of a new JPA agreement in December 2023, the document would be amended to exclude assertions that EBCE outperforms PG&E in reducing greenhouse gas emissions. Tom Kelly sought clarification about whether the JPA would need to be revised and re-endorsed by all member cities if it contained misleading statements about greenhouse gas reductions.
(1:11:13) Chair Marquez asked for staff to provide a timeline for Stockton will “go live”. Chair Marquez also requested that the Finance, Administration and Procurement Subcommittee address Tom Kelly’s public comment remarks at 1:09:58. Finally, Chair Marquez asked about the information that staff provides to new communities for outreach purposes.

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12. CAC Report
(1:13:38) CAC Chair Eldred’s report focused on the delayed emissions presentation and CAC Member Lutz’s City Staff Perspectives findings:

1. Delayed Emissions Presentation:
• The CAC held a presentation and discussion in April regarding EBCE's emissions intensity compared to other CCAs. EBCE's emissions were significantly higher than others with more renewable and carbon-free energy.
• CAC members expressed desire for a concise emissions summary to aid transparency. The updated emissions presentation has been postponed several times and the CAC looks forward to the new version with 2022 data.

2. City Staff Perspectives Report Summary:
• CAC Member Jim Lutz interviewed city sustainability staff to understand coordination on climate action plans.
• Key findings included appreciation for EBCE's expertise but desire for more collaborative program design, increased flexibility, longer-term planning visibility, and independent feedback collection.
• Recommendations were to increase city collaboration in program development, allow broader participation, create a strategic roadmap with city input, and gather regular city staff feedback. • The report focused on improving coordination between EBCE local development programming and member city/county climate action plans. (1:20:13) Vice-Chair Balch asked if there is a technical advisory group that can address and provide feedback for CAC Member Lutz’s City Staff Perspectives report. (1:22:32) Member Gonzalez (with additional input from Vice-Chair Balch and Chair Marquez) stressed that staff, Board and other communities should engage in a strategic planning process to develop clear objectives around high-priority or repeatedly addressed topics such as clean energy goals, service territory expansion and pricing rates.
(1:23:30) Member Roche requested a timeline for when the Board will hear the updated Emissions presentation.
(1:26:38) Chair Marquez announced that, going forward, closed sessions be held at the ending rather than the beginning of meetings.

13. Energy Prepay #3 Approval (Action Item)
Authorization to move forward in executing a third energy prepayment transaction (1:41:14) Member Gonzalez asked for staff to provide a concise explanation for the public about the advantage that EBCE has due to its ability to issue tax-free bonds. He mentioned that the primary advantage appears to be tax-free interest rates, contrasting EBCE with other entities like banks. He asked for a brief overview of why East Bay Community Energy
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this tax-free bond issuance creates an arbitrage opportunity and how that benefits EBCE.
(1:44:15) Member Gonzalez moved approval of Item 13 and Member Bauters seconded. The motion passed unanimously by all members present:

Yes:13
No:0
Abstain: 0
Excused: 3
CEO Employment Contract (Action Item)
The clerk read a public comment letter from Jane Kelly titled “Community Concerns Regarding the Management of EBCE and Requested Action”, dated July 18, 2023. The following is a summary of that letter:
(1:50:42) Jane Kelly urged the Board to deny CEO Chaset's proposed salary increase and bonus due to concerns over mismanagement. Jane Kelly argued that CEO Chaset has not prioritized EBCE's climate goals and requested that the Board address these issues by either directing Chaset to urgently combat climate change or finding new leadership aligned with the community's goals.
(1:53:20) Vice-Chair Balch mentioned that he and CEO Chaset were part of the Compensation Ad Hoc. They discussed CEO Chaset's priorities for the organization, aiming to align them with EBCE’s long-term goals. While Mr. Chaset expressed a preference for a lengthier contract; the Board opted for a reevaluation approach to ensure alignment with EBCE's strategy. Balch acknowledged CEO Chaset's cooperation in finalizing the contract and confirmed Pleasanton's support for it. (1:55:09) Member Gonzalez moved approval of Item #13 and Member Tiedemann seconded. The motion passed unanimously by all members present:

Yes:13
No:0
Abstain: 0
Excused: 3

14. Board Member and Staff Announcements including requests to place items on future Board agendas
• (1:56:12) Chair Marquez requested to prioritize the Emissions presentation on the September 2023 agenda.
• CAC Chair Eldred requested to schedule conversations around the following topics:
o Allocation for community programming - Healthy Communities; o EBCE/Ava’s intentions around service territory expansion; o Methodology of the on-bill credit portion of the 2022/23 surplus waterfall allocation.
• Vice-Chair Balch requested an update about the new space including a review of the lease.

East Bay Community Energy
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• Vice-Chair Balch requested a timeline for scheduling in person Board meeting. • Chair Marquez requested that future board agendas include a calendar of Board Member requests.
• Member Cox requested an update on how EBCE is utilizing artificial intelligence.

15. Adjourned at 8:00pm
The next Board of Directors meeting will be held on Wednesday, September 20, 2023 at 6:00 pm.

Consent Item 5
Consent Item 5
TO: East Bay Community Energy Board of Directors
FROM: Nick Chaset, Chief Executive Officer
SUBJECT: Contracts Entered Into
DATE: September 20, 2023
________________________________________________________________________

RECOMMENDATION
Accept the CEO’s report on contracts that EBCE has entered, as required by the Administrative Procurement Policy from July 12, 2023, to September 14, 2023; C-2023-064 AIQUEOUS, LLC Amendment 3 to the Consulting and Online Services Agreement extends the term to June 30, 2024, adds $100,000 to the not to exceed for Fiscal Year 2023/2024 with total compensation not to exceed $360,000, with updates to the Scope of Work and Schedule.

C-2023-065 Wilson Sonsini Goodrich Rosati Fourth Amendment to CSA extends the term through June 30, 2024, adds $436,029 will be allocated for the term July 1, 2022, to June 30, 2023, and $600,000 will be allocated for the term from July 1, 2023, to June 30, 2024, total compensation is not to exceed $1,036,029.00.

C-2023-066 FinalOption (dba Pacific Printing) Fourth Amendment to CSA adding $100,000 to the compensation and extending the term to June 30, 2023, total compensation not to exceed $1,220,000.

C-2023-067 Pivotal Talent Search, LLC Second Amendment to CSA Extends the term through June 30, 2024, adds $3,582.10 for services in June 2022, and $100,000 for Fiscal Year 2023- 2024, maximum total compensation for this agreement is $203,582.10.

C-2023-068 Oakland Roots SC, LLC Sponsorship Agreement Adds additional $100,000 in compensation and extends the term to June 30, 2024, total compensation is not to exceed $320,000.

C-2023-069 PC Professional, Inc. Third Amendment to CSA Adds additional $100,000 in compensation and extends the term to June 30, 2024, total compensation is not to exceed $320,000.

Consent Item 5
C-2023-070 Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES) Memorandum of Commitment Collaboration between the Governor's Office (Go-Biz), UCOP and other organizations to build a collaborative ecosystem of technology, policy, community, and finance partners in CA to develop a proposal for a US DOE co-funded Regional Clean Hydrogen Hub (no cost).

C-2023-071 Orrick, Herrington & Sutcliffe, LLP Consulting Services Agreement Providing bond and tax counsel services related to prepay transaction, August 2, 2023, through the third anniversary of the effective date of the Agreement, and the date of issuance of the bonds, maximum compensation under this Agreement is $250,000.

C-2023-072 Hall Energy Law PC Third Amendment to CSA extends the termination date through June 30, 2024, and adds additional $250,000 for fiscal year 2023/2024, and $23,900.500 for fiscal 2022/2023, maximum compensation not-to-exceed $877,390.50.

C-2023-073 Sixth Dimension PMCM Inc. Second Amendment to CSA extends the termination date through June 30, 2024.

C-2023-074 Celery Design Collaborative Fifth Amendment to CSA extends the termination date through June 30, 2024, and adds additional $400,000 for fiscal year 2023/2024, maximum compensation not-to-exceed $1,745,000.

C-2023-075 PFM Financial Advisors LLC together with its affiliate PFM Swap Advisors LLC Financial Services Agreement for Financial Advisor services for a total amount of $150,000, contingent on successful prepay execution, term of June 1, 2023, to December 31, 2023.

C-2023-076 The Understory, LLC Second Amendment to CSA extends the term through July 1, 2024.

C-2023-077 Replica, Inc. Order Form - Platform Subscription Agreement (12) Twelve Month Subscription Term from August 15, 2023, through August 14, 2024, that renews annually.

C-2023-078 Law Office of David Peffer First Amendment to CSA Extends the termination date through June 30, 2024, and adds an additional $12,000 for fiscal year 2023/2024, maximum compensation not to exceed $32,000. Effective January 1, 2024, David Peffer's hourly rate will increase to $330/hr.

C-2023-079 City of Berkeley Charging Station Master Site License Agreement Fifteen-year agreement granting EBCE the rights to construct, install and maintain electrical vehicle charging stations and associated infrastructure for public use.

C-2023-080 BCAL LMP Harrison Property LLC & CSHV 1999 Harrison, LLC & Big Fish Games, Inc.

SUBLEASE (1999 Harrison Street, 23rd Floor, Oakland, CA) Sublandlord (Big Fish Games), Subtenant (EBCE) and Master Landlord (BCAL LMP Harrison Property LLC, and successor in interest (CSHV 1999 Harrison, LLC) sublease agreement expires on March 31, 2025.

C-2023-081 Nixon Peabody LLP Second Amendment to Legal Services Agreement Extends the termination date through June 30, 2024, and adds an additional $21,113.76 for Fiscal Year 2022-2023, and $200,000 for Fiscal Year 2023-2024, maximum compensation not-to-exceed $316,113.76.

Consent Item 5
C-2023-082 Afaf Translations LLC Third Amendment to CSA Extends the termination date through June 30, 2024, and adds $20,000 for Fiscal Year 2023-2024, maximum compensation not-to-exceed $70,000.

C-2023-083 Bentham Paulos Third Amendment to CSA Extends the termination date through June 30, 2024, and adds $45,000 for Fiscal Year 2023-2024, maximum compensation not-to-exceed $180,000.

C-2023-084 BCAL LMP HARRISON PROPERTY LLC & BIG FISH GAMES, INC. CONSENT TO SUBLEASE AGREEMENT - Landlord and Tenant consent to sublease Suite 2300, (23rd) floor of the building located at 1999 Harrison Street, Oakland, CA to EBCE.

C-2023-085 BCAL LMP HARRISON PROPERTY LLC AMENDMENT TO LICENSE AGREEMENT Allows EBCE to terminate the License Agreement at 1999 Harrison Suite 810 with (15) fifteen days prior written notice.

C-2023-086 BCAL LMP HARRISON PROPERTY LLC LAKE MERRITT PLAZA OFFICE LEASE Seven (7) year and Seven (7) month lease; from April 1, 2025, through October 31, 2023, for 1999 Harrison Suite 2300.

C-2023-087 Salesforce, Inc. Order Form Q-07457967 (12) Twelve Month Subscription Term from August 15, 2023, through August 14, 2024 that automatically renews for additional one year terms. Total amount not to exceed $91,830.38.

C-2023-088 California State University, East Bay Facility Use Agreement Two (2) events; the first room rental is on September 5, 2023 ($425), and the second room rental is on September 6, 2023 ($325). The total rental is $750.

C-2023-089 CLEAResult Consulting Services Agreement (Portland) for Ride Electric Bike Adoption Program through January 15, 2027, with compensation not to exceed $10,000,000.

C-2023-090 MissionCTRL Second Amendment to CSA extends the term through June 30, 2024, and adds $98,000 to the compensation for thought leadership services, for a total amount not to exceed $296,000.

C-2023-091 Bay Area News Group Advertising Agreement Advertising space in publications and digital ads for Fremont Argus, Daily Review, and Oakland Tribune for the term on July 1, 2023, to June 30, 2024.

C-2023-092 Chapman and Cutler Consulting Services Agreement legal advice related to prepay transaction, total cost not to exceed $175,000 for the term through June 30, 2024.

C-2023-093 Alameda County Transportation Commission Project Funding Agreement for the Ride Electric Program $4,000,000 to be provided to EBCE's eBike Incentive program in Alameda County, with EBCE providing $6,000,000.

C-2023-094 Los Angeles Cleantech Incubator Transportation Electrification Partnership Letter EBCE will provide $25,000 is sponsorship and will gain access to advisory group meeting and Consent Item 5
activities, working groups, and others to advance policies and funding related to Transportation Electrification.

C-2023-095 Sound of Hope Radio Network 4th Amendment to CSA adds $15,000 for advertising and translation services and extends the term through June 30, 2024, total compensation is not to exceed $75,000.

C-2023-096 Thrive Mind Collaborative 1st Amendment to MSA adds $130,000 in compensation for Leadership coaching services.

C-2023-097 The Law Office of Joseph F. Wiedman 3rd Amendment to CSA adds $40,000 and extends the term through June 30, 2024, total compensation is not to exceed $104,000.

C-2023-098 Clean Energy Regulatory Research 4th Amendment to CSA adds additional compensation in the amount of $49,500 for a total amount not to exceed $176,500, updates to the scope of work, extends the term through June 30, 2024.

C-2023-099 InsideSource Credit Terms and Terms and Conditions of Sale purchase, delivery, and installation of desk dividers and removal of excess desks in new office location at 1999 Harrison St. Suite 2300, total cost not to exceed $71,511.05.

C-2023-100 InsideSource Order Form purchase, delivery, and installation of desk dividers and removal of excess desks in new office location at 1999 Harrison St. Suite 2300, total cost not to exceed $71,511.05.

C-2023-101 Davis Wright Tremaine Fourth Amendment to CSA extends the term through June 30, 2024, expands the scope of work, updates the hourly rate of compensation, and adds $340,000 in compensation (across the Public Policy, Marketing, Power Resources, and Local Development Departments) with total compensation not to exceed $742, 804.

C-2023-102 Landscape Studio Addendum 2 to CSA adds and additional $17,500 in compensation for new logo exploration.

C-2023-103 Richards Watson and Gershon Third Amendment to CSA adds $400,000 in additional compensation, with total compensation not to exceed $1,575,000, updates the hourly rates of compensation, and extend the term through June 30, 2024.

C-2023-104 Docusign Order Form Adds Premier Support and 2000 additional digital envelopes to existing plan through April 2024 at a cost of $2,000.

C-2023-105 Comcast Business Move/Upgrade Service Form Moving services from 1999 Harrison Suite 810 to Suite 2300 and upgrading services.

C-2023-106 Comcast Business Service Order Agreement Monthly cost will be $189.99 per month.

C-2023-107 Valley Relocation and Storage Move Agreement Moving services from 1999 Harrison Suite 810 to Suite 2300, cost was quoted at $7,180.

Consent Item 6
Consent Item 6

TO: East Bay Community Energy Board of Directors

FROM: Howard Chang, Chief Operating Officer & Treasurer

SUBJECT: Energy Prepay Transaction #3 Summary of Results (Informational)

DATE: September 20, 2023
__________________________________________________________________

Recommendation
Receive an informational item to summarize the results of EBCE’s third energy prepay transaction.

Background and Discussion
On July 19, 2023, EBCE approved moving forward with its third energy prepay transaction.

Working with Morgan Stanley as the bond underwriter, we successfully priced the bonds on August 9, 2023 and closed the prepay transaction on August 16, 2023.

Details of the transaction are below.

Total Bond Proceeds: $1,037,266,229.50
Start Date: Jan 1, 2024
Tenor of the initial bonds: 7 years
Cost of Issuance: 0.59%
Average Annual Savings for Initial Term: $6,931,707
Given the strong execution and opportune market timing, it is very notable that this has resulted in the highest savings discount on a MWh basis of $12.67/MWh of any Morgan Stanley Prepay to date. This transaction is EBCE’s third prepay transaction. Together with the savings from EBCE’s previous two prepay transactions, EBCE has secured annual savings of approximately $14MM, which represents roughly a 2% discount on energy costs to all EBCE customers. All three prepay transactions are 30 energy contracts. The savings from the second prepay transaction are locked in until 2031, which is when the bonds will need to be repriced, and the future discount will be based on market conditions at that time. The savings from the first transaction are locked in until 2032 because it closed on 10-year bonds and the savings from the second transaction are locked in until 2029 because it closed on 6-year bonds.

Consent Item 6
Through the energy prepay transaction this discount is being applied to a variety of long and short-term renewable energy and large hydro contracts that EBCE is assigning into the structure. Based on the number of eligible source-specified PPAs under contract, EBCE will seek to continue to execute additional prepay transactions in the coming years to maximize the available savings.

EBCE’s board approved and adopted a resolution subject to the following parameters:
(a) the Bonds will not be obligations of EBCE, but will be limited obligations of the Issuer payable solely from the revenues and other amounts pledged therefor under the Indenture, including amounts payable by EBCE under the Power Supply Contract; (b) the aggregate principal amount of the Bonds shall not exceed $1,000,000,000; (c) the annual energy savings to EBCE under the Power Supply Contract shall be at least $4.50 per MWh
The executed transaction complies with all aspects of the resolution with a principal amount of $997,895,000 and savings of over $12.67/MWh. Note that the principal amount of $997,895,000 is less than the proceeds of $1,037,266,229.50. This difference exists because the standard market coupon on bonds is 5%, but currently the market yield is in the 4% range.

Therefore, the bonds are priced with a small premium, which increases the proceeds actually invested by bondholders at day 1.

Previous Background Information:

An energy prepayment is a long-term financial transaction available to municipal utilities and tax-exempt entities such as CCAs that enables a meaningful power procurement cost savings opportunity. This prepay structure has historically been utilized for natural gas procurement and is now being applied towards renewable energy. To date, EBCE, Silicon Valley Clean Energy (SVCE), MCE, CPA, and Pioneer Energy, have executed prepay transactions and currently a number of other CCAs are also in the process of initiating a similar structure.

Financial Impact
There is no financial impact related to receiving this informational item.

Attachments
None
Consent Item 7
Consent Item 7
TO: East Bay Community Energy Board of Directors
FROM: Anish Patel, Director, Infrastructure Delivery
SUBJECT: Approve Resolution Authorizing EBCE CEO to Negotiate and Execute an Amendment to the Agreement with ARUP to Implement
Transportation Electrification Infrastructure Development consulting support
DATE: September 20, 2023
__________________________________________________________________ Recommendation
Approve a Resolution authorizing EBCE CEO to negotiate and execute an Amendment to the Consulting Services Agreement (“Agreement”) with ARUP North America, LTD (“ARUP”) dated May 19, 2021, to provide Engineering and Project Development Services that will facilitate transportation electrification infrastructure development with respect to the battery deployment into direct current fast charging (“DCFC”) stations, to expand the scope, and to increase the compensation by $140,000, for a total amount not to exceed $720,000 through December 31, 2024.

Background and Discussion
EBCE has conducted a detailed analysis to understand home charging access in our service area and identified critical disparities that will hinder widespread Electric Vehicle (“EV”) adoption and, therefore, the ability to achieve California’s ZEV goals.

EBCE is investing in an Equitable EV Fast Charging Network to ensure all residents can join and benefit from the transition to EVs. EBCE retained an external consultant, ARUP, to determine various options to design the direct current fast charging infrastructure by proposing the DCFC product with an integration of battery storage.

By 2030 EBCE intends to deploy a public network of DCFC hubs, each with a minimum of 10 dual-port DCFCs, to supplement a diverse array of community-specific TE programs. Our goal is to have upwards of 40 to 50 DCFC hubs operational to meet the Consent Item 7
recharging needs of light-duty passenger EVs, as well as medium- and heavy-duty goods movement vehicles.

DCFC Infrastructure Development Support Professional Services EBCE has been working on pre-development activity regarding the DCFC infrastructure development for several sites in Alameda County. One of the critical tasks for us is to work on new electrical service planning with PG&E. We received the map provided by PG&E to show available electrical distribution capacity on the grid (called ICA maps) which we use as one of the site selection criteria to determine the available capacity around our sites. Per our reviews, EBCE determined that we can obtain up to 2MW of low voltage (480V, 3Ph) electrical service from PG&E to build DCFC infrastructure for several sites. However, we were then informed by PG&E that they don't have electrical capacity available in their network to provide electrical service for some of our sites. For one site, PG&E can provide partial electrical service 2 years from now (for an example: 500KW available in Q4 of 2025, full capacity available in Q1 of 2028).

On the second site, there is an existing 500kW service at an existing building that EBCE may be able to access for EVSE supply.

Our goal is to install ten (10) dual head, 150KW each DCFC charger with a total of 20 EV stalls including ADA stalls. We seek professional consultation from ARUP to get various design options, associated cost, road map, schedule, challenges, risks associated with the sites where we have limited to no capacity available from PG&E.

Our goal is to explore options to deploy a battery storage infrastructure to mitigate this issue.

In turn, staff is seeking authorization for the CEO to negotiate and execute an Amendment to the ARUP Agreement to expand the Scope of Work to include additional DCFC infrastructure development professional services and increase the compensation by $140,000.

Fiscal Impact
This Amendment will be funded with $140,000 from the previously approved Local Development Budget.

Attachments
A) Resolution of the Board of Directors of the East Bay Community Energy Authority Authorizing the CEO to Amend the Consulting Services Agreement with ARUP North America, LTD.

Attachment Consent Item 7
RESOLUTION NO. R-2023-xx

A RESOLUTION OF THE BOARD OF DIRECTORS

OF THE EAST BAY COMMUNITY ENERGY AUTHORITY AUTHORIZING THE CEO TO AMEND THE CONSULTING SERVICES AGREEMENT WITH ARUP NORTH AMERICA, LTD.

WHEREAS The East Bay Community Energy Authority (“EBCE”) was formed as a community choice aggregation agency (“CCA”) on December 1, 2016, Under the Joint Exercise of Power Act, California Government Code sections 6500 et seq., among the County of Alameda, and the Cities of Albany, Berkeley, Dublin, Emeryville, Fremont, Hayward, Livermore, Piedmont, Oakland, San Leandro, and Union City to study, promote, develop, conduct, operate, and manage energy-related climate change programs in all of the member jurisdictions. The cities of Newark and Pleasanton, located in Alameda County, along with the City of Tracy, located in San Joaquin County, were added as members of EBCE and parties to the JPA in March of 2020. The city of Stockton, located in San Joaquin County was added as a member of EBCE and party to the JPA in September of 2022.

WHEREAS On July 18, 2018, the Board approved the Local Development Business Plan (“LDBP”) and budget. The LDBP identifies a series of local development early actions, outlines a series of policy principles, and defines a set of metrics to measure the impact on Alameda County, and
WHEREAS EBCE issued a competitive Request for Proposal solicitation in April 2021 to select vendors to provide engineering and project development services that will support solar, battery energy storage system and DCFC deployment, and WHEREAS EBCE executed an agreement with ARUP North America, Ltd. (“ARUP”) dated May 19, 2021 (“Agreement”) to complete a solar and battery energy storage feasibility assessment on critical municipal facilities designated to serve the community in time of emergency, and
WHEREAS On March 16, 2023 EBCE executed a certain First Amendment to the Agreement with ARUP for the purposes of expanding the Agreement’s Scope of Work and adding additional compensation for a total compensation amount not to exceed five-hundred eighty thousand dollars ($580,000), and
WHEREAS ARUP is a firm with extensive experience supporting applications for Transportation electrification infrastructure design and EBCE wishes to utilize these services in addition to the solar and storage project development services already underway.

NOW, THEREFORE, THE BOARD OF DIRECTORS OF THE EAST BAY COMMUNITY ENERGY AUTHORITY DOES HEREBY RESOLVE AS FOLLOWS:

Section 1. The CEO is hereby authorized to negotiate and execute an Amendment to the Agreement to expand the Scope of Work to provide transportation Attachment Consent Item 7
electrification infrastructure development consultation that will facilitate deployment of Direct Current Fast Charging (“DCFC”) and battery energy storage systems at public parking spaces, and to increase the total compensation by $140,000; with total compensation not to exceed $720,000. The CEO is further authorized to execute any additional clarifying or clerical changes to the Agreement, which must be approved by General Counsel.

ADOPTED AND APPROVED this 20th day of September 2023.

Elisa Márquez, Chair
ATTEST:

Adrian Bankhead, Clerk of the Board
Consent Item 8
Consent Item 8
TO: East Bay Community Energy Board of Directors
FROM: Marie Fontenot, Vice President of Power Resources SUBJECT: Ratifying Resolution No. R-2023-18, Clarifying and Affirming that such Board authorization includes the CEO’s authority to negotiate and execute an agreement with MRP Pacifica Marketing, LLC regarding the 16 MW/MWh battery storage project in Kings County (Action) DATE: September 20, 2023
__________________________________________________________________ Recommendation
Adopt one Resolution ratifying Resolution No. R-2023-18, clarifying and affirming that such Board authorization includes the CEO’s authority to negotiate and execute an agreement with MRP Pacifica Marketing, LLC regarding the 16 MW/MWh battery storage project in Kings County and authorizing CEO take necessary action to implement such project. The project components and operational date are detailed below:
a. Malaga: This encompasses a 15-year, financial hedge and RA from a co-located 96 MW natural gas peaker, a 96MW/96MWh battery storage project in Fresno County, CA, and a 16MW/64MWh battery storage project in Kings County. The expected online date for the battery projects is April 1, 2024.

The project is developed by Middle River Power, LLC.

Background and Discussion
The 2022 Long-Term Resource Request for Offers (RFO) is EBCE’s second long-term contract solicitation. The RFO was launched in February 2022. The RFO sought several hundred megawatts (MW) of contracts with renewable energy and battery storage projects with a preference for projects located in California, and more preferentially, those located in Alameda County. EBCE’s objective was to drive investments in new renewable and energy storage projects in Alameda County and California, while Consent Item 8
securing affordable resources to manage future power price risk. EBCE received a very healthy response to its RFO both in volume and quality of projects and proposals.

The Malaga project is a financial hedge and RA agreement. It will be comprised of a co-located 96MW natural gas peaking facility and a 96MW/96MWh battery storage project in Fresno County and a 16MW/64MWh battery storage facility in Kings County.

The natural gas peaking facility is already built and operational; the battery is new and not yet developed. The contract is for 15 years with an expected commercial operation date of April 1, 2024. Middle River Power is an experienced developer and project owner having numerous operating natural gas facilities in California. Middle River Power has executed a similar agreement with another CCA. The contracting entity is MRP Pacifica Marketing, LLC.

Attachments
A. Resolution Ratifying Resolution No. R-2023-18, Clarifying and Affirming that such Board authorization includes the CEO’s authority to negotiate and execute an agreement with MRP Pacifica Marketing, LLC and authorizing CEO take necessary action to implement the 16MW/64MWh battery storage project with MRP Pacifica Marketing, LLC in Kings County.

B. Resolution No. R-2023-18.
1 https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M319/K825/319825388.PDF 2 https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M389/K603/389603637.PDF Attachment Consent Item 8A
RESOLUTION NO. R-2023-XX

A RESOLUTION OF THE BOARD OF DIRECTORS

OF THE EAST BAY COMMUNITY ENERGY AUTHORITY CLARIFYING BOARD AUTHORIZATION IN RESOLUTION NO. R-2023-18
WHEREAS The East Bay Community Energy Authority (“EBCE”) was formed as a community choice aggregation agency (“CCA”) on December 1, 2016, Under the Joint Exercise of Power Act, California Government Code sections 6500 et seq., among the County of Alameda, and the Cities of Albany, Berkeley, Dublin, Emeryville, Fremont, Hayward, Livermore, Piedmont, Oakland, San Leandro, and Union City to study, promote, develop, conduct, operate, and manage energy-related climate change programs in all of the member jurisdictions. The cities of Newark and Pleasanton, located in Alameda County, along with the City of Tracy, located in San Joaquin County, were added as members of EBCE and parties to the JPA in March of 2020. The city of Stockton, located in San Joaquin County was added as a member of EBCE and party to the JPA in September of 2022.

WHEREAS EBCE issued the 2020 Long-Term Resources request for offers (RFO) in October 2020;
WHEREAS EBCE re-evaluated the previously offered project while negotiating contracts from the 2022 RFO and saw new value in the unique commercial structure; WHEREAS MRP Pacifica Marketing, LLC, proposed a Financial Hedge and RA Agreement for a co-located 96MW natural gas peaking facility and a 96MW/96MWh battery storage project in Fresno County and a 16MW/64MWh battery storage project in Kings County, developed by Middle River Power;
WHEREAS the project is expected to be operational by April 1, 2024 and will provide a financial hedge and Resource Adequacy (RA) for the term of fifteen years; WHEREAS on March 15, 2023, the EBCE Board of Directors adopted Resolution No. R-2023-18 authorizing the CEO to negotiate and execute a fifteen-year financial hedge and RA Agreement with MRP Pacifica Marketing, LLC for a co-located 96MW natural gas peaking facility and a 96MW battery energy storage project in Fresno County;
WHEREAS the 16MW/64MWh battery storage project in Kings County was described in the staff report associated with R-2023-18 and called out in a recital but was inadvertently omitted from the Board action section of the Resolution; and WHEREAS the Board of Directors would like to clarify and affirm that the Board authorization in Resolution No. R-2023-18 includes the 16MW/64MWh battery storage project in Kings County.

NOW, THEREFORE, THE BOARD OF DIRECTORS OF THE EAST BAY COMMUNITY ENERGY AUTHORITY DOES HEREBY RESOLVE AS FOLLOWS:

Attachment Consent Item 8A
Section 1. The EBCE Board of Directors hereby ratifies Resolution No. R-2023- 18, clarifying and affirming that such Board authorization includes the CEO’s authority to negotiate and execute an agreement with MRP Pacifica Marketing, LLC for a 16MW/64MWh battery storage project in Kings County.

Section 2. The EBCE Board of Directors hereby authorizes the CEO to take any necessary action to implement the 16MW/64MWh battery storage project in Kings County.

ADOPTED AND APPROVED this 20th day of September, 2023.

Elisa Márquez, Chair
ATTEST:

Adrian Bankhead, Clerk of the Board
Staff Report Item 12
Staff Report Item 12
TO: East Bay Community Energy Board of Directors
FROM: Marie Fontenot, Vice President of Power Resources SUBJECT: Middle River Power Malaga Contract Approval (Action) DATE: March 15, 2023
__________________________________________________________________ Recommendation
Adopt a Resolution authorizing the Chief Executive Officer to finalize negotiations and execute an Agreement with contracting entity MRP Pacifica Marketing, LLC for the Malaga contract. The Malaga contract is a 15-year, multi-product agreement comprised of a financial hedge backed by physical resources and RA from a co-located existing natural gas peaker plant and an incremental battery storage project in Fresno County as well as RA from an incremental battery storage project in Kings County, CA. with April 1, 2024 as the date for contract deliveries to begin. The project is being developed by Middle River Power, LLC.

Background and Discussion
The 2022 Long-Term Resource Request for Offers (RFO) is EBCE’s third long-term contract solicitation. The RFO was launched in February 2022. The RFO sought several hundred megawatts (MW) of contracts with renewable energy and battery storage projects with a preference for projects located in California, and more preferentially, those located in Alameda County. EBCE’s objective was to drive investments in new renewable and energy storage projects in Alameda County and California, while securing affordable resources to manage future power price risk. EBCE received a healthy response to its RFO both in volume and quality of projects and proposals.

EBCE administered the RFO and completed robust analytics using internal tools and the cQuant valuation platform to calculate the net present value of proposed projects and determine the optimal portfolio to meet its objectives. All of these contracts will be utilized to hedge EBCE against price fluctuation in the CAISO energy markets and they will contribute to procurement mandates issued by the California Public Utilities Attachment Consent Item 8B
Staff Report Item 12
Commission (CPUC). The 2021-2023 Electric Reliability Requirements procurement mandate identified volumes of RA capacity each CPUC-jurisdictional load serving entity must procure and have online in the years 2021, 2022 and 2023.1 The second mandate requires additional volumes of RA come online in years 2023, 2024, 2025, and 2026. That mandate is the “Decision Requirement Procurement to Address Mid-Term Reliability 2023-2026”.2 The Malaga contract is comprised of multiple products and three resources; the deal structure includes a financial hedge backed by physical resources and two RA agreements. The Malaga contract was originally offered to EBCE in its 2020 RFO but was re-evaluated during the 2022 RFO process. Staff sees value to this unique mixture of products: a financial hedge offered in part by an existing asset is especially valuable in the current climate: supply chain problems continue to delay the construction of new facilities and investor-owned utilities experience delays in their ability to interconnect new generating resources, and RA provided by a natural gas plant will contribute to EBCE’s position and is needed as the RA rules undergo redesign. The hedge is intended to provide financial coverage, a form of insurance policy, for EBCE during the highest demand periods of the year and will provide some coverage of EBCE’s open position. The proposed hedge structure is a financial transaction only, EBCE will not take possession of or title to the energy generated by the natural gas plant or the energy charged and discharged by the co-located battery; as such the transaction will not add emissions to EBCE’s portfolio.

The physical resources that comprise the contract are a co-located 96MW natural gas peaking facility and a 96MW/96MWh battery storage project in Fresno County and an additional 16MW/64MWh battery storage project in Kings County. The natural gas peaking facility is existing; the batteries are new and not yet developed. The 96MW battery storage project co-located with the gas plant is noteworthy in the addition of this new resource is intended to result in reduced dispatch of the co-located natural gas peaking facility by the CAISO market. The contract is for 15 years with is expected to begin delivery on April 1, 2024. Middle River Power is an experienced developer and project owner having numerous operating natural gas facilities in California. Middle River Power has executed a similar agreement with another CCA.

The contracting entity is MRP Pacifica Marketing, LLC.

Attachments
A. Resolution Authorizing the CEO to Negotiate and Execute a Fifteen-Year Financial Hedge and RA Agreement with MRP Pacifica Marketing, LLC.

B. PowerPoint Presentation
1 https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M319/K825/319825388.PDF 2 https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M389/K603/389603637.PDF Attachment Consent Item 8B
Attachment Staff Report Item 12B
RESOLUTION NO. R-2023-XX

A RESOLUTION OF THE BOARD OF DIRECTORS

OF THE EAST BAY COMMUNITY ENERGY AUTHORITY AUTHORIZING THE CEO TO

NEGOTIATE AND EXECUTE A DISPATCHABLE ENERGY AND ENERGY STORAGE

AGREEMENT WITH MRP PACIFICA MARKETING, LLC
WHEREAS The East Bay Community Energy Authority (“EBCE”) was formed as a community choice aggregation agency (“CCA”) on December 1, 2016, Under the Joint Exercise of Power Act, California Government Code sections 6500 et seq., among the County of Alameda, and the Cities of Albany, Berkeley, Dublin, Emeryville, Fremont, Hayward, Livermore, Piedmont, Oakland, San Leandro, and Union City to study, promote, develop, conduct, operate, and manage energy-related climate change programs in all of the member jurisdictions. The cities of Newark and Pleasanton, located in Alameda County, along with the City of Tracy, located in San Joaquin County, were added as members of EBCE and parties to the JPA in March of 2020.

NOW, THEREFORE, THE BOARD OF DIRECTORS OF THE EAST BAY COMMUNITY ENERGY AUTHORITY DOES HEREBY RESOLVE AS FOLLOWS:

Section 1. The CEO is hereby authorized to negotiate and execute a fifteen-year financial hedge and RA Agreement with MRP Pacifica Marketing, LLC for a co-located 96MW natural gas peaking facility and a 96MW battery energy storage project in Fresno County. The final agreement shall include the key terms outlined in the Staff Report associated with this Resolution.

ADOPTED AND APPROVED this 15th day of March, 2023.

Attachment Consent Item 8B
Attachment Staff Report Item 12B

Elisa Marquez, Chair
ATTEST:

Adrian Bankhead, Clerk of the Board
Attachment Consent Item 8B
Bilateral Contract for Board
Consideration
PRESENTED BY: Marie Fontenot
DATE: March 15, 2023
Attachment Staff Report Item 12B Attachment Consent Item 8B • Context:
– Recent 2022 RFO Solicitation Overview
– 2022 RFO Participation
– Evaluation Process
• Current RFO Portfolio Characteristics
• Projects Proposed for Execution
• Challenges in Marketplace
• Next Steps
• Appendix: Portfolio Summary
2 Agenda
Attachment Staff Report Item 12B Attachment Consent Item 8B Goals & Objectives
• Secure a portfolio of contracts
to provide EBCE customers
with affordable renewable
and clean energy sources
• Meet IRP Near- and Mid-Term
Resource Adequacy Reliability
Procurement mandates
• Meet a significant percent of
SB350 long-term contracting
requirements, equal to 65% of
RPS obligations
• Create new renewable energy
projects to deliver PCC1 RECs
• Contract low-cost energy
hedges to compliment
existing portfolio
• Partner with SJCE for
efficiency, to minimize
expenses, and lead the
market in contract terms
Actions
• Issued a broad, open,
competitive solicitation to
ensure wide array of
opportunities considered
• Evaluated combinations of
projects to achieve desired
volume targets
• Typically prioritize project risk,
location, workforce
development, economics, and
other characteristics; limited
ability to do so in this RFO due
to limited offers in earlier years
• Encouraged RFO participants
to be creative and provide
proposal variations on
individual projects and include
battery storage
3 Project Characteristics
Facilities:
• Location: Projects may be within or outside
of California. All energy must be deliverable
to CAISO & must provide RA
• Construction Status: Energy and related
products may come from new resources or
add incremental capacity to existing
resources.

Capacity:
• Minimum Contract Capacity: 5 MW
• Maximum Contract Capacity: none
Delivery Date:
• Energy and RPS attribute delivery must be
within calendar years 2023, 2024, 2025, or
2026 with a preference for projects that
begin delivery earlier within this window.

Contract Duration:
• 10-20 year durations
Technology:
• Renewables, Large Hydro
• Storage – short or long duration; any
technology
Solicitation Overview
Attachment Staff Report Item 12B Attachment Consent Item 8B 4 Solicitation Overview – Eligible Products
Product # Product Name Description Example
Product 1 As-Available RPS Product New or incremental capacity to an existing stand-alone PCC1-eligible generating resource solar, wind, geothermal, small
hydro or ocean (thermal,
wave, or current)
Product 2 As-Available RPS plus
Energy Storage
New or incremental capacity to an existing stand-alone PCC1-eligible generating resource with co-located energy storageSame as above plus storage with 2-hr, 4-hr, or 4-hr+
duration capability
Product 3 Firm or Shaped RPS
Product
New PCC1-eligible generating resources; likely
paired with energy storage
Energy delivered during
specific hours
Product 4 High Capacity Factor, No
On-Site Emissions RPS
Energy
New stand-alone PCC1-eligible generating
resource
Geothermal or Biomass
Product 5 Stand-Alone Energy
Storage Toll or RA-Only
offer
Energy storage may offer a full product “tolling”
structure contract or and RA-only offer
Any storage technology with
2-hr, 4-hr, or 4-hr+ duration
capability
Product 6 Zero-Emitting Capacity
Resources
Must be available every day from 5pm to 10pm
(hours ending 17 through 22); must be able to
deliver at least 5 MWh of energy for every 1 MW
of incremental capacity
Emission-free generation
resources, emissions-free
generation paired with
storage, or demand response
Attachment Staff Report Item 12B Attachment Consent Item 8B 5 Participation
• Less robust project offering than 2020 RFO. 44 unique project sites; 185 contract variations (as compared to 70 sites; 400 project variations in 2020 RFO) • All 6 products that were solicited were offered
• Offers included solar, wind, geothermal, pumped hydro, and storage • Projects based in 6 different states (CA, AZ, ID, NM, NV, OR); predominantly CA – *Only 1 projects in EBCE service territory.

Attachment Staff Report Item 12B Attachment Consent Item 8B Evaluation Process
• Evaluation Rubric scored 3 areas:
– Counterparty Execution, Offer Competitiveness, and Project Development Status – Multiple items under each area
• Two reviewers were assigned to each project.
• Staff reviewed all submitted information and provided scores for all categories except for Term Sheet Markups and NPV.
– Each item has 10 point max. at its own weighting.
– Term Sheet Markups were scored by one assigned reviewer. – NPV scores were directly incorporated into overall project score with a weighting of 45%. • The Net Present Value was calculated based on simulations on 3 different forward curves • For each forward curve we took a weighted average of the P5 (50%), P50 (25%), and P95 (25%) and then took a simple average across the 3 curves
• We normalized this number on a $/MW basis and the projects were then assigned a 0-10 score based on the NPV distribution
• Scoring and rubric were consistent with the selection process for the 2018 California Renewables RFP and 2020 RPS and Storage RFO.
6 Attachment Staff Report Item 12B Attachment Consent Item 8B 2022 RFO Portfolio Characteristics
7 Developer Project Location Product Offtake COD Nameplate Sept NQC
Gener
-ation
Longroad Sun Pond Maricopa County,
AZ
PV and
ESA EBCE 4/1/2025 85 MW 34.4
Stor-age
NextEra
Energy
Kola Energy
Storage
San Joaquin County
(Tracy), CA ESA EBCE 6/1/2025 125 MW 116.75
RA Only
ConEd Alpaugh BESS Tulare County, CA RA only EBCE 6/1/2024 5 MW 4.5 Vitol Ocotillo Solar San Diego County,
CA RA only EBCE 8/1/2023 50 MW 50
Broad Reach
Power
Noosa Energy
Storage
San Joaquin County,
CA RA only EBCE & SJCE 6/1/2024 30 MW 27
Broad Reach
Power
Cascade Energy
Storage
San Joaquin County,
CA RA only EBCE &
SJCE 6/1/2024 5 MW 4.5
Attachment Staff Report Item 12B Attachment Consent Item 8B “Existing” Portfolio Summary
8 Attachment Staff Report Item 12B Attachment Consent Item 8B Middle River Power – Malaga Dispatchable Energy and
Energy Storage Project Details
9 • Originated and negotiated bilaterally. Originally offered into 2020 Renewable Resource and Energy Request for Offers (RFO).
• Financial Hedge back by physical assets and RA Agreement. – Existing gas peaker plant
– Two new batteries
• 15-year contract
• Expected Initial Contract Delivery Date is April 1, 2024 • Project has an executed interconnection agreement.
• The contracting entity under Middle River Power (MRP) is MRP Pacifica Marketing, LLC.

Attachment Staff Report Item 12B Attachment Consent Item 8B Middle River Power Company Overview
10 • Middle River Power is a private equity sponsored investment and asset management platform focused on US power generation assets. • Middle River Power owns and operates 2300 MW of natural gas fired generation with 160 MW of peaker and 100 MW of solar in development within California and a combined total of over 3000 MW throughout the US.
• Middle River Power has 420 MW of co-located natural gas and battery storage in development within California.
• MRP has successfully developed and contracted several assets in California such as a 100 MW solar project with a 50 MW battery in Victorville, a 60 MW standalone battery, and a 130 MW geothermal project in Coso Junction, California • Middle River Power is an experienced power owner and operator in California with several their projects contracted with PG&E ending in 2022.

Attachment Staff Report Item 12B Attachment Consent Item 8B Example Portfolio – Market Exposure
11 • Modeling exhibits a preference for portfolios that, on average, limit EBCE’s sales of excess electricity into the market. This leads to periods of market reliance in “high load” months to limit exposure to low / negative prices in “lower load” months
Sample week
– April 2030
Sample week
– July 2030
Portfolio is “long”
Attachment Staff Report Item 12B Attachment Consent Item 8B Challenges in Marketplace
• Supply Chain
• Permitting Delays
• Interconnection Delays
• Risk of additional governmental intervention, similar to solar anti-circumvention investigation of 2022 12 Attachment Staff Report Item 12B Attachment Consent Item 8B Next Steps
• Finalize contract and execute agreements.
• Assess project as it hits key milestones and matures further. • Update filing to CPUC on status of 2021-2023 and 2023-2026 Electric Reliability Requirements due June 1, 2023.
13 Attachment Staff Report Item 12B Attachment Consent Item 8B Appendix
14 Attachment Staff Report Item 12B Attachment Consent Item 8B CEO Report Item 9
CEO Report Item 9
TO: East Bay Community Energy Board of Directors
FROM: Nick Chaset, Chief Executive Officer
SUBJECT: CEO Report (Informational Item)
DATE: September 20, 2023
________________________________________________________________________ Recommendation
Accept Chief Executive Officer (CEO) report on update items below.

Special Board Retreat – Analytics
A Special Board Retreat for the Analytics team was held on July 13, 2023. Members were introduced to the Analytics team and received updates about infrastructure, security and collaboration with other CCAs. This meeting concluded the 2023 Special Board Retreat series.

Executive Committee Meeting
The September 6th meeting of Executive Committee meeting was canceled. The next Executive Committee meeting will be held on October 4, 2023 at 9am.

Finance, Administration and Procurement Subcommittee Meeting The Finance, Administration and Procurement Subcommittee met on Tuesday, September 5, 2023. Members received updates about the audit and the status of recruiting treasury managers. Members also received a review of the Energy Prepay #3 recent transaction closing. The next Finance, Administration and Procurement Subcommittee will be held on November 8, 2023 at 1pm.

New Staff
Ryne Dudley – Manager of Structured Finance
Ryne joined EBCE in September 2023 as a Manager on the Structured Finance team. Ryne assists with the sourcing, diligence, structuring, negotiating, and closing of financial transactions that both source and deploy EBCE’s balance sheet capital.

Most recently, Ryne was a member of the Structured Finance team at Stem Inc. where he assisted in the development, structuring, and capital markets activities for over 100MW of C&I and utility scale battery storage projects. Prior to Stem, Ryne held investment and finance roles with companies and investment banks such as Exelixis, Citizens Capital Markets, and Delancey Street Partners.

CEO Report Item 9
Ryne began his career as a private credit analyst at LBC Credit Partners and holds a B.B.A in Finance from Temple University.

Daniel Pratt – Finance Associate
Daniel joined EBCE on 9/11/2023 as a Finance Associate on the Finance team. Daniel will be responsible for the cash management operations as well as helping develop finance specific dashboards.

Prior to EBCE, Daniel worked as an accounting advisor for a CPA firm in San Francisco for 7 years before joining a retail startup in their finance department.

Daniel has a BS in economics from University of Nevada, Reno and an MS in Business Analytics from St Mary’s College of California. He loves board games, baseball, and his dog Mr. Bingley (named by his fiance).

Customer Compliance Communications
Below is a chart of important information on major customer compliance communications in September and October:

Title Joint Rate Mailer Power Content Label Mailer
Compliance Requirement CPUC CEC
Audience All current EBCE and PG&E
bundled customers within our
service territory
All EBCE customers served in 2022
Timing Requirement Typically by 7/1 each year;
extension granted to 9/1 due to
PG&E rate changes
Typically by 10/1 each year
Recently revised to 12/31
Our Timing Email and Mail last week of
August (complete)
Email and Mail first week of October
(not yet final by time of posting)
Key Content • Prescribed template;
oversized postcard
• Co-branded with PG&E
• Compares rate costs of 4
main rates (Resi, CARE, Small
Commercial, Large
Commercial)
• Compares power content of
EBCE to PG&E
• One section is a prescribed
template; remainder of mailer is
used for marketing
• Will include a “coming soon” for
Ava Community Energy
• Compares power content of
EBCE to California
• Includes carbon intensity
Joint Rate Mailer
CEO Report Item 9
Draft Power Content Label Mailer (example sections, not complete mailer) CAC Chair Report Item 10
TO: East Bay Community Energy Board of Directors
FROM: Anne Olivia Eldred, Chair, Community Advisory Committee SUBJECT: CAC Chair Report (Informational Item)
DATE: September 20, 2023
__________________________________________________________________ Recommendation
Accept Chair report on items below.

Al Weinrub
We would like to celebrate the acquisition of 50 years of Al Weinrub’s writings and his historical archive of social movement documents by the University of Massachusetts, Amherst Libraries. The Al Weinrub Justice Papers join the Library’s W.E.B. Dubois and Daniel Elsberg collections, among others, as important historical archives for activists, researchers, historians, and scholars.

Celebration of Life for Al Weinrub 1943-2023
1:00 pm – 5:00 pm, September 23, 2023
Chapel of the Chimes
In lieu of flowers, please consider donating to the Al Weinrub Justice Fund:
https://minutefund.uma-foundation.org/project/38424
Sustainability and Climate Action Plan City Staff and EBCE Coordination Report Staff prepared a response to the report that Community Advisory Committee Member, At-Large Jim Lutz prepared and presented in the July meeting. The CAC received this response at Monday's meeting. Lutz was saddened that the primary message that EBCE member cities were happy with EBCE staff, and wanted to participate earlier in the process so that more of our member cities, particularly our small cities, could take full advantage of EBCE programmatic offerings was missed. Staff offered to meet with Member Lutz off line.

Staff response is attached.

CalCCA filing in the CPUC Diablo Canyon extension proceeding Attached is a CalCCA filing in the CPUC Diablo Canyon extension proceedings. It outlines how non-bypassable charges should be allocated among customers and asks to use RA capacity and GHG-free attributes after 2025. The filing is regarding SB 846.

CAC Comments on Agenda Item 14 - Update on Planning for Net Billing Tariff (NBT) Comments submitted from a technical expert on the CAC who is a homeowner with solar panels with questions regarding the climate and consumer benefits of NBT.

Attachments
A. Staff Response to the Sustainability and Climate Action Plan City Staff and EBCE Coordination Report
B. CalCCA filing in the CPUC Diablo Canyon extension proceeding C. Comments on Agenda Item 14. Update on Planning for Net Billing Tariff CAC Item C4B
Staff Report
TO: East Bay Community Energy Community Advisory Committee FROM: Cait Cady, Public Engagement Coordinator
SUBJECT: EBCE Municipal Staff Coordination
DATE: September 18, 2023
__________________________________________________________________ Recommendation
Receive an update on EBCE’s ongoing engagement efforts with municipal staff partners.

Background and Discussion
A report was presented at the July Community Advisory Committee (CAC) meeting, in which Member Jim Lutz documented conversations with municipal sustainability staff from EBCE’s member jurisdictions and summarized key findings about EBCE’s current municipal engagement efforts. In response to this report, and subsequent interest from Members of the CAC on this topic, EBCE staff would like to share more information about the agency’s ongoing efforts to engage with the staff of our member jurisdictions. EBCE staff were pleased to hear that municipal staff appreciate their jurisdiction’s partnership with EBCE and we are always interested in hearing suggestions for how we can improve our public engagement efforts.

Summary of EBCE’s Engagement with Municipal Staff Partners EBCE sees municipal staff as key partners and stakeholders. As such, we strive for frequent and consistent collaboration.

A central component of our engagement strategy are the monthly meetings with municipal partners. These ‘MuniPals’ meetings are hosted by EBCE’s Public Engagement team and designed to keep our muni partners up to date on all things Attachment CAC Chair Report Item 10A
EBCE and provide a forum for feedback/questions. The meetings are often attended by members of the EBCE team across various departments, who share their expertise and project updates. Our MuniPals meetings regularly cover topics such as local development/programs, legislative tracking, customer care/billing updates, annual budget overviews, marketing efforts, and many more. Every month, EBCE staff coordinate internally to select topics we see as most pressing to share with municipal partners that month.

Additionally, between MuniPals meetings EBCE staff will regularly send out important updates to the group and monthly marketing toolkits to supply member jurisdictions with EBCE content for their own communications efforts.

In the report, a frequent topic was EBCE’s engagement with municipal staff on local programs, with a recommendation that EBCE should be doing more to engage muni partners in program design. First, to highlight some of the engagement our team currently does, over the past year, local programs staff have joined 8 of the past 12 MuniPals meetings and provided lengthy updates on programs in all stages of development. For many of these programs, this initial outreach was a jumping off point for future coordination, numerous ad hoc conversations with interested city staff, and opportunities to solicit feedback on implementation.

Given EBCE’s frequent engagement with city staff, we are aware that some staff partners would prefer a more involved role in program design. EBCE staff appreciate both the enthusiasm and critical expertise municipal staff partners can and do bring to these conversations. Our Local Programs team works diligently to collaborate with key stakeholders, like muni staff, for many programs, particularly regarding implementation planning. In terms of input on the overall direction of EBCE’s programmatic efforts, the Board of Directors is responsible for deciding what programs the agency will pursue, but we encourage coordination between municipal staff and their respective Board Member.

Some programs more than others are very well positioned for significant muni staff input, like those that are designed for municipalities specifically. The Critical Municipal Facilities Resilience program is a great example of this type of program, and municipal staff engagement has been at the center of implementation. The program was designed to address key barriers that our municipal staff colleagues identified for implementing resilience projects in their cities and EBCE has been in constant coordination with our municipal colleagues throughout several phases of the program.

Attachment CAC Chair Report Item 10A
Lastly, when EBCE starts developing new programs, staff design them to serve communities all across the service area. However, there may be times when a program is available to some cities but not all due to a multi-phased implementation approach. For example, public EV charger deployment and the Critical Municipal Facilities Resilience program utilized this approach and were not available to all cities at the time of their initial rollout.

Comparison to Other CCAs/Utilities
EBCE staff wanted to learn more about how other regional agencies, especially neighboring CCAs, engage with municipal staff from the communities that they serve.

After soliciting feedback from neighboring CCAs about their engagement practices, it appears that EBCE’s current engagement strategy already meets or goes above and beyond many best practices in the industry. For example, many comparable agencies do not host regular meetings with municipal staff.

Conclusion
EBCE is grateful for the high levels of engagement from our municipal staff colleagues, and we look forward to continuing this close partnership.

Fiscal Impact
This update has no fiscal impact.

Attachment CAC Chair Report Item 10A
Docket No.: R.23-01-007
Exhibit No.:

Date: June 9, 2023
Witnesses: Brian Dickman

OPENING TESTIMONY OF BRIAN DICKMAN

ON BEHALF OF

THE CALIFORNIA COMMUNITY CHOICE ASSOCIATION
RULEMAKING IMPLEMENTING SENATE BILL 846 CONCERNING

POTENTIAL EXTENSION OF DIABLO CANYON POWER PLAN OPERATIONS Attachment CAC Chair Report Item 10B
i

TABLE OF CONTENTS
I. INTRODUCTION AND SUMMARY OF TESTIMONY .................................................... 1 II. CUSTOMERS PAYING FOR EXTENDED OPERATIONS SHOULD RECEIVE THE BENEFITS OF DCPP’S RA AND GHG-FREE ATTRIBUTES .......................................... 3 A. Costs And Benefits of DCPP Extended Operations Should Be Aligned and Fairly Allocated to Customers ....................................................................................................... 4

1. SB 846 Shifts The Financial Risk of Extending DCPP Operations to Customers, and They Should Benefit Accordingly .............................................................................. 4

2. The Commission Should Follow The CAM Model To Allocate The Costs and Benefits of DCPP Extended Operations ..................................................................... 5 B. DCPP RA Capacity Should Be Allocated to LSEs ............................................................. 7

1. Allocating DCPP RA To LSEs Will Avoid Artificially Understating Resources Available in A Constrained Market ............................................................................ 7

2. Allocating DCPP’s Attributes Will Not Impact The State’s Long-Term Planning Goals ......................................................................................................................... 14 C. The Commission Should Direct PG&E To Continue Offering Voluntary Allocations of DCPP’s GHG-Free Attributes To LSEs ............................................................................ 17 III. PG&E SHOULD BE REQUIRED TO FILE A STAND-ALONE APPLICATION

SEEKING APPROVAL OF THE FORECASTED NET COSTS OF DCPP CONTINUED OPERATION ON AN ANNUAL BASIS ............................................................................ 20 A. A New Annual Application for The Recovery of The Forecasted Costs of DCPP Extended Operations Should Be Structured in The Same Manner As PG&E’s Annual ERRA Forecast Proceeding ............................................................................................... 20 B. PG&E’s DCPP Forecast Application Should Include Detailed Support of The Projected Net Costs to Be Charged Customers ................................................................................. 23 IV. THE NET COSTS OF DCPP EXTENDED OPERATIONS SHOULD BE TRACKED IN

A NEW BALANCING ACCOUNT AND RECOVERED THROUGH A NEW NBC INCLUDED IN IOU DELIVERY RATES .......................................................................... 29 A. PG&E Has Already Developed A New Balancing Account to Record The Net Costs of DCPP Extended Operations .............................................................................................. 30 B. A New NBC Should Be Created and Charged to Customers in Jurisdictional IOUs’ Delivery Rates ................................................................................................................... 30

ATTACHMENTS
ATTACHMENT A: Curriculum Vitae of Brian Dickman
ATTACHMENT B: Select Data Request Responses
Attachment CAC Chair Report Item 10B
1 1 I. INTRODUCTION AND SUMMARY OF TESTIMONY
2 The California Community Choice Association (CalCCA) presents this opening 3 testimony in the Rulemaking Implementing Senate Bill 846 (SB 846) Concerning Potential Extension of Diablo Canyon Power Plant Operations1 4 (DCPP OIR). This testimony has 5 been prepared on behalf of CalCCA by Brian Dickman, Partner, NewGen Strategies and 6 Solutions, LLC. Mr. Dickman’s qualifications are set forth in Attachment A. 7 CalCCA has a particular interest in the Diablo Canyon Power Plant (DCPP) 8 extended operations and this DCPP OIR because SB 846 directs that certain costs of 9 extended operations will be recovered from customers of all load-serving entities (LSEs) 10 subject to the California Public Utilities Commission’s (Commission) jurisdiction, 11 including customers of community choice aggregators (CCA) that are members of 12 CalCCA. This testimony presents CalCCA’s proposals on certain issues falling within 13 Phase 1: Track 2 as established in the April 6, 2023, Assigned Commissioner’s Scoping Memo and Ruling2 14 (OIR Scoping Ruling). Specifically, CalCCA’s proposals address three scoping items, listed below:3 15
16 1. If the Commission directs and authorizes extended operations at DCPP, what 17 are the new processes to authorize annual recovery of all reasonable DCPP 18 extended operation costs and expenses on a forecast basis, including allocation 19 of forecast costs among Commission-jurisdictional load-serving entities. 20 2. Whether additional cost recovery mechanisms, agreements, plans, and/or 21 orders are needed prior to the current retirement dates for Diablo Canyon 22 Units 1 and 2 (i.e., in 2024 and 2025, respectively). 1 Rulemaking (R.) 23-01-007, Rulemaking Implementing Senate Bill 846 Concerning Potential Extension of Diablo Canyon Power Plant Operations (Jan. 12, 2023):
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M501/K368/501368884.PDF. 2 R.23-01-007, Assigned Commissioner’s Scoping Memo and Ruling (Apr. 6, 2023) (Scoping Ruling), at 5-6: https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M505/K462/505462882.PDF. 3 CalCCA reserves the right to respond or comment on other matters within the scope of this proceeding at the appropriate time as included in the OIR Scoping Ruling or other scoping rulings during the course of the proceeding.

Attachment CAC Chair Report Item 10B
2 1 3. Whether and how the benefits of extended operations, including resource 2 adequacy and greenhouse gas-free attributes, should be allocated among the 3 LSEs and customers paying for extended operations.
4 As described further in my testimony, CalCCA recommends the following:
5 • The Commission should adopt the same process currently used for resources 6 subject to the Cost Allocation Mechanism (CAM) to allocate DCPP’s resource 7 adequacy (RA) capacity to all LSEs contributing toward cost recovery. Capacity 8 should be allocated based on each entity’s proportional contribution to the group’s 9 combined 12-month coincident peak.
10 • The Commission should require DCPP’s green-house gas (GHG)-Free attributes 11 be made available to all LSEs contributing toward cost recovery through a 12 voluntary allocation, similar to the current ‘interim’ approach approved for Pacific 13 Gas and Electric Company’s (PG&E) large hydroelectric and nuclear facilities. 14 • The Commission should require PG&E to file a stand-alone application seeking 15 approval of the forecasted net costs of DCPP continued operations on an annual 16 basis. PG&E should be required to present detailed projections of all DCPP costs 17 and revenues in a format similar to the information provided in its general rate 18 case (GRC) and Energy Resource Recovery Account (ERRA) proceedings. 19 • Net DCPP costs that are to be recovered from customers of all jurisdictional LSEs 20 in the state should be allocated to investor-owned utility (IOU) service territories 21 based on the contribution to the group’s combined 12-month coincident peak. 22 • The Commission should require PG&E to track the net costs of DCPP extended 23 operations in a new balancing account and recover those costs through a new non-24 bypassable charge (NBC) included in each IOU’s delivery rates. 25 • In sum, the ratemaking process for DCPP costs would be:
26 1. PG&E prepares an annual DCPP Forecast Application that is similar to 27 but separate from the ERRA Forecast Application.
28 2. A Commission decision in the DCPP Forecast Application sets the level of 29 the revenue requirement to be collected through the DCPP-specific NBC 30 in each IOU’s service territory.
31 3. That revenue requirement is translated to a $/kWh charge for eligible 32 customers in an IOU’s service territory in November and December via 33 each IOU’s consolidated rate change advice letter filing.

Attachment CAC Chair Report Item 10B
3 1 II. CUSTOMERS PAYING FOR EXTENDED OPERATIONS SHOULD RECEIVE 2 THE BENEFITS OF DCPP’S RA AND GHG-FREE ATTRIBUTES
3 There are two ways for the Commission to ensure customers benefit from the 4 value of a resource’s attributes. First, the Commission might assign customers a credit 5 against retail rates. Second, the Commission might allocate resource attributes among the 6 LSEs serving those customers.
7 Currently, the Commission follows the first approach for DCPP. The costs to own 8 and operate DCPP are recovered from bundled and departed load customers in PG&E’s 9 service territory through Power Charge Indifference Adjustment (PCIA) rates, which are 10 structured to recognize the value of DCPP’s generation-related attributes as a credit 11 against retail rates. PG&E charges customers for DCPP’s above-market costs, calculated 12 as the cost of the resource less the market value of its energy and capacity. Generation 13 output is sold into the CAISO market, and the market revenue is netted against DCPP 14 costs. The value of DCPP RA that PG&E retains to meet a portion of its bundled 15 customer RA requirement is reflected as a credit against DCPP costs and reduces PCIA 16 rates for customers. Revenue received from sales of DCPP RA, if any, to third parties is 17 also credited against DCPP costs.
18 Going forward, costs associated with extended operations at DCPP will not be 19 recovered through the PCIA. Instead, SB 846 allows PG&E to charge customers a new 20 NBC to recover all “reasonable costs and expenses necessary to operate [DCPP] beyond the current expiration dates,”4 21 net of market revenue from DCPP operation. Under the 22 cost recovery regime described in SB 846, customer rates will no longer reflect a credit 4 Cal. Pub. Util. Code § 712.8(h)(1).

Attachment CAC Chair Report Item 10B
4 1 for the value of RA, nor will they reflect a credit to recognize the value of the GHG-free 2 attribute of the generation.
3 Consequently, the Commission would need to follow the second method to ensure 4 that customers that pay the cost of continued DCPP operation realize the value of 5 continued operations.
6 A. Costs And Benefits of DCPP Extended Operations Should Be Aligned and 7 Fairly Allocated to Customers
8 1. SB 846 Shifts The Financial Risk of Extending DCPP Operations to 9 Customers, and They Should Benefit Accordingly
10 SB 846 alters the cost recovery framework for DCPP during extended operations 11 and shifts the financial risk of extending operations to customers throughout California. 12 Pursuant to SB 846, PG&E will assess several new charges to customers to compensate 13 PG&E shareholders “in lieu of a rate-based return on investments and in acknowledgment of the greater risk of outages in an older plant.”5 14 Specifically, PG&E will collect 15 $13.00/MWh for each MWh generated by DCPP, plus a fixed payment of $100 million 16 ($50 million per unit) annually. Together, these fees collected in lieu of a rate-based return total approximately $320 million6 17 per year, compared to $143 million in annual return on 18 rate base proposed by PG&E in its 2023 GRC. SB 846 entitles PG&E to recover from 19 customers the cost of replacement power during unplanned outage periods, even if the 20 unplanned outage is the result of a failure by PG&E to meet the reasonable manager standard.
7 21 In fact, PG&E is allowed to charge all customers up front to fund a $300 22 million liquidated damages balancing account that can be used to cover the cost of 5 Cal. Pub. Util. Code § 712.8(f)(5) and § 712.8(f)(6). 6 Volumetric payments estimated based on actual generation output during 2021. 7 Cal. Pub. Util. Code § 712.8(i)(1).

Attachment CAC Chair Report Item 10B
5 1 replacement power during these imprudent outages. It is not reasonable for customers to 2 bear all of these costs, including more than doubling the payments to PG&E shareholders, 3 without realizing the corresponding benefits of the plant’s extended operation. 4 2. The Commission Should Follow The CAM Model To Allocate The Costs 5 and Benefits of DCPP Extended Operations
6 SB 846 extended the life of the DCPP plant for the benefit of all California’s electric 7 customers while designating a single IOU, PG&E, as the operator. Public Resources Code 8 Section 25548.7 states, “Continued operation of the Diablo Canyon powerplant as provided 9 in this chapter is in all respects for the welfare and the benefit of the people of the state…” 10 Based on this rationale, SB 846 also alters the cost recovery framework for DCPP during 11 extended operations. SB 846 entitles PG&E to recover the reasonable and necessary costs to 12 operate DCPP beyond the current expiration dates, net of market revenue from DCPP 13 operation. With limited exceptions, SB 846 specifies that DCPP extended operations costs 14 are to be recovered from customers of all jurisdictional LSEs in California. 15 The rationale and framework for extending DCPP operations described in SB 846 16 is similar to the CAM concept originally established by the Commission in Decision (D.) 17 06-07-029. The Commission adopted the CAM as a mechanism to streamline 18 procurement of critical new resources for the benefit of multiple customer groups (e.g., 19 bundled and unbundled customers). In D.06-07-029 the Commission stated, “[We] are 20 adopting a cost-allocation mechanism… that allows the advantages and costs of new 21 generation to be shared by all benefiting customers in an IOU’s service territory. We 22 designate the IOUs to procure this new generation. The LSEs in the IOU’s service 23 territory will be allocated rights to the capacity that can be applied toward each LSE’s 24 RA requirements. The LSE’s customers receiving the benefit of this additional capacity Attachment CAC Chair Report Item 10B
6 1 pay only for the net cost of this capacity, determined as a net of the total cost of the contract minus the energy revenues associated with dispatch of the contract.”8 2 3 As directed by the Commission, IOUs procure CAM resources for the benefit of 4 all customers in their respective service territories. CAM resource costs, net of revenues 5 from selling energy and ancillary services into the California Independent System 6 Operator (CAISO) market, are then recovered from all customers in each IOU’s service 7 territory through a volumetric NBC. PG&E’s CAM NBC is known as the New System 8 Generation Charge (NSGC).
9 Recognizing the similarities between CAM and DCPP extended operations, a 10 fundamental principle that should be followed here is that the allocation of costs and 11 benefits should be aligned and fairly distributed to customers. When establishing the 12 CAM, the Commission determined, “[a]ll RA counting benefits and net costs are spread 13 to the LSEs whose customers are allocated costs based on share of 12-month coincident 14 peak, adjusted on a monthly basis to facilitate load migration. The contract costs paid and 15 RA benefits received by [departed load] and bundled customers should be based on a share basis equal to the credit share received.”9 16
17 The Commission should allocate the costs and benefits of DCPP extended 18 operations the same way it allocates the costs and benefits of CAM resources. 19 Specifically, net costs that PG&E will recover from customers of all jurisdictional LSEs 20 in the state, per SB 846, should be allocated to IOU service territories based on the contribution to the group’s combined 12-month coincident peak.10 21 As I describe later in 8 D.06-07-029 at 7.
9 Id. at 31.
10 The 12-month coincident peak allocation should be consistent with the RA attribute allocation prepared by Energy Division to match costs and benefits.

Attachment CAC Chair Report Item 10B
7 1 my testimony, each IOU would recover the allocated DCPP costs from all customers in 2 its service territory through a new NBC included in delivery rates. 3 Each Commission-jurisdictional LSE should also receive a proportional share of 4 DCPP’s RA attributes, based on a share of the 12-month coincident peak. At a high level, 5 following the CAM procedures already in place for the Commission’s RA compliance 6 program, Energy Division should include an allocation of DCPP RA capacity in the RA 7 template for each LSE, reducing the System RA requirement for each LSE by its share of 8 DCPP capacity for compliance periods during extended operations. Below, I describe in 9 more detail how the Commission should allocate DCPP RA to LSEs. 10 B. DCPP RA Capacity Should Be Allocated to LSEs
11 1. Allocating DCPP RA To LSEs Will Avoid Artificially Understating 12 Resources Available in A Constrained Market
13 California LSEs face a constrained RA market, despite the fact that DCPP 14 remains in operation. Several different analyses have now concluded that, unless recent 15 weather patterns shift back to “normal,” to avoid significant capacity shortages until 16 unprecedented amounts of new resources can be brought online, DCPP should continue 17 to operate. As LSEs seek to procure sufficient resources to meet their obligations under 18 the Commission’s Resource Adequacy program they are already faced with year-over-19 year price increases, price spikes in high demand summer months, and a lack of capacity 20 available in the market. Ignoring DCPP in the RA market, especially when it is still 21 operating and providing system capacity, will only exacerbate the market constraints and 22 artificially increase rates.
23 The California Energy Commission (CEC) staff report on Diablo Canyon Power 24 Plant Extension (CEC Report) published in March 2023 recommends the CEC determine Attachment CAC Chair Report Item 10B
8 1 that it is prudent for the state to pursue extension of DCPP due to the risk that sufficient 2 resources may not be built in time to reach procurement targets ordered by the Commission and to address potential grid demands in extreme heat events.11 3 The CEC Report relies on a 4 deterministic resource stack analysis to evaluate capacity needs through 2032 assuming 5 DCPP units are retired. The analysis indicates that under planning, or ‘normal,’ 6 circumstances the CAISO market should have sufficient capacity to meet demand. 7 However, the report demonstrates that deviations from normal conditions, such as the heat 8 waves experienced in California during 2020 and 2022, will put significant strain on the 9 available capacity and result in resource shortages during critical summer months. 10 The CEC also recognizes that its analysis relies on aggressive assumptions, 11 including the “ability to build new clean energy resources at a pace not seen before and in the face of supply chain, interconnection, and permitting delays.”12 12 In fact, when the CEC 13 considered resource delays and summer temperatures equivalent to those experienced in 14 2022, the stack analysis demonstrates anticipated capacity shortfalls exceeding 2,000 15 MW through 2029.
16 The relevance of this conclusion is underscored by the Joint Agency Reliability 17 Planning Assessment (Joint Agency Report) published by the CEC and the Commission 18 in February 2023. The Joint Agency Report details that climate driven events had a 19 significant impact on CAISO system reliability in each of the last three years:
20 Climate change is causing substantial variability in weather patterns 21 and an increase in climate-driven natural disasters, which is 22 resulting in more challenges to maintaining grid reliability. In 2020, 23 a west-wide heat event resulted in rotating outages August 14 and 24 15. In 2021, dry conditions resulted in a wildfire in Oregon that 25 impacted transmission lines that California depends on for 11 CEC Report at. ii. 12 Id. at 25.

Attachment CAC Chair Report Item 10B
9 1 reliability, resulting in a loss of 3,000 megawatts (MW) of imports 2 to the California Independent System Operator (California ISO) 3 territory and 4,000 MW of overall import capacity to the state. In 4 2022, California experienced record high temperatures between 5 August 31 and September 9. On September 6, 2022, the California 6 ISO recorded a new record peak load at 52,061 MW, nearly 2,000 7 MW higher than the previous record, despite significant efforts to reduce load during this peak period.13 8
9 As part of its reliability assessment, the Joint Agency Report concluded that if DCPP is 10 retired by 2025, capacity shortfalls of 500 MW to 3,800 MW are expected between 2023 11 and 2027 unless the heat events that occurred in 2020 and 2022 are aberrations and not part of the ‘new normal’ Californians face.14 12
13 The CEC Report also acknowledges the shortcomings of a deterministic stack 14 analysis approach, stating, “It is difficult to articulate the probability of the outcomes 15 contained in the results from a deterministic stack approach. Thus, the actual probability of 16 the outage risks associated with different supply and demand balances are uncertain, especially when looking far into the future.”15 17 Notably, the CAISO conducted a probabilistic 18 production cost modeling analysis to support the Commission IRP process, inform summer 19 preparedness activities, and support the CEC’s evaluation of the prudence of extending 20 DCPP operation. The CAISO analysis found capacity shortages between approximately 750 21 MW and 1,285 MW are expected in 2025 and 2026, even after considering new resource additions identified in the IRP or as ordered by Commission procurement decisions.16 22 23 CalCCA witnesses Eric Little and Andrew Mills sponsor testimony in this 24 proceeding to present an analysis of the constrained RA market published by CalCCA in 13 Joint Agency Reliability Planning Assessment at 7 (Feb. 2023). 14 Id. at 50. 15 CEC Report at 16. 16 February 2, 2023 Letter to CEC Vice Chair, available at http://www.caiso.com/Documents/Jan2- 2023-Letter-CaliforniaEnergyCommissionViceChair-CAISOReliabilityModeling.pdf.

Attachment CAC Chair Report Item 10B
10 1 March 2023 (CalCCA Stack Analysis), updated to include recent information regarding 2 the status of the RA market. The CalCCA Stack Analysis concurs with the CEC’s 3 analysis, finding that certain conditions similar to those considered in the CEC analysis 4 are contributing to RA shortfalls including extreme weather conditions, declining hydro 5 resource availability due to drought, delays bringing new resources online, increasing 6 capacity needs across the Western region, and restrictive regulatory requirements. Based 7 on its updated analysis, CalCCA anticipates a 433 MW shortage for 2023, growing to a 8 1,258 MW shortage in 2025.
9 All of these assessments point to the same conclusion: capacity is scarce, it will 10 remain scarce, and DCPP provides needed System RA. One symptom of the constrained 11 RA market is that many LSEs have been unable to meet their System RA requirements 12 despite being willing to pay. The Enforcement Actions Spreadsheet updated by the 13 Consumer Protection and Enforcement Division in February 2023 tracks RA citations 14 issues to various entities from October 2009 through November 2022. As shown in 15 Figure 1, there was a sharp increase in the number of citations in 2019, and elevated 16 levels continued through 2022.

Attachment CAC Chair Report Item 10B
11 1 Figure 1
2 3 Another symptom of the constrained market is the steadily increasing price of 4 System RA. Figure 2 below reproduces Figure 4 from the 2021 Resource Adequacy Report,17 5 showing the rise in RA prices from 2017 to 2021. 17 2021 Resource Adequacy Report: https://webproda.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/resource-adequacy-homepage/2021_ra_report_040523.pdf.

Attachment CAC Chair Report Item 10B
12 1 Figure 2
2 3 As the figure shows, Energy Division’s 2021 Resource Adequacy Report illustrates that the 4 average price of System RA transactions executed for August 2021 was 158% higher than for August 2017.18 5 The RA market price benchmarks calculated by Energy Division in 6 September 2022 report that System RA prices in 2022 averaged $8.11/kW-month over the 7 entire year, and the forecast for average System RA prices in 2023 is $7.39/kW-month. 8 Energy Division’s data also shows that variation in RA prices during 2021 was 9 significantly greater during high-demand summer months relative to other periods; prices for 15 percent of transactions exceeded $14/kW-month during July – September 2021.19 10 18 Id. at 28-29.
19 Id. at 27-28.

Attachment CAC Chair Report Item 10B
13 1 The CalCCA Stack Analysis concurs, finding “Resources that garnered $3.63 kilowatt 2 (kW)-month in 2019 rose to prices as high as the mid-$40 kW-month for summer 2023 and are increasingly unavailable at any price.”20 3 Figure 3 below presents Energy 4 Division’s monthly price data for 2021 in graph form. 5 Figure 3
6 7 Price spikes such as these in the short-term RA market simply create a windfall for 8 existing generation owners at the expense of retail consumers. There is no incremental 9 reliability benefit to the system from these increased costs. 10 Withholding DCPP’s 2,280 MW of capacity from the RA market would worsen the 11 market constraints causing such spikes. Further squeezing the RA market by ignoring DCPP will increase costs for customers by over $200 million21 12 annually as they are required to 13 procure RA rather than count the DCPP capacity they pay for during extended operations. 14 There will be no incremental reliability benefit accompanying this dramatic rate increase. 20 CalCCA Stack Analysis at 2. Internal citation omitted. 21 2,280 MW * $7.39/kW-month * 1,000 * 12 = $202.2 million.

Attachment CAC Chair Report Item 10B
14 1 2. Allocating DCPP’s Attributes Will Not Impact The State’s Long-Term 2 Planning Goals
3 Regardless of the cause of the scarcity in the RA market, and the resulting high 4 prices, California will need more resources to contribute to meeting the Commission’s 5 RA requirements until new zero-carbon reliability resources can be built. Recognizing 6 this need, SB 846 describes the purpose of extending DCPP operation: “Preserving the 7 option of continued operations of the Diablo Canyon powerplant for an additional five 8 years beyond 2025 may be necessary to improve statewide energy system reliability and 9 to reduce the emissions of greenhouse gases while additional renewable energy and zero-10 carbon resources come online, until those new renewable energy and zero-carbon resources are adequate to meet demand.”22 11
12 In Reply Comments on the Order Instituting Rulemaking to establish this 13 proceeding, PG&E argued, “RA allocation to reduce RA compliance procurement activity is 14 in conflict with Legislative direction that the state act with urgency to bring clean 15 replacement energy to support reliability and achieve California’s landmark climate goals.”23 16 This position ignores the difference between the Integrated Resource Planning 17 (IRP) process and the Commissions procurement focused decisions, which drive the 18 construction of new resources, and RA compliance, which drives near-term LSE 19 procurement to optimize the use of already-existing resources. California’s IRP process for 20 Commission-jurisdictional LSEs comprises two parts: 1) identifying an optimal portfolio for 21 meeting state policy objectives, and 2) aggregating the LSEs’ collective efforts for planned 22 PRC § 25548(b). Emphasis added. 23 R.23-01-007, Reply Comments of Pacific Gas And Electric Company (U 39 E) on Administrative Law Judge’s Ruling Requesting Comments on Phase 1: Track 1 Issues (May 31, 2023) (PG&E Reply Comments), at 8: https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M510/K286/510286991.PDF.

Attachment CAC Chair Report Item 10B
15 1 and contracted resources to compare to the optimal system. The Commission IRP process 2 requires jurisdictional LSEs to submit plans every two years to ensure they can meet GHG reduction targets while maintaining system reliability.24 3 In the IRP planning track, the 4 Commission adopts a preferred system plan identifying the optimal portfolio spanning over 5 a ten-year forecast period, and then sets requirements for LSEs to plan toward that future. 6 “To the extent that the CPUC orders procurement in the IRP proceeding, it is generally to meet a reliability or GHG reduction need identified in the planning track.”25 7 8 The purpose of the Commission’s RA program is to ensure capacity resources are 9 contracted for and available to meet California demand in the short term. The 10 Commission describes that the RA program “guides resource procurement and promotes 11 infrastructure investment by requiring that LSEs procure capacity so that capacity is available to the CAISO when and where needed.”26 12 The RA program has two types of 13 filings: annual and monthly. On an annual basis, LSEs are required to demonstrate that 14 they have procured 90% of their System RA obligation for the five summer months of the 15 coming compliance year. On a monthly basis, LSEs must demonstrate they have procured 16 100% of their monthly System RA obligation. LSEs can demonstrate compliance with 17 their RA obligations either through long-term procurement (i.e., pursuant to the IRP and 18 Commission procurement decisions) or through purchases of RA capacity from third 19 parties in the bilateral market.
20 PG&E also argued in its Reply Comments that allocated RA capacity from DCPP 21 to LSEs for RA compliance purposes “would in effect provide a procurement reprieve to 24 Joint Agency Report at 25.
25 Id. at 26.
26 https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/resource-adequacy-homepage, accessed May 23, 2023.

Attachment CAC Chair Report Item 10B
16 1 LSEs, thus, countering the incentive for LSEs to engage in incremental procurement to 2 improve reliability of the state’s electrical system…[T]he Commission is currently 3 considering extended operation through 2030 and, if LSEs assume RA and GHG-free 4 energy from DCPP through 2030, that could impact whether they enter into contracts today for delivery in the late 2020s.”27 5
6 This is not true. The Commission’s IRP process and ensuing procurement 7 decisions will continue to dictate the pace of long-term resource procurement even if 8 DCPP RA counts toward jurisdictional LSEs’ RA compliance obligations in the near 9 term. SB 846 prohibits LSEs from including DCPP energy, capacity, or GHG-free 10 attributes in their resource planning and requires the state to continue to act with urgency to bring clean replacement energy online.28 11 As discussed earlier, however, long-term 12 resource planning differs from short-term RA compliance procurement. Furthermore, 13 LSEs are already acting to bring new capacity online from 2021 through 2026 pursuant to 14 procurement requirements in D.19-11-016 and D.21-06-035, although the Commission 15 recognized in D.23-02-040 challenges related to procuring long-lead time resources. The 16 Joint Agency Report confirms, “Between 2020 and late 2022, the CPUC’s IRP 17 procurement orders and prior LSE procurement resulted in over 11,000 MW of new 18 nameplate energy resources, equivalent to over 6,000 MW of new Net Qualifying Capacity (NQC) that can count toward RA capacity obligations.”29 19 20 Even after accounting for resource additions ordered or planned through the IRP 21 process, the Joint Agency Report found that, under extreme weather conditions, capacity 27 PG&E Reply Comments at 8-9.
28 PRC § 25548(c). 29 Joint Agency Report at 29.

Attachment CAC Chair Report Item 10B
17 1 shortfalls are expected to continue throughout DCPP extended operations. Factoring in 2 possible delays in planned procurement due to supply chain challenges only increases the 3 expected shortfalls. In short, the risk of insufficient or delayed resource procurement 4 drives the need to extend DCPP operations; extension of operations is not the cause of 5 delayed procurement.
6 DCPP RA should be allocated among all LSEs whose customers will pay for the 7 cost of extended operations to avoid artificially understating available resources in an 8 already constrained RA market. The IRP and Commission procurement directives will 9 ensure new resources will be built over the long term. The Commission designed the RA 10 program to ensure resources are under contract and available to meet peak demand in the 11 short term. Removing DCPP from the pool of resources available to count toward System 12 RA requirements will artificially constrict the market, despite DCPP’s continued operation. 13 C. The Commission Should Direct PG&E To Continue Offering Voluntary 14 Allocations of DCPP’s GHG-Free Attributes To LSEs
15 In R.17-06-026, the Commission has been evaluating whether it should 16 incorporate a credit for GHG-Free attributes into the PCIA to reflect the premium value 17 of GHG-Free energy as an offset to resource costs. Analysis of historical market 18 transaction data led Energy Division to conclude in September 2022 that “there is 19 currently a premium for GHG-Free resources” in California and to recommend the value be recognized in the PCIA. 20 30 GHG-Free energy has value to LSEs because it impacts 30 R.17-06-026, Administrative Law Judge’s Ruling Requesting Comments on GHG-Free Resources Staff Proposal and Other Issues (Sept. 12, 2022), Attachment A, “GHG Free Data Analysis and Staff Proposal” (September 12 Staff Proposal), at 5:
https://docs.cpuc.ca.gov/SearchRes.aspx?DocFormat=ALL&DocID=496874129.

Attachment CAC Chair Report Item 10B
18 LSEs’ carbon intensity for the purpose of their Power Content Label.31 1 Receiving GHG-2 Free energy also impacts LSEs’ marketing efforts. On May 4, 2023, the Commission 3 issued a proposed decision in R.17-06-026 (PCIA OIR Proposed Decision) finding that 4 there was sufficient data to support a “heightened value for GHG-Free resources, which 5 can be attributed to [Power Content Label] value or meeting an individual LSEs’ GHG reduction goals more broadly.”32 6
7 The Commission should require PG&E to offer allocations of DCPP’s GHG-Free 8 attributes to LSEs whose customers will pay for extended operations. Doing so simply 9 requires the Commission to continue the status quo, with a few modifications. Resolution 10 E-5111 approved PG&E’s current ‘interim’ allocation process which allocates GHG-Free attributes from resources in PG&E’s PCIA portfolio.33 11 PG&E offers LSEs within its 12 service territory an allocated amount of GHG-Free energy generated by specified facilities corresponding to each LSE’s “Allocation Ratio.”34 13 Once a year PG&E offers 14 each LSE its Allocation Ratio which, after execution of a Sales Agreement, corresponds 15 to an allocated quantity of GHG-Free energy sold to the LSE during the delivery year. 16 Under this framework, LSEs that accept the allocations may report the corresponding 31 Under the CEC’s Power Source Disclosure program, LSEs must disclose to their customers the mix of sources used to provide electricity service during the previous calendar year, and the greenhouse gas emissions intensity of their portfolio. The annual disclosure is made on an LSE’s “Power Content Label.” 32 R.17-06-026, Proposed Decision Addressing Greenhouse Gas-Free Resources, Long-Term Renewable Transactions, Energy Index Calculations, and Energy Service Providers’ Data Access (issued May 4, 2023), at 17: https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M508/K069/508069560.PDF. 33 Allocation of PG&E’s GHG-Free resource was first approved in Resolution E-5046, which adopted Appendix P to PG&E’s 2014 Bundled Procurement Plan specifying the terms under which GHG-Free attributes would be allocated. Resolution E-5111 approved several modifications to Appendix P based on experience with the allocation process to that point. 34 The Allocation Ratio is defined as the LSE’s monthly load forecast used in PG&E’s ERRA Forecast Application compared to the total forecasted load for customers responsible for the costs of the resources. Because allocation of DCPP GHG-Free attributes during extended operations would involve LSE outside of PG&E’s service territory, the CEC’s California Energy Demand forecast, as updated annually, could be used to determine the applicable Allocation Ratio.

Attachment CAC Chair Report Item 10B
19 1 GHG-Free energy on their annual Power Content Label under the CEC’s Power Source 2 Disclosure Program.
3 PG&E should continue to offer voluntary allocations of the GHG-free attributes associated with DCPP.35 4 PG&E’s existing allocation process needs only minor 5 modifications to conform to DCPP’s extended operations. PG&E should modify its 6 Bundled Procurement Plan (BPP) Appendix P to accommodate an annual allocation and 7 offer process for DCPP as a stand-alone specified resource. Under my proposal, PG&E 8 would calculate DCPP GHG-Free generation separate from PG&E’s other resources, and 9 would expand eligibility to receive an allocation of DCPP generation to all California 10 LSEs subject to the DCPP NBC, including PG&E and other IOUs. LSEs can confirm 11 their acceptance of an allocation by executing a sales agreement with PG&E subject to 12 the conditions in PG&E’s BPP Appendix P. Unclaimed allocations, if any, would be 13 unused for that delivery year and would not be reported on any individual LSE PCL or 14 other communications.
15 Continuing voluntary allocations is a reasonable approach to ensuring that cost-16 responsible customers continue to have the option of receiving the benefits of DCPP’s 17 GHG-free energy.
35 The PCIA OIR Proposed Decision adopts a GHG-Free allocation or Market Price Benchmark process for large hydroelectric resources, and allows, but does not require, the IOUs to continue to offer allocations of GHG-Free attributes from PCIA-eligible nuclear resources on a voluntary, annual basis.

The PCIA OIR Proposed Decision ties this framework to the PCIA and eliminates it once the PCIA sunsets. It does not address the continuation of voluntary allocation under a non-PCIA rate mechanism.

Attachment CAC Chair Report Item 10B
20 1 III. PG&E SHOULD BE REQUIRED TO FILE A STAND-ALONE APPLICATION 2 SEEKING APPROVAL OF THE FORECASTED NET COSTS OF DCPP
3 CONTINUED OPERATION ON AN ANNUAL BASIS
4 A. A New Annual Application for The Recovery of The Forecasted Costs of DCPP 5 Extended Operations Should Be Structured in The Same Manner As PG&E’s 6 Annual ERRA Forecast Proceeding
7 PG&E currently establishes the annual cost to operate DCPP through a 8 combination of its GRCs, annual ERRA proceedings, and other filings to address specific issues such as employee retention and decommissioning costs.36 9 PG&E recovers DCPP 10 costs from bundled and departed load customers in its service territory through PCIA and Nuclear Decommissioning rates.37 11 SB 846 directed the Commission to authorize PG&E 12 to recover the net cost of DCPP extended operations through a new proceeding structured similarly to its annual ERRA Forecast proceeding.38 13
14 For the period of DCPP extended operations, PG&E should present for approval a 15 single application with an annual forecast of all DCPP-related costs eligible for recovery 16 from ratepayers (DCPP Forecast Application). As California Public Utilities Code Section 17 712.8(h)(1) suggests, the DCPP Forecast Application should follow a similar process as the 18 ERRA Forecast proceeding, i.e., an initial application presenting PG&E’s forecast of net 19 costs for the subsequent year, followed by a period of party review and opportunities to file 20 testimony. PG&E should also be required to submit an update to forecasted costs, during the 21 pendency of the annual forecast proceeding, to capture the most recent market conditions available prior to establishing the final net cost forecast. 39 22 The Commission should require 36 PG&E Response to CalCCA Data Request 1.01. 37 PG&E Response to CalCCA Data Request 1.02. 38 Cal. Pub. Util. Code § 712.8(h)(l). 39 In PG&E’s annual ERRA Forecast proceedings, PG&E files a “Fall Update” in October providing updated forecasted costs.

Attachment CAC Chair Report Item 10B
21 1 PG&E to prepare its annual DCPP Forecast Application based on the same forecast 2 assumptions used to develop the ERRA Forecast for the corresponding period (including, 3 for example, forecasted market revenues, fuel costs, generation output, and other variables), 4 and procedural milestones in the DCPP Forecast Application should follow a timeline that 5 runs in parallel with the ERRA Forecast proceeding.
6 Despite the similarity between the two filings, the DCPP Forecast Application 7 should be a standalone application to facilitate participation from all affected 8 stakeholders in the state without complicating PG&E’s ERRA Forecast application 9 process. That application is typically limited to a handful of parties seeking to address 10 PG&E-specific issues and rarely includes the other IOUs as parties. Moreover, a 11 substantial amount of work is done in that proceeding, including ratemaking and the 12 implementation of policy directed by other cases. Examples of these issues in just the 13 past few years include:
• The methodology to refund a CAM misallocation;40 14
• The methodology to return ERRA overcollections in an equitable manner;41 15 16 • The methodology to calculate the RA component of Green Tariff Shared Renewable rates;42 17
18 • Implementation of changes to the methodology used to calculate the PCIA from D.18-10-019 and D.19-10-001;43 19
20 • The inclusion of unapproved Catastrophic Event Memorandum Account and 21 Wildfire Expense Memorandum Account costs in the PCIA revenue requirement;44 22 and
40 D.20-02-047 at 10.
41 Id. at 11-12.
42 D.20-12-038 at 28-29. 43 See, e.g., D.18-10-019 at Ordering Paragraphs (OPs) 8 and 10; D.19-10-001 at OPs 2-4. 44 A.21-06-001, PG&E Prepared Testimony at 9-8:10-16 to 9-9:1-4 and Table 9-2.

Attachment CAC Chair Report Item 10B
22 1 • Addressing the accounting resulting from PG&E acting as a Central Procurement 2 Entity (D.20-06-002), to meet 2021 summer reliability targets (D.21-02-028); or 3 to meet the incremental procurement targets 2021-2023 (D.19-11-016) that impact 4 the CAM balancing account, ModCAM balancing accounts and the Portfolio 5 Allocation Balancing Account.
6 Creating a standalone proceeding for DCPP-related issues would avoid overwhelming the 7 expedited ERRA Forecast proceeding with parties and issues that seek to only address 8 DCPP-related issues. The significant non-DCPP-related policy and implementation issues 9 are frequently addressed in PG&E’s ERRA Forecast proceeding. 10 PG&E would no longer present DCPP-related costs in its ERRA Forecast or 11 recover those costs through PCIA rates during the period of extended operations. Rather, 12 PG&E would recover the Commission-approved DCPP net cost forecast through distinct 13 NBCs included in the delivery rates for each IOU’s service territory. 14 Each year as part of the DCPP Forecast Application the Commission would 15 approve 1) the total forecasted DCPP net costs, and 2) the amount allocated to customers 16 in each IOU’s service territory. Each IOU would then be responsible for calculating the 17 corresponding volumetric NBC charged to customers of all jurisdictional LSEs based on electricity consumption in their own service territory.45 18 The IOUs would include their 19 respective NBCs in delivery rates via each IOU’s annual consolidated rate change advice 20 letter process (e.g., the Consolidated Rate Change in Southern California Edison’s service territory and the Annual Electric True-UP (AET) in PG&E’s service territory).46 21 22 In sum, the ratemaking process for DCPP costs would be:
45 Cal. Pub. Util. Code § 712.8(l)(1). 46 See Resolution E-5217 (establishing uniform procedures to standardize the large energy utilities’ annual end-of-year consolidated electric revenue for January 1 rate change advice letter filings to provide a more efficient process) Small jurisdictional IOUs subject to the requirements of SB 846 would follow the equivalent process for routine rate updates in their respective service territories (Aug. 4, 2022):
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M496/K459/496459720.PDF.

Attachment CAC Chair Report Item 10B
23 1 1. PG&E prepares an annual DCPP Forecast Application that is similar to 2 but separate from the ERRA Forecast Application.
3 2. A Commission decision in the DCPP Forecast Application sets the level of 4 the revenue requirement to be collected through the DCPP-specific NBC 5 in each IOU’s service territory.
6 3. That revenue requirement is translated to a $/kWh charge for eligible 7 customers in an IOU’s service territory in November and December via 8 each IOU’s consolidated rate change advice letter filing. 9 B. PG&E’s DCPP Forecast Application Should Include Detailed Support of The 10 Projected Net Costs to Be Charged Customers
11 As described earlier, PG&E is entitled to recover from customers the reasonable 12 costs and expenses necessary to operate DCPP beyond the current expiration dates, net of 13 market revenue from DCPP operation. The Commission should require PG&E to present 14 detailed projections of all costs and revenues during DCPP extended operations in the 15 annual DCPP Forecast Application. The presentation of costs and revenue included in the 16 DCPP Forecast Application should be similar to the information provided in PG&E’s 17 GRC and ERRA proceedings. For example, PG&E should provide details of DCPP fixed 18 costs by Major Work Category (MWC) and FERC account. Detailed generation output 19 projections, nuclear fuel procurement costs, and other related forecast inputs should 20 support forecasts for variable costs.
21 To incorporate the new SB 846 framework, the traditional DCPP revenue 22 requirement calculation requires several changes. For example, SB 846 allows PG&E to 23 recover all operating expenses and certain tax costs, but it is no longer allowed to record 24 capital expenditures to rate base. Routine capital expenditures are to be recovered as 25 operating expenses, and significant one-time capital expenditures may be amortized over 26 more than one year as authorized by the Commission. Furthermore, several new fees will 27 be charged to customers to compensate PG&E shareholders in lieu of a rate-based return Attachment CAC Chair Report Item 10B
24 1 on investments, including a volumetric performance-based fee of $13.00/MWh for each 2 MWh generated by DCPP and a fixed payment of $100 million ($50 million per unit) 3 annually. PG&E is also entitled to charge customers $12.5 million per month to fund a 4 $300 million liquidated damages balancing account that can be used to cover the cost of 5 replacement power during certain outages. Figure 4 provides an illustrative revenue 6 requirement compilation, following a format consistent with the GRC and ERRA, 7 demonstrating the calculation of DCPP net costs before and after adopting the changes 8 that must be implemented pursuant to SB 846.

Attachment CAC Chair Report Item 10B
25 1 Figure 4
2 3 In its May 19, 2023, Prepared Testimony (DCPP Cost Testimony) providing 4 historical and forecast cost information for DCPP, PG&E presented limited cost Line Cost Category Source Current SB 846
1 Operating Expenses
2 Production 2023 GRC; February Update $315,173 $315,173 3 Transmission 2023 GRC; February Update $4,283 $4,283
4 Uncollectibles 2023 GRC; February Update $3,765 $3,765 5 Administrative and General 2023 GRC; February Update $241,315 $241,315 6 Franchise & SFGR Tax Requirement 2023 GRC; February Update $9,577 $9,577 7 Amortization 2023 GRC; February Update $31,327 $31,327 8 Other Adjustments 2023 GRC; February Update ($1,142) ($1,142) 9 Taxes
10 Property 2023 GRC; February Update $19,669 $19,669
11 Payroll 2023 GRC; February Update $18,735 $18,735
12 Business 2023 GRC; February Update $264 $264
13 Other 2023 GRC; February Update $4,964 $4,964
14 State Corporation Franchise 2023 GRC; February Update $30,786 $30,786 15 Federal Income Tax 2023 GRC; February Update $24,010 NA 16 Other
17 Depreciation 2023 GRC; February Update $409,011 NA
18 Other Revenue 2023 GRC; February Update ($4,684) ($4,684) 19 Employee Retention and License Renewal Costs 2023 ERRA/AL 5268-E; 5461-E-A $53,192 $53,192 20 SB 846 Items
21 Fixed Payment In Lieu of Rate-Based Return PUC § 712.8(f)(6) $100,000 22 Volumetric Payment In Lieu of Rate-Based Return PUC § 712.8(f)(5) $228,035 23 Liquidated Damages Balancing Acct Funding PUC § 712.8(g), § 712.8(i) $150,000 24 Replacement Power Costs PUC § 712.8(i) TBD
25 Incremental Decommissioning Planning PUC § 712.8(f)(1), 712.8(f)(3) TBD 26 Independent Review Panel Costs PUC § 712.8(f)(4) TBD 27 Annual Capital Expenditures PUC § 712.8(h)(2) TBD
28 Return on Rate Base
29 Rate Base 2023 GRC; February Update $1,952,370 NA
30 Rate of Return 7.34% NA
31 Return on Rate Base 2023 GRC; February Update $143,304 NA 32 Variable Production Costs
33 Fuel 2021 FERC Form 1 $121,881 $121,881
34 Total Costs $1,425,430 $1,327,140
35 CAISO Market Revenue
36 2023 NP-15 Market Price ($/MWh) 2023 ERRA Energy Index $84.22 $84.22 37 Annual Generation (GWh) 2021 FERC Form 1 17,541 17,541 38 Total Wholesale Market Revenue $1,477,318 $1,477,318 39 Net Costs ($51,887) ($150,178)
($000)
Attachment CAC Chair Report Item 10B
26 1 information according to the Electric Utility Cost Group (EUCG) method which 2 excludes several cost categories that PG&E considers corporate costs but that are assigned or allocated to DCPP for ratemaking purposes.47 3 As operator of the plant, PG&E 4 will continue to incur common corporate costs in support of DCPP extended operations, 5 and these costs are appropriately recovered from customers through the DCPP NBC. 6 PG&E acknowledged in its DCPP Cost Testimony that the annual cost recovery 7 application for extended operations would include all costs relevant to DCPP operations, 8 including common costs such as benefits, overhead, employee retention, regulatory compliance, and statutory charges and fees.48 9 As such, PG&E should present its request 10 for cost recovery in the DCPP Forecast Application in a manner consistent with the GRC 11 and ERRA filings.
12 In addition, the Commission should require PG&E to demonstrate in its DCPP 13 Forecast Application that its DCPP Forecast includes common cost assumptions that are 14 consistent with its 2023 GRC. This GRC includes attrition years that extend beyond the original DCPP expiration dates to 2026 and assumes DCPP is retired.49 15 For example, to 16 determine the DCPP revenue requirement in its GRC PG&E allocates several categories 17 of common corporate costs (e.g., administrative and general expense) to DCPP using 18 approved allocation factors. When asked in discovery, PG&E objected to providing 19 details of the common costs allocated to DCPP in the 2023 GRC and opted not to explain whether actual common costs would be impacted by extended operations.50 20 Because 21 PG&E would not provide these additional details, Figure 4 contains only an illustrative 47 PG&E Prepared Testimony (May 19, 2023) at 2:3-18. 48 Id. at 16:1-13. 49 PG&E Response to CalCCA Data Request 1.04. 50 PG&E Responses to CalCCA Data Requests 1.05- 1.08.

Attachment CAC Chair Report Item 10B
27 1 revenue requirement using summarized cost categories from PG&E’s GRC for the 2023 2 test period. In its DCPP Forecast Application, the Commission should require PG&E to 3 quantify the impact of DCPP extended operations on its common costs relative to the 4 amount approved in its 2023 GRC and demonstrate that there is no double counting of 5 common costs proposed for recovery in the GRC and DCPP NBC. 6 Lastly, SB 846 states: “To the extent the commission decides to allocate any 7 benefits or attributes from extended operations of the Diablo Canyon powerplant, the commission may consider the higher cost to customers in the operator’s service area.” 51 8 9 As a trade association with members that are both within and outside of “the operator’s 10 service area,” CalCCA has a deep interest in finding the fairest way for the Commission 11 to act upon such considerations.
12 Under SB 846, PG&E will assign a small portion of the costs authorized for 13 recovery directly to customers of LSEs in its service territory. Those customers are also 14 the sole beneficiaries of surplus wholesale market revenue and the return of excess funds 15 paid into the liquidated damages balancing account by all customers. For example, half of 16 the volumetric payment in lieu of a rate-based return ($6.50, in 2022 dollars, for each megawatt hour generated by DCPP during the period of extended operations)52 17 is to be 18 paid only by the customers of LSEs in PG&E service territory. In exchange for this cost 19 responsibility, customers of LSEs in PG&E service territory will receive a credit for all 20 surplus wholesale market revenue remaining after offsetting DCPP’s annual operating 21 costs.
51 Cal. Pub. Util. Code § 712.8(q).
52 Cal. Pub. Util. Code § 712.8(f)(5).

Attachment CAC Chair Report Item 10B
28 1 Figure 5 is an illustrative division of net annual costs and revenue recovered from 2 all customers versus those charged only to customers of LSEs in PG&E service territory. 3 Notably, at current wholesale market prices it is possible that the total DCPP costs will be 4 less than the total market revenue. In that case, PG&E will return the surplus revenue only 5 to customers of LSEs in its service territory. Furthermore, even though customers of all 6 LSEs in California will fund the liquidated damages balancing account ($12.5 million per 7 month, up to a total balance of $300 million), funds remaining in the balancing account at 8 the end of DCPP extended operations will be returned solely to customers of LSEs in PG&E service territory.53 9
53 Cal. Pub. Util. Code §§ 712.8(g), 712.8(i), 712.8(u).

Attachment CAC Chair Report Item 10B
29 1 Figure 5
2 3 IV. THE NET COSTS OF DCPP EXTENDED OPERATIONS SHOULD BE TRACKED 4 IN A NEW BALANCING ACCOUNT AND RECOVERED THROUGH A NEW 5 NBC INCLUDED IN IOU DELIVERY RATES
6 As described earlier, PG&E currently recovers its costs to operate DCPP, both 7 direct and indirect, through PCIA rates. To properly track and recover the net costs of 8 DCPP extended operations, all related costs items should no longer be included in the 9 PCIA but should be recorded in a new balancing account established specifically for this purpose.
54 10 PG&E has been developing parameters for the new balancing account, and 54 Notably, in its 2024 ERRA Forecast application filed May 15, 2023, PG&E removed DCPP Unit 1 from the PCIA revenue requirement effective November 2024.

Attachment CAC Chair Report Item 10B
30 1 required subaccounts, to enable tracking and allocation of costs to appropriate LSEs; 2 CalCCA largely supports PG&E’s approach on this matter. 3 A. PG&E Has Already Developed A New Balancing Account to Record The Net 4 Costs of DCPP Extended Operations
5 PG&E proposed the Diablo Canyon Extended Operations Balancing Account 6 (DCEOBA) in Advice Letter (AL) 6870-E to track the costs during DCPP extended 7 operations. CalCCA reviewed PG&E’s proposed tariff statements as part of the AL 6870- 8 E process, and PG&E incorporated CalCCA’s feedback into the tariff language. CalCCA 9 supports using the DCEOBA to track DCPP extended operations cost recovery as long as 10 the tariff language accommodates recording all common costs that may be allocated to 11 DCPP. CalCCA agrees with PG&E’s proposal to allocate cost responsibility by IOU 12 service territory in separate subaccounts of the DCEOBA. 13 B. A New NBC Should Be Created and Charged to Customers in Jurisdictional 14 IOUs’ Delivery Rates
15 California Public Utilities Code Section 712.8(I)(1) specifies, “The recovery of 16 these non-bypassable costs by the [LSEs] shall be based on each customer’s gross 17 consumption of electricity regardless of a customer’s net metering status or purchase of 18 electric energy and service from an [ESP], [CCA], or other third-party source of electric 19 energy or electricity service.” As such, each IOU will need to implement its own NBC 20 and remit to PG&E the revenue received through the charge. 21 As described earlier in my testimony, one outcome of PG&E’s DCPP Annual 22 Forecast will be an allocation of the net costs of DCPP extended operations for the 23 upcoming year by IOU service territory. To develop the DCPP NBC, each IOU would 24 first need to allocate its share of DCPP costs among its unique customer classes. The net 25 costs by customer class would then be divided by the forecast class energy consumption Attachment CAC Chair Report Item 10B
31 1 to develop a $/kWh rate. Similar to the allocation across service territories, DCPP costs 2 should be allocated among customer classes using each customer class’s contribution to 3 12-month coincident peak. This is also the approach currently used to develop CAM 4 surcharges. On an annual basis, each IOU should submit its DCPP NBC proposal for 5 Commission approval and implementation in rates through the annual consolidated rate 6 change advice letter process.
7 This concludes my testimony.

Attachment CAC Chair Report Item 10B

ATTACHMENT A

CURRICULUM VITAE OF BRIAN DICKMAN
Attachment CAC Chair Report Item 10B
Brian Dickman

PARTNER
[email protected]
Economics | Strategy | Stakeholders | Sustainability
www.newgenstrategies.net
Mr. Brian Dickman is a partner in NewGen’s energy practice with 20 years of utility industry experience. Mr. Dickman’s career includes over a decade working for PacifiCorp, a vertically integrated investor-owned utility, including senior-level positions in regulatory, financial, and commercial roles. He began consulting in 2017, assisting a wide array of clients across the United States and internationally, including utilities, large consumers, and private investment firms.

Mr. Dickman has extensive experience preparing and evaluating utility revenue requirements and cost allocation studies, developing utility avoided costs, and analyzing the impact of new initiatives and transactions on a utility and its customers. In addition to his extensive technical experience, Mr. Dickman understands the regulatory governance process, and he has personally testified as an expert witness before state public utility commissions in California, Idaho, Indiana, Oregon, Utah, Washington, and Wyoming.

Mr. Dickman advises numerous Community Choice Aggregator (CCA) clients in California, focusing on regulatory and rate issues such as the state-mandated exit fee known as the Power Charge Indifference Adjustment (PCIA). He also represents California CCAs as a member of the Cost Allocation Mechanism Procurement Review Groups for PG&E and Southern California Edison established by the California Public Utility Commission to provide an independent review of the centralized procurement of local generation capacity requirements.

EDUCATION
 Master of Business Administration, Finance Emphasis, University of Utah  Bachelor of Science, Accounting, Utah State University

KEY EXPERTISE
 Cost of Service and Rates
 Financial Analysis and Modeling
 Power Charge Indifference Amount
 Regulatory Strategy
 Revenue Requirement

RELEVANT EXPERIENCE
Electric Cost of Service, Rate Design, and Regulatory Analysis Mr. Dickman leads projects developing utility revenue requirements, preparing cost of service and rate design studies, and performing financial and regulatory analyses for electric utilities. Mr. Dickman previously held leadership positions at a multi-billion-dollar utility. He was responsible for interfacing with state regulatory agencies in support of revenue requirements, cost recovery mechanisms, avoided costs, valuations of potential asset acquisitions and other commercial opportunities, and financial impacts of utility initiatives. Mr. Dickman now works with clients and stakeholders to prepare pro forma financial models to determine revenue sufficiency, evaluate the cost of service studies and rate design proposals, and support such proposals before local and state governing bodies. Mr. Dickman’s experience also includes evaluating the financial and rate impact of proposed mergers and acquisitions, acquisition and divestiture of utility assets, negotiated retail service contracts, changing business models, and stranded costs due to exiting load.

Attachment CAC Chair Report Item 10B
Expert Witness and Litigation Support
Mr. Dickman provides comprehensive expert witness testimony related to utility revenue requirements, cost of service, rate design, and other ratemaking issues before state and local regulatory bodies. He has provided litigation support in wholesale and retail jurisdictions, including California, Idaho, Indiana, Oregon, Washington, Wyoming, Utah, the Federal Energy Regulatory Commission, and Ontario Energy Board. Mr. Dickman offers expert witness testimony and litigation support in the following areas.

Revenue Requirement | Cost Allocation | Rate Design
Mr. Dickman prepared revenue requirements, inter-jurisdictional cost allocation, coincident peak allocation studies, and supporting testimony for PacifiCorp over many years. He now provides litigation support and expert testimony for clients wishing to review utility filings on revenue requirement, cost allocation, and rate design, including program-specific rate tariffs.

Power Supply Costs | Stranded Costs | Rate Adjustment Mechanisms Mr. Dickman has prepared and evaluated variable power supply cost forecasts, power supply cost balancing accounts and other rate mechanisms, stranded costs, and exit fees for departing load. Since 2019, Mr. Dickman has actively participated in PCIA matters in California on behalf of CCA clients.

Avoided Costs | Resource Valuation
Mr. Dickman provided expert testimony for PacifiCorp on various components included in a proposed method for valuing solar generation resources, the calculation of Public Utility Regulatory Policies Act avoided costs for large resources, and support of modifications to the avoided cost calculation for small resources.

A sample of Mr. Dickman’s utility clients includes the following:
 Abu Dhabi Distribution
Company, UAE
 Central Coast Community
Energy, CA
 City and County of San
Francisco, CA
 Clean Power Alliance, CA
 Duke Energy, NC
 East Bay Community Energy,
CA
 Hydro One, Ontario, CA
 Liberty Utilities, CA
 Lubbock Power and Light, TX
 Minnesota Power, MN
 New York Power Authority,
NY
 Portland General Electric, OR
 San Diego Community Power, CA
 San Jose Clean Energy, CA
 Silicon Valley Clean Energy
Authority, CA
 Vermont Gas Systems, VT
A sample of Mr. Dickman’s non-utility clients includes the following:
 Blackstone Group, NY
 California Community Choice
Association, CA
 Facebook, CA
 Hemlock Semiconductor, MI
 Newmont Mining, NV
 SABIC Innovative Plastics, IN
 Tri-County Metropolitan
Transportation District, OR
 Vistra Energy, TX
Attachment CAC Chair Report Item 10B

WORKSHOPS AND PRESENTATIONS
Host organizations and the topics Mr. Dickman presented are displayed below.

Customer Choice at a Vertically Integrated Utility
Advanced Workshop in Regulation and Competition, Center for Research in Regulated Industries, 2018 Attachment CAC Chair Report Item 10B

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

1. SCE A.12-01-008
A.12-04-020
A.14-01-007
Declaration supporting response to petition for
modification of D.15-01-051, addressing changes to
optional green tariff program rates
California Public Utilities
Commission
Clean Power Alliance,
California Choice
Energy Authority
2022

2. SCE A.22-05-014 Expert testimony evaluating the calculation of the Power Charge Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
Clean Power Alliance,
California Choice
Energy Authority, and
Central Coast
Community Energy
2022

3. PG&E, SCE,
SDG&E
A.20-02-009
A.20-04-002
A.20-06-001
(Consolidated)
Expert testimony evaluating the unrealized sales
volumes and revenue due to Public Safety Power
Shutoff events
California Public Utilities
Commission
CCA Parties (9 individual
CCAs)
2022

4. San Diego
Gas &
Electric
A.21-09-001 Expert testimony responding to proposed residential electrification tariff
California Public Utilities
Commission
San Diego Community
Power and Clean
Energy Alliance
2022

5. San Diego
Gas &
Electric
R.20-05-003 Declaration supporting motion for clarification of D.19- 11-016, quantifying impact to allocated incremental
reliability procurement requirement due to departing
load
California Public Utilities
Commission
San Diego Community
Power
2021

6. Southern
California
Edison
A.21-06-003 Expert testimony evaluating the calculation of the Power Charge Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
Clean Power Alliance
and California Choice
Energy Authority
2021

7. Pacific Gas
& Electric
A.21-06-001 Expert testimony evaluating the calculation of the Power Charge Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
Joint Community Choice
Aggregators
2021

8. San Diego
Gas &
Electric
A.21-04-010 Expert testimony evaluating the calculation of the Power Charge Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
San Diego Community
Power and Clean
Energy Alliance
2021

9. Pacific Gas
& Electric
A.12-01-008
A.12-04-020
A.14-01-007
Declaration supporting petition for modification of
D.15-01-051, recommending changes to optional green
tariff program rates designed to avoid shifting costs of resource capacity to non-participants
California Public Utilities
Commission
Joint Community Choice
Aggregators
2021
Attachment CAC Chair Report Item 10B

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

10. Pacific Gas
& Electric
A.19-11-019 Expert testimony (adopted) addressing use of marginal costs to determine economic development rates and
responding to proposed electrification tariff for retail customers
California Public Utilities
Commission
Joint Community Choice
Aggregators
2021

11. Pacific Gas
& Electric
A.20-07-002 Expert testimony evaluating the calculation of the Power Charge Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
Joint Community Choice
Aggregators
2020

12. Southern
California
Edison
A.20-07-004 Expert testimony evaluating the calculation of the Power Charge Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
Clean Power Alliance
and California Choice
Energy Authority
2020

13. Pacific
Power
Docket UE 375 Joint testimony supporting a settlement agreement resolving the annual variable power supply cost
forecast and generation resource dispatch model
Public Utility
Commission of Oregon
Facebook, Inc. 2020

14. Pacific Gas
& Electric
A.20-02-009 Expert testimony evaluating the appropriateness of entries recorded to the Portfolio Allocation Balancing
Account to true up the Power Charge Indifference
Amount
California Public Utilities
Commission
Joint Community Choice
Aggregators
2020

15. Vectren
Energy
Delivery of
Indiana
Cause No. 43354
MCRA 21 S1
Expert testimony supporting a settlement agreement
regarding the calculation and use of a 4CP load study
to allocate tariff rider costs among customer classes
Indiana Utility
Regulatory Commission
SABIC Innovative
Plastics Mt. Vernon, LLC
2020

16. PacifiCorp Docket UE 307 Expert testimony supporting the annual variable power supply cost forecast and generation resource dispatch
model
Public Utility
Commission of Oregon
2016

17. PacifiCorp Docket UM 1662 Joint testimony with Portland General Electric regarding the need for a renewable resource tracking
mechanism to provide cost recovery related to the
impacts of renewable resource generation
Public Utility
Commission of Oregon
2015

18. PacifiCorp Docket UE 296 Expert testimony supporting the annual variable power supply cost forecast and generation resource dispatch
model
Public Utility
Commission of Oregon
2015
Attachment CAC Chair Report Item 10B

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

19. PacifiCorp Docket No. 20000-
469-ER-15
Expert testimony regarding the annual variable power
supply cost forecast and modifications to the Energy
Cost Adjustment Mechanism
Public Service
Commission of
Wyoming
2015

20. PacifiCorp Docket No. 15-035-
03 Provided expert testimony regarding the true up of
variable power supply costs in the Energy Balancing
Account mechanism
Public Service
Commission of Utah
2015

21. PacifiCorp Docket UM 1716 Expert testimony proposing changes to the calculation of PURPA avoided costs for large resources
Public Utility
Commission of Oregon
2015

22. PacifiCorp Docket No. 20000-
481-EA-15
Expert testimony proposing changes to the calculation
of PURPA avoided costs for large resources
Public Service
Commission of
Wyoming
2015

23. PacifiCorp Docket No. 15-035-
T06
Expert testimony updating standard PURPA avoided
cost prices and supporting modifications to the
avoided cost calculation for small resources
Public Service
Commission of Utah
2015

24. PacifiCorp Case No. PAC-E-15-
03 Expert testimony proposing changes to the calculation of PURPA avoided costs for large resource
Idaho Public Utilities
Commission
2015

25. PacifiCorp Docket UE-144160 Declaration supporting updates to standard PURPA avoided cost prices and supporting modifications to
the avoided cost calculation for small resources
Washington Utilities
and Transportation
Commission
2014

26. PacifiCorp Docket UE 287 Expert testimony supporting the annual variable power supply cost forecast and generation resource dispatch
model
Public Utility
Commission of Oregon
2014

27. PacifiCorp Case No. PAC-E-14-
01 Expert testimony regarding the true up of variable
power supply costs in the Energy Cost Adjustment
Mechanism
Idaho Public Utilities
Commission
2014

28. PacifiCorp Docket A.14-08-002 Expert testimony supporting the annual variable power supply cost forecast and the true up of costs in the
Energy Cost Adjustment Clause mechanism
California Public Utilities
Commission
2014

29. PacifiCorp Docket No. 20000-
447-EA-14
Expert testimony regarding the true up of annual
variable power supply cost in the Energy Cost
Adjustment Mechanism
Public Service
Commission of
Wyoming
2014
Attachment CAC Chair Report Item 10B

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

30. PacifiCorp Docket No. 14-035-
31 Expert testimony regarding the true up of variable
power supply costs in the Energy Balancing Account
mechanism
Public Service
Commission of Utah
2014

31. PacifiCorp Case No. PAC-E-13-
03 Expert testimony regarding the true up of variable
power supply costs in the Energy Cost Adjustment
Mechanism
Idaho Public Utilities
Commission
2013

32. PacifiCorp Docket A.13-08-001 Expert testimony supporting the annual variable power supply cost forecast and the true up of costs in the
Energy Cost Adjustment Clause mechanism
California Public Utilities
Commission
2013

33. PacifiCorp Docket No. 13-035-
32 Expert testimony regarding the true up of variable
power supply costs in the Energy Balancing Account
mechanism
Public Service
Commission of Utah
2013

34. PacifiCorp Docket UM 1610 Expert testimony proposing changes to the calculation of PURPA avoided costs for large and small generation
resources
Public Utility
Commission of Oregon
2012

35. PacifiCorp Docket A.12-08-003 Expert testimony supporting the annual variable power supply cost forecast and the true up of costs in the
Energy Cost Adjustment Clause mechanism
California Public Utilities
Commission
2012

36. PacifiCorp Docket No. 12-035-
67 Expert testimony regarding the true up of variable
power supply costs in the Energy Balancing Account
mechanism
Public Service
Commission of Utah
2012

37. PacifiCorp Docket No. 20000-
389-EP-11
Expert testimony regarding the collection of deferred
balances accrued through previous Power Cost
Adjustment Mechanisms
Public Service
Commission of
Wyoming
2011

38. PacifiCorp Docket No. 20000-
405-ER-11
Inter-jurisdictional cost allocation and revenue
requirement and sponsored expert testimony in
corresponding general rate case
Public Service
Commission of
Wyoming
2011

39. PacifiCorp Case No. GNR-E-11-
03 Expert testimony proposing changes to the calculation of PURPA avoided costs for large and small generation
resources
Idaho Public Utilities
Commission
2011

40. PacifiCorp Case No. PAC-E-06-
10 Expert testimony regarding low income customer
weatherization rebates
Idaho Public Utilities
Commission
2010
Attachment CAC Chair Report Item 10B

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

41. PacifiCorp Docket No. 20000-
405-ER-10
Inter-jurisdictional cost allocation and revenue
requirement and sponsored expert testimony in
corresponding general rate case
Public Service
Commission of
Wyoming
2010

42. PacifiCorp Docket No. 10-035-
89 Inter-jurisdictional cost allocation and revenue
requirement and sponsored expert testimony in
corresponding general rate case
Public Service
Commission of Utah
2010

43. PacifiCorp Docket No. 20000-
352-ER-09
Inter-jurisdictional cost allocation and revenue
requirement and sponsored expert testimony in
corresponding general rate case
Public Service
Commission of
Wyoming
2009

44. PacifiCorp Case No. PAC-E-08-
07 Inter-jurisdictional cost allocation and revenue
requirement and sponsored expert testimony in
corresponding general rate case
Idaho Public Utilities
Commission
2008

45. PacifiCorp Docket No. 20000-
333-ER-08
Inter-jurisdictional cost allocation and revenue
requirement and sponsored expert testimony in
corresponding general rate case
Public Service
Commission of
Wyoming
2008
Attachment CAC Chair Report Item 10B

ATTACHMENT B

SELECT DATA RESPONSES
Attachment CAC Chair Report Item 10B

PACIFIC GAS AND ELECTRIC COMPANY
Diablo Canyon Power Plant Operations Extension OIR
Rulemaking 23-01-007
Data Response
PG&E Data Request No.: CalCCA_001-Q001
PG&E File Name: DiabloCanyonPowerPlantOperationsExtensionOIR_DR_CalCCA_001-Q001 Request Date: May 5, 2023 Requester DR No.: 001
Date Sent: May 19, 2023 Requesting Party: California Community Choice Association
PG&E Witness: Ryan Stanley /
Tom Baldwin
Requester: Nikhil Vijaykar
QUESTION 001
Please identify all accounting mechanisms (including balancing accounts, memorandum accounts, etc.) PG&E relies on to record costs related to Diablo Canyon operation, maintenance, licensing, and decommissioning and retirement.

ANSWER 001
PG&E currently relies on the following active accounting mechanisms to record costs and cost recovery related to Diablo Canyon Power Plant’s (DCPP) operations as follows:

Portfolio Allocation Balancing Account (PABA)
The purpose of this balancing account is to recover all “above-market” costs from all generation resources eligible for recovery through Power Charge Indifference Adjustment (PCIA) rates. This includes several different operational activities as found in PG&E’s Electric Preliminary Statement Part HS and described further below:1 Utility-Owned Generation Revenue Requirements
PABA recovers the base revenue requirements associated with DCPP’s operations, maintenance, and capital recovery as identified in PG&E’s general rate case (as one of several utility-owned generation facilities). PABA also recovers specific revenue requirements related to the DCPP Retention Program and DCPP license renewal costs associated with relicensing costs for the current operating license period (i.e., prior to SB 846). Please see Electric Preliminary Statement Part HS, Tariff Lines 5.n., 5.p through 5.r. for relevant entries related to Utility-Owned Generation revenue requirements.
1 Hyperlink at: https://www.pge.com/tariffs/assets/pdf/tariffbook/ELEC_PRELIM_HS.pdf.

Attachment CAC Chair Report Item 10B
CAISO-Related Entries
PABA also records relevant CAISO activity. This includes energy market revenues from scheduling and/or bidding DCPP into the CAISO market net of any miscellaneous or site-specific load that is also incurred for DCPP. Please see Electric Preliminary Statement Part HS, Tariff Lines 5.t. through 5.v. for relevant CAISO-related entries.

Fuel Costs
In addition, PABA is authorized to recover nuclear fuel expenses and miscellaneous expenses for DCPP, as well as carrying costs on PG&E’s net outstanding nuclear fuel inventory at the rate of the three-month commercial paper rate. Please see Electric Preliminary Statement Part HS, Tariff Lines 5.z. and 5.aa. for relevant nuclear fuel entries.

Note: Recovery within PABA is included through the current licensing period and will not include extension period activity.

Nuclear Decommissioning Adjustment Mechanism (NDAM)
This account recovers authorized nuclear decommissioning revenue requirements and to provide full recovery of costs. In addition, the approved tariff includes recovery of other related expenses including costs to satisfy the requirements of CA Bill 968 and Public Utilities Code Section 712.5 Section 3, DCPP Employee Retraining Program budget, and authorized recovery of funds approved in the Community Impact Mitigation Program (CIMP). Detailed accounting entries can be found in PG&E’s Electric Preliminary Statement Part DB.2
Diablo Canyon Retirement Balancing Account (DCRBA)
This account is used to track actual expenses and capital revenue requirements against expense budgets or capital revenue requirements related to (1) DCPP full book value by the time Units 1 & 2 cease operations, (2) the DCPP Employee Retention Program, and (3) the DCPP Employee Retraining Program. The differences are transferred to PABA or NDAM as applicable and as authorized by the Commission. Detailed entries can be found in PG&E’s Electric Preliminary Statement Part HK.3 Nuclear Regulatory Commission Rulemaking Balancing Account (NRCRBA) This account is used for recovery of actual expenses for complying with existing, emerging or evolving NRC regulations and directives. These costs include but are not limited to, the following four major NRC rulemaking processes currently in progress:

Fukushima Daiichi Rulemaking, Cyber-Security Rulemaking, Emergency Planning 2 Hyperlink at: https://www.pge.com/tariffs/assets/pdf/tariffbook/ELEC_PRELIM_DB.pdf. 3 Hyperlink at: https://www.pge.com/tariffs/assets/pdf/tariffbook/ELEC_PRELIM_HK.pdf.

Attachment CAC Chair Report Item 10B
Rulemaking, and the new National Fire Protection Standard (NFPA) 805 Rulemaking.

Detailed entries can be found in PG&E’s Electric Preliminary Statement Part GM.4 Department of Energy Litigation Balancing Account (DOELBA) This account tracks and records for customers of any proceeds, net of costs, from PG&E’s lawsuit against the Department of Energy (DOE) filed in the Federal Court of Claims on January 22, 2004, regarding the DOE’s breach of spent fuel contracts and any additional claims for reimbursement that PG&E may have against DOE arising out of or related to spent fuel contracts. This account ensures the proper crediting and allocation of proceeds and costs for the benefit of customers as determined by the Commission between the Diablo Canyon and Humboldt Bay nuclear power plants. The DOELBA will expire after litigation is completed, proceeds have been received, and the Commission has authorized disposition of the balance. Amounts get transferred to PABA or NDAM as authorized by the Commission. Detailed entries can be found in PG&E’s Electric Preliminary Statement Part DZ.5
Additional mechanisms related to costs for extend operations of DCPP in accordance with SB 846 were proposed as part of PG&E’s Advice Letter 6870-E and Supplemental Advice Letter 6870-E-A, currently pending disposition from the Commission. 4 Hyperlink at: https://www.pge.com/tariffs/assets/pdf/tariffbook/ELEC_PRELIM_GM.pdf 5 Hyperlink at: https://www.pge.com/tariffs/assets/pdf/tariffbook/ELEC_PRELIM_DZ.pdf Attachment CAC Chair Report Item 10B

PACIFIC GAS AND ELECTRIC COMPANY
Diablo Canyon Power Plant Operations Extension OIR
Rulemaking 23-01-007
Data Response
PG&E Data Request No.: CalCCA_001-Q002
PG&E File Name: DiabloCanyonPowerPlantOperationsExtensionOIR_DR_CalCCA_001-Q002 Request Date: May 5, 2023 Requester DR No.: 001
Date Sent: May 19, 2023 Requesting Party: California Community Choice Association
PG&E Witness: Ryan Stanley Requester: Nikhil Vijaykar
QUESTION 002
Please identify all rate mechanisms currently relied on by PG&E to recover any costs related to Diablo Canyon and describe the costs included in each mechanism.

ANSWER 002
PG&E currently recovers costs associated with Diablo Canyon through two nonbypassable charges:
• Power Charge Indifferent Adjustment (PCIA) rates
• Nuclear Decommissioning rates
PCIA revenues are credited to the Portfolio Allocation Balancing Account (PABA).

Nuclear Decommissioning revenues are credited to the Nuclear Decommissioning Adjustment Mechanism (NDAM). Please see PG&E’s response to Question 1 of this data request for further details on the activities recovered within PABA and NDAM, as well as other accounts transferred to PABA and NDAM for cost recovery.

Attachment CAC Chair Report Item 10B

PACIFIC GAS AND ELECTRIC COMPANY
Diablo Canyon Power Plant Operations Extension OIR
Rulemaking 23-01-007
Data Response
PG&E Data Request No.: CalCCA_001-Q004
PG&E File Name: DiabloCanyonPowerPlantOperationsExtensionOIR_DR_CalCCA_001-Q004 Request Date: May 5, 2023 Requester DR No.: 001
Date Sent: May 19, 2023 Requesting Party: California Community Choice Association
PG&E Witness: Brian Ketelsen Requester: Nikhil Vijaykar QUESTION 004
Please confirm that PG&E’s 2023 GRC assumes the Diablo Canyon Power Plant is retired in 2024 (Unit 1) and 2025 (Unit 2). If not confirmed, please explain.

ANSWER 004
PG&E objects to this data request as irrelevant and outside the scope of this proceeding. Subject to and without waiving that objection, PG&E confirms that PG&E’s 2023 GRC assumes DCPP is retired in 2024 (Unit 1) and 2025 (Unit 2).

Attachment CAC Chair Report Item 10B

PACIFIC GAS AND ELECTRIC COMPANY
Diablo Canyon Power Plant Operations Extension OIR
Rulemaking 23-01-007
Data Response
PG&E Data Request No.: CalCCA_001-Q005
PG&E File Name: DiabloCanyonPowerPlantOperationsExtensionOIR_DR_CalCCA_001-Q005 Request Date: May 5, 2023 Requester DR No.: 001
Date Sent: May 19, 2023 Requesting Party: California Community Choice Association
PG&E Witness: Requester: Nikhil Vijaykar
QUESTION 005
Please quantify all common costs by category allocated to Diablo Canyon Power Plant revenue requirement in 2023, 2024, 2025, and 2026 as included in PG&E’s February Update of its 2023 GRC. For each category, explain the basis for the total common costs and the method used to allocate costs to Diablo Canyon Power Plant.

ANSWER 005
PG&E objects to this data request on grounds that it is irrelevant and outside the scope of this proceeding.

Attachment CAC Chair Report Item 10B

PACIFIC GAS AND ELECTRIC COMPANY
Diablo Canyon Power Plant Operations Extension OIR
Rulemaking 23-01-007
Data Response
PG&E Data Request No.: CalCCA_001-Q006
PG&E File Name: DiabloCanyonPowerPlantOperationsExtensionOIR_DR_CalCCA_001-Q006 Request Date: May 5, 2023 Requester DR No.: 001
Date Sent: May 19, 2023 Requesting Party: California Community Choice Association
PG&E Witness: Requester: Nikhil Vijaykar
QUESTION 006
Please explain whether the common costs identified in the previous request allocated to Diablo Canyon Power Plant prior to its retirement are assumed to be reallocated among other resources and/or departments after Diablo Canyon Power Plant retirement.

ANSWER 006
PG&E objects to this data request on grounds that it is irrelevant and outside the scope of this proceeding.

Attachment CAC Chair Report Item 10B

PACIFIC GAS AND ELECTRIC COMPANY
Diablo Canyon Power Plant Operations Extension OIR
Rulemaking 23-01-007
Data Response
PG&E Data Request No.: CalCCA_001-Q007
PG&E File Name: DiabloCanyonPowerPlantOperationsExtensionOIR_DR_CalCCA_001-Q007 Request Date: May 5, 2023 Requester DR No.: 001
Date Sent: May 19, 2023 Requesting Party: California Community Choice Association
PG&E Witness: Requester: Nikhil Vijaykar
QUESTION 007
Please explain whether PG&E assumed a reduction in overall common costs through 2026 due to Diablo Canyon Power Plant retirement. If yes, please quantify the reduction by year and by category. If no, please explain why not.

ANSWER 007
PG&E objects to this data request as irrelevant and outside the scope of this proceeding.

Attachment CAC Chair Report Item 10B

PACIFIC GAS AND ELECTRIC COMPANY
Diablo Canyon Power Plant Operations Extension OIR
Rulemaking 23-01-007
Data Response
PG&E Data Request No.: CalCCA_001-Q008
PG&E File Name: DiabloCanyonPowerPlantOperationsExtensionOIR_DR_CalCCA_001-Q008 Request Date: May 5, 2023 Requester DR No.: 001
Date Sent: May 19, 2023 Requesting Party: California Community Choice Association
PG&E Witness: Requester: Nikhil Vijaykar
QUESTION 008
Please explain whether continued operation of Diablo Canyon Power Plant will cause PG&E common costs to be higher than projected in 2025 and 2026 relative to the amount assumed in PG&E’s GRC. If yes, please quantify the incremental common costs by year and category. If not, please explain.

ANSWER 008
PG&E objects to this data request on grounds that PG&E’s GRC costs are irrelevant and outside the scope of this proceeding.

Notwithstanding this objection, PG&E’s May 19, 2023, Testimony in Rulemaking (R.) 23-01-007, Table 2, presents cost forecasts through 2030 that include accounting categories adopted by the Electric Utility Cost Group (EUCG). The “Support Services” line item includes costs for organizations outside of DCPP such as Information Technology, Insurance, Legal, Finance, Executive Leadership, Communications, Safety and Health, Procurement, and Human Resources.

These organizations have separate GRC chapters and are not included in the Nuclear chapter in PG&E’s most recent GRC Application, Application 21-06-021 and therefore could be considered common costs supporting Diablo Canyon.

Of note, the EUCG cost presentation in PG&E’s May 19, 2023, Testimony does not capture items such as property taxes, depreciation, interest expense, and revenues.

Attachment CAC Chair Report Item 10B
Agenda Item 14: Update on Planning for Net Billing Tariff (NBT) (Informational Item) Comments submitted from a technical expert on the CAC who is a homeowner with solar panels Some background:

NEM 3 has been in effect since April 14th, 2023 and if you applied for a system prior to this, it is still technically under NEM2 -- unless you add more solar panels, at which time utilities (under the direction of the CA PUC) can now push you to NEM3. The PUC made a request to various community organizations such as the Sierra Club, Grid Alternatives, and NDRC. Their response can be found here: https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K043/500043682.PDF Many of these concerns still exist with the PUC's NBT decision. Now we are changing the NEM structure again and I as a rooftop solar owner, community member, and consumer, would like to know how this can possibly be good for me.

Mission of EBCE/Ava Community Energy:

It appears to me that EBCE / Ava Community Energy's "...mission is to reinvest profits directly into East Bay communities creating local green energy jobs and clean power projects", is counterproductive to rooftop solar, and the organization is more inclined to build renewable infrastructure, profiting through investments in solar and wind farms. How can we call this a community organization when it is using the very dollars it accrues through electricity subsidized by rooftop solar production, to sell it back to these same rooftop solar producers at night at consumer pricing?
Incentives for battery storage:

Here is the url for EBCE's battery incentive which mentions a $500 incentive for battery storage.: https://ebce.org/resilient-home/
They are partnered with Sunrun, which when I called to ask if I can add a battery system to my solar PV system, twice said that they could do it and would call me back, but then never did.

From this experience, I suspect that they are not very interested in selling just battery systems.

Cost analysis using payback period:

The payback period for a solar system with no battery storage doubles with NEM 3.0; going from 5-6 years for NEM 2.0 to a decade for NEM 3 (albeit from a battery storage provider): https://www.fortresspower.com/nem3-why-is-battery-storage-so-important/#:~:text=NEM%202.0%20had%20a%20solar,of%20savings%20under%20NEM%203.0.

This is also corroborated from a non-biased site: https://www.energysage.com/blog/net-metering-3-0/ However, lower Solar PV pricing and rising electric rates can change this payback period. Until the various utilities decide on how to implement NBT, we cannot calculate how this would impact the payback period.

Conflict to consumers concerning EV vehicles and adding solar PV:

In the meantime, EBCE has pushed for folks to move to electric cars, which is a great business decision in terms of profits, as they would sell more electricity, and would push most solar PV owners into the import mode for electricity.

Profits over community:

I understand the need for EBCE / Ava Community Energy to prioritize profits, but the organization is supposed to be a green alternative, something that puts community above profits: https://ebce.org/about/
Conclusion:

The current trend for NEM seems counterintuitive in motivating homeowners to add rooftop solar (and wind) installations, and pushing California further away from both decarbonization and a future micro-grid resiliency model.

Attachment CAC Chair Report Item 10C
BTW - (this is more of a question than a statement...) I am still confused as to the Time of Use Cost being the NEM 3.0 platform. You asked a great question about PV homeowners exporting at a wholesale lower rate, and then paying a higher consumer rate for importing electricity. Ms.

Kelly's answer was confusing to me. I am also concerned about how grandfathering would work.

Can you please ask her to elaborate on this as well?
Attachment CAC Chair Report Item 10C
Staff Report Item 11
Staff Report Item 11
TO: East Bay Community Energy Board of Directors
FROM: Alex DiGiorgio, Public Engagement Manager
SUBJECT: Inclusion of New Communities: City of Lathrop (Action Item) DATE: September 20, 2023
__________________________________________________________________ Recommendations
Receive staff report and analysis on including the City of Lathrop within EBCE’s service area and take the following actions:

A) Adopt a Resolution to authorize the City of Lathrop to join the EBCE as a member agency and signatory to the JPA Agreement, with customer enrollments to begin in 2025, and to direct staff to update Exhibit A (“List of Parties”), Exhibit B (“Annual Energy Use”), and Exhibit C (“Voting Shares Vote”) of EBCE’s Joint Powers Agreement to reflect the inclusion of Lathrop.

B) Adopt a Resolution to authorize staff to update EBCE’s Implementation Plan to reflect the inclusion of the City of Lathrop, and to submit the updated Implementation Plan to the California Public Utilities Commission (CPUC) before the end of calendar year 2023.

Background and Discussion
As a mission-driven public agency, EBCE strives to reduce energy-related greenhouse gas (GHG) emissions by providing access to renewable energy at competitive rates while pioneering innovative programs and policies. To the extent EBCE retains and expands its customer base, it can accelerate the achievement of this mission.

Moreover, by including new communities within its service area, EBCE can cultivate a more demographically diverse customer base; and more generally advance sustainable development, environmental justice, and energy democracy throughout neighboring communities in California.

Staff Report Item 11
New Community Inclusion: Requirements, Timing, Process
Section 3.1 of EBCE’s Joint Powers Authority (JPA) Agreement refers to the “Addition of Parties,” and provides for the possibility of including new cities and/or counties within the JPA and its corresponding service area with updates to the JPA Agreement’s Exhibits.

Requirements: New community inclusion process and conditions of membership In order to join EBCE, the following legal and procedural requirements must be met:
1) the governing body of the prospective jurisdiction (i.e., the City Council) must pass a Resolution requesting to join EBCE and agreeing to become a signatory of the EBCE JPA Agreement; and pass an ordinance to implement a community choice aggregation program pursuant to Public Utilities Code Section 366.2; 2) EBCE’s Board must pass a Resolution authorizing the addition of the prospective jurisdiction as a new member and directing staff to update the JPA Agreement Exhibits; and 3) finally, EBCE must submit an updated Implementation Plan to the California Public Utilities Commission (CPUC) reflecting the membership of the new jurisdiction(s) within EBCE’s JPA.

The Lathrop City Council has already adopted the required Resolution agreeing to become a signatory to EBCE’s JPA Agreement and join EBCE; and it has passed the required two readings of a corresponding ordinance pursuant to Public Utilities Code Section 366.2 (please see attachments). The next step in Lathrop’s EBCE membership process is for the EBCE Board of Directors to adopt the proposed Resolution adding Lathrop to the JPA Agreement to add the City to EBCE’s membership, with customer enrollments to begin in 2025.

Section 3.1 of the JPA Agreement also provides for the satisfaction of other “additional conditions” for JPA membership, including “membership payment” or “membership fee,” which are subject to the discretion of EBCE’s Board. To date, the EBCE Board has not imposed such conditions on membership for new parties.

Lathrop’s elected leaders, City staff, and community members expect the City to be able to join EBCE’s JPA and participate in its governance under the same conditions as all current members. If these expectations are not met, it could lead Lathrop and/or future, prospective new member-jurisdictions in San Joaquin County or elsewhere to become less interested in joining EBCE. For these reasons, the Board is encouraged to proceed cautiously when considering conditions on new membership.

Once Lathrop has joined EBCE and its membership is certified by the CPUC, the City will be entitled to appoint a member of the City Council to serve as a member of the EBCE Board of Directors.

Staff Report Item 11
Requirements: Update JPA Exhibits A, B, & C
To implement the addition of Lathrop as a signatory and member of EBCE, the Board must approve updates to JPA Exhibits A (“List of Parties”); B (“Annual Energy Use”); and C (“Voting Shares”). Section 1.3 of the JPA Agreement provides that Exhibits A, B, and C may be revised upon the approval of the Board, without such revision constituting an amendment to the Agreement.

Exhibit A: “List of Parties”
Exhibit A lists the names of all jurisdictions which are members of EBCE’s Joint Powers Authority. Updating this list is straightforward; it simply involves adding the names of new member jurisdictions, pending the passage of a Board Resolution authorizing their JPA membership.

If the Board authorizes the membership of the City of Lathrop, the City’s name must be added to Exhibit A listed in alphabetical order (draft Attached).

Recommendation: Pending Board authorization to include the City of Lathrop, approve a motion to update Exhibit A to include the City among the “List of Parties.”
Exhibits B & C: “Annual Energy Use” & “Voting Shares Vote” Exhibits B and C list the annual energy use and the voting shares percentage of each member jurisdiction.

The Board voting procedures are set forth in Section 4.12 of the JPA Agreement.

According to Section 4.12.1, most Board decisions require a simple majority vote of all the Directors, with each jurisdiction having one equal vote.1 This procedure is referred to as a “Percentage Vote.” Additionally, Section 4.12.2 creates a “Voting Shares Vote” procedure, which may immediately follow an affirmative or a tied Percentage Vote if requested by three or more Directors. Under a Voting Shares Vote, each jurisdiction’s vote is essentially ‘weighted’ according to the size of its annual energy usage as compared to EBCE’s total annual energy (i.e., the collective, community-wide electricity demand within its borders). Historically, the Board has allowed new members to participate in ‘Voting Shares’ at their entry into EBCE, 1 Section 8.4 (“Amendment of this Agreement”) requires a two-thirds majority vote to amend the JPA itself; and a three-quarters vote to amend the voting provisions of Section 4.12.

Staff Report Item 11
rather than waiting until service to the new community is launched.2 Staff recommends the Board continue following this precedent, rather than risk alienating prospective new member-jurisdictions.

To date, the Voting Shares Vote provision of the JPA has been invoked exceedingly rarely—if ever. Indeed, no current EBCE staff member can recall an instance in which a vote of this type has occurred since EBCE’s formation in 2016.

Exhibit B sets forth the Annual Energy Use for each member-jurisdiction and EBCE’s Total Annual Energy use, for purposes of calculating members’ voting shares.

According to Section 1.1.23 of the JPA Agreement, “Annual Energy Use” for the first two years after EBCE’s launch date (December 1, 2016) is based on the annual electricity usage within each member’s respective jurisdiction. After two years, the JPA Agreement provides that Annual Energy Use is to be based on the annual electricity usage of accounts served by EBCE within the member’s jurisdiction. The Total Annual Energy is the sum of all the member jurisdictions’ Annual Energy Use.

The numbers in Exhibit B, together with the corresponding voting shares in Exhibit C, are supposed to be “adjusted annually as soon as reasonably practicable after January 1, but no later than March 1 each year subject to the approval of the Board.” At the time of EBCE’s formation, Exhibit B relied on 2014 PG&E load data. From 2019 to 2021, Exhibit B relied on 2018 PG&E load data.3 Since 2022, Exhibit B has relied on 2021 PG&E load data. Staff’s recommendation is to continue updating Exhibit B to reflect more current load data.

Specifically, EBCE staff recommends the Board update Exhibit B using the most recent PG&E load data available (i.e., from calendar year 2022).4 This provides an ‘apples-to-apples’ comparison for each member jurisdiction and does not preclude the Board from transitioning to EBCE’s post-enrollment load data once a full calendar year of EBCE usage becomes available for the cities of Stockton and Lathrop.5 2 When EBCE’s Board voted in 2019 to include the cities of Newark, Pleasanton, and Tracy; and the City of Stockton in 2022, it did so with the intention of allowing those new member-jurisdictions to participate in Voting Shares Votes based on their respective, citywide PG&E load data if/when such votes were to occur. Staff recommends the current EBCE Board follow this precedent. 3 From 2019 to 2021, Exhibit B relied on 2017 PG&E load data for the City of Newark. This was due to the lengthy time required to receive Newark’s requested 2018 load data from PG&E before the end of the 2019 calendar year.
4 The most recent PG&E load data available to EBCE is from calendar year 2022 for all jurisdictions, including the City of Lathrop.
5 The City of Stockton’s EBCE enrollment was delayed until January 1st, 2025, by CPUC Resolution E-5258.

Staff Report Item 11
Exhibit C sets forth the Voting Shares for EBCE member jurisdictions based on the corresponding Annual Energy Use and Total Annual Energy numbers provided in Exhibit B. If the Board decides to follow staff’s recommendation and provides direction to update Exhibit B using 2022 PG&E load data, Exhibit C will be adjusted accordingly to reflect the Voting Shares percentage of each member jurisdiction.

Recommendation: Update Exhibit B using 2022 PG&E load data for “Annual Energy Use” and “Total Energy Use,” for all current EBCE member-jurisdictions and the City of Lathrop. Update Exhibit C’s Voting Shares to correspond to updated numbers in Exhibit B. Consider updating Exhibits B and C again in 2024 using 2023 EBCE load data, when such data becomes available for EBCE member-jurisdictions.

Timing of new enrollments
In February of 2018, the CPUC passed Resolution E-4907, which delays the timeline by which California cities and counties may begin service with Community Choice Aggregation (CCA) agencies, like EBCE. In effect, cities and counties must wait a full calendar year between the time they form or join a CCA and when electricity customers within their borders may be enrolled in the CCA’s service. As a result, any jurisdiction that requests to begin service with EBCE by 2025, must complete the process of joining EBCE’s JPA by the end of calendar year 2023. Otherwise, enrollment with EBCE will not be possible until 2026 or later.

In April of 2023, the CPUC passed Resolution E-5258, which delayed the City of Stockton’s EBCE enrollment until January 1, 2025 (as well as the enrollments of other California cities that had been preparing to join CCAs in 2024). In brief, E-5258 retroactively applied additional conditions to CCAs that were planning to expand their service to new communities. These conditions focused on the timing of Resource Adequacy (“RA”) procurement and compliance requriements. EBCE has since adjusted its RA planning to account for these requriements and does not expect similar delays to impact the Lathrop’s EBCE enrollment should the Board approve the City’s JPA membership. As a result, pending the Board’s approval, Lathrop’s anticipated start of EBCE service would begin in January 2025, along with Stockton.

Process
Given the requirements and timing articulated above, EBCE staff has drafted a document outlining the process to join EBCE in time to enroll customers in 2025 Please see attached: “Steps to Joining East Bay Community Energy (EBCE).” Staff Report Item 11
The table below summarizes the City of Lathrop’s EBCE membership consideration and implementation processes:

Date Event
Oct ‘22-March ‘23 EBCE staff meet with Lathrop City staff at City’s invitation. EBCE staff continue to engage and communicate with City staff.

March-May 2023 City completes PG&E load data request forms/non-disclosure agreements. EBCE staff receives load data from PG&E.

July-August 2023 City Council passes Resolution, Ordinance to join EBCE (attached). City Manager executes JPA signature page (attached).

August 2023 EBCE conducts quantitative analysis to evaluate City's JPA membership request (attached).

Sept-Oct 2023 Earliest opportunities for EBCE Executive Committee (Exec Com), Board of Directors (BoD) and Community Advisory Committee (CAC) to consider quantitative analysis, inclusion request(s), and updates to JPA Agreement Exhibits A, B and C.

Oct-Dec 2023 Latest opportunities for EBCE Exec Com, BoD and CAC to consider quantitative analysis, inclusion request(s), and updates to JPA Agreement Exhibits A, B and C. Pending affirmative Board vote, staff updates Exhibits, and files updated Implementation Plan with CPUC. 2024 City of Lathrop entitled to a seat on EBCE’s Board of Directors; EBCE’s community outreach to new communities begins. Some EBCE programs may become available to Lathrop’s electricity customers (e.g. technical assistance w/energy resilience at critical municipal facilities). 2025 EBCE customer account enrollments begin in Lathrop (and Stockton) Fiscal Impact
The prospect of including a new city within EBCE’s Joint Powers Authority and service area—particularly one as rapidly growing and demographically diverse as Lathrop6— presents considerable financial implications for the Agency. For this reason, EBCE staff conducted a Quantitative Analysis (QA) using the City’s annual PG&E load data (from calendar year 2022) to evaluate the cost of service to this prospective new member jurisdiction. The results of this analysis are included as an attachment to this report.7
6 Lathrop has been identified by the State Department of Finance as one of the fastest growing cities in California: https://www.abc10.com/article/news/local/lathrop-growth-surge/103-245febe8-8751-4dea-9ce2-a3b6909095c6 & https://www.mantecabulletin.com/news/local-news/lathrop-californias-fastest-growing-city/ For an overview of Lathrop’s demographics and community profile for 2022/23, please refer here:
https://www.ci.lathrop.ca.us/sites/default/files/fileattachments/economic_development/page/10081/lathrop smart_community_profile_2022-23.pdf
7 Please refer to the attached “Presentation: Lathrop EBCE Membership: Quantitative Analysis” Staff Report Item 11
In short, the purpose of the QA was to help answer the following, basic question: Can EBCE include Lathrop within its growing service area, while providing the same level of service (or better) offered to current JPA member-jurisdictions and their communities? This level of service (also known as EBCE’s “value proposition”) offers customers competitive electricity rates with greater access to non-nuclear, carbon-free energy resources compared to standard PG&E service.8 Based on the results of the QA, staff is confident the answer to this question is ‘yes’.

According to the QA, the additional electric load of Lathrop in 2022 would have yielded approximately $1.77 million to EBCE’s net revenues, or an additional 1.6% to EBCE’s overall net position for that year. For 2025, the QA estimates the addition of Lathrop would contribute an additional 0.9% to EBCE’s overall net position. This would represent a small, but positive fiscal impact on EBCE and its existing communities and customer base. These additional net revenues could be used to supplement EBCE reserves, reduce retail rates, and/or expand funding for local renewable energy project development and energy-related programs (e.g., rebates for energy storage, electric vehicles and EV charging infrastructure).

The table below summarizes the findings of the QA:

Lathrop
2022
EBCE
2022
EBCE w/Lathrop
(and Stockton*)
2025
Accounts 7,300 642,400 766,000
Annual
Load(GWh/yr)
184 6,552 8,220
Peak Load
(MW)
49 1,636 2,237
Net
Position %
+1.6% +14.5% +8%
(+0.9% specifically
due to Lathrop)
Net
Position $
$1.77M $109.99M $197.99M
*Stockton’s EBCE enrollment was delayed until 2025 by CPUC Res E-5258 NOTES:
*Based on current overhead costs and 10-year average market values/forecasts; 8 EBCE currently offers customers a Bright Choice electric rate discount of 5% (previously 3%); and a Renewable 100 premium of ¼ a penny per kilowatt-hour (previously $0.01/kWh), compared to PG&E standard rates. Meanwhile, draft power content forecasts for 2022 (the most recent year for which data is available) indicate that EBCE’s non-nuclear carbon-free power will be more than 71% of total supply; while PG&E’s is expected to be approximately 47%. Please refer to the Emissions Overview developed for EBCE’s Board in June 2023:
https://cdn.sanity.io/files/pc49kbjr/production/0b9774744b54508e7a00353085d003d475fdabe1.pdf Staff Report Item 11
*Assumes 7% account opt out rate (slightly above EBCE’s current service area-wide opt out rate);
*Applies EBCE’s 2023 rates from 2023-24 budget development; *Data excludes ineligible loads (e.g. BART, Direct Access, Standby); *Uses 2022 PG&E load data for Lathrop;
Financial Stress Test: Modeling Wholesale Energy Market and Power Charge Indifference Adjustment (PCIA) Scenarios
To help the Board evaluate the financial risk associated with including the City of Lathrop, the QA included a “Financial Stress Test.” Among other things, this test measured the impact of two key cost variables: 1) wholesale energy market prices; and 2) the Power Charge Indifference Adjustment (PCIA).9 For example, a financial scenario could include a sustained wholesale energy price environment in which prices remain at EBCE’s median forecasted levels, while the PCIA increases dramatically (e.g., the PCIA climbing to the 5th percentile in cost,). Per the Board’s rate-setting policies, EBCE absorbs the cost of the PCIA to ensure its value proposition to customers (i.e., Bright Choice customers receive a 5% discount compared to PG&E’s standard rates; and Renewable 100 customers pay an additional ¼ cent per kilowatt-hour above PG&E rates). In other words, EBCE’s rate discount for Bright Choice customers, and the slight premium for Renewable 100 customers, remains consistent, despite any fluctuations in the PCIA. As such, dramatic increases in the PCIA can negatively impact EBCE’s financial position.

In these conditions, EBCE could still ‘break even’ (i.e., the Agency’s costs would be roughly equal to revenues during the sample year). Nevertheless, even in circumstances in which the cost to serve Lathrop could exceed the amount EBCE receives in retail rate revenues, EBCE’s financial position would very likely remain secure due to Lathrop’s relatively small size. In other words, the cost to serve Lathrop’s electricity load represents a fraction of EBCE’s current, overall costs.

Moreover, EBCE could take steps to mitigate the negative financial impacts of this scenario (e.g., by adjusting the Bright Choice discount from 5% to 4%).

EBCE staff also modeled a “worst case” scenario, defined as a sustained wholesale energy price environment in which costs vastly exceed forecasts (e.g., wholesale prices that are roughly 85% higher than forecasted, or in the 95th percentile).

To be clear, a scenario of this kind would not be a temporary ‘spike’ in energy costs due to a weather event like a cold snap or a heat wave; it would be a prolonged energy market disruption lasting approximately a year or more, and likely the result of catastrophic events (e.g. a war between energy-rich countries; or an 9 The PCIA is a charge to ensure that both PG&E customers and those who have left PG&E to purchase electricity from other providers (e.g., EBCE and other community choice aggregators) pay for the above market costs for electric generation resources that were procured by PG&E on their behalf.

Staff Report Item 11
unprecedented natural disaster that destroys or extensively damages vast critical infrastructure, like natural gas pipelines and/or electric transmission networks).

Under these conditions, EBCE could experience costs that exceed revenues by approximately 33%.10 Nevertheless, EBCE could still mitigate the financial impacts by 1) adjusting rates (e.g., reducing the Bright Choice discount/raising retail rates, and/or increasing the Renewable 100 premium); and 2) taking various cost-cutting measures (e.g., reducing the budgets of certain departments or programs).

While it is difficult to predict future energy market prices, or account for large-scale catastrophic events, the modeling and ‘stress tests’ routinely performed by EBCE staff provide a conservative lens through which to consider the City of Lathrop’s membership request. As mentioned above, staff’s goal was to determine whether EBCE could include Lathrop within its growing service area, while providing the same level of service offered to current JPA member-jurisdictions and their communities.

Based on the results of the QA, staff is confident EBCE can do so.

Qualitative Considerations
Lastly, in addition to considering the governance and financial implications of Lathrop’s EBCE membership, there are numerous qualitative benefits to consider as well. These include the following:
• Diversity, Equity, and Inclusion (DEI) - By expanding access to competitively priced renewable energy and related programs to growing, frontline communities in California’s Central Valley, EBCE can continue to advance the Agency’s goals around diversity, equity, and inclusion; • Environmental Justice – For a variety of systemic, economic, geographic, topographic, historical, and socio-political reasons, air pollution (among other forms of pollution) in Lathrop and the greater San Joaquin Valley region represents an urgent public health challenge.11 Pediatric asthma, in particular, is fairly widespread, affecting one in six children.12 By providing alternatives to fossil fuel-based energy resources in the building, transportation, and agricultural sectors, EBCE can help advance environmental justice and increase the quality of life for local communities;
10 The financial stress test assumes cost increase persist for an entire year. It estimates the cost of energy to be the percentage of additional load multiplied by the 2023-24 budgeted energy expenses. It does not include initial customer notification costs (e.g., four mailed enrollment notices, staff time, event fees, travel, etc.)
11 https://www.kvpr.org/local-news/2022-05-20/low-income-san-joaquin-valley-families-struggle-to-get-asthma-services-through-new-state-program 12 https://www.scientificamerican.com/article/climate-change-is-bad-news-for-california-children-with-asthma/ Staff Report Item 11
• Local Programs – Due to its location within a major highway corridor and a global hub for agriculture, industry, and light/medium/heavy-duty trucking and goods transport, Lathrop offers tremendous programmatic opportunities for EBCE’s transportation and building electrification endeavors. EBCE staff has identified multiple program areas where collaboration can begin right away; • Legislation and Political Influence – By welcoming new State Assembly/Senate districts and new Federal Congressional districts into EBCE’s service area, EBCE’s current communities and customers will benefit from greater representation in Sacramento and Washington DC through EBCE’s legislative and regulatory advocacy efforts;
• CCA Proliferation, Public Power, and Energy Democracy – When fast-growing, demographcially diverse cities, like Lathrop, join California’s CCA moment, they help catalyze public power and energy democracy throughout California by example. As with the cities of Tracy and Stockton, Lathrop’s EBCE membership would likely have a compounding positive impact by influencing neighboring Central Valley jurisdictions to consider CCA generally and/or EBCE membership specifically.

While difficult to measure, perhaps, these qualitative benefits and opportunities should not be underestimated. By including the City of Lathrop within its service area, EBCE can cultivate a more demographically diverse customer base, while advancing sustainable development, environmental justice, and energy democracy in communities throughout California and the United States.

Staff Recommendation

1. Receive update and analysis on including the City of Lathrop within EBCE’s service area;

2. Adopt a Resolution to approving the inclusion of the City of Lathrop within EBCE’s Joint Powers Authority and service area, with customer enrollments to begin in 2025 and direct staff to update Exhibit A (“List of Parties”), Exhibit B (“Annual Energy Use”), and Exhibit C (“Voting Shares Vote”).

3. Adopt a Resolution to authorize staff to update the Implementation Plan to reflect the inclusion of the City of Lathrop, and to submit the updated Implementation Plan to the California Public Utilities Commission (CPUC) before the end of calendar year 2023.

Attachments
Staff Report Item 11
A. Steps to Joining East Bay Community Energy;
B. Presentation: Quantitative Analysis - City of Lathrop EBCE Membership C. Presentation: CEO Report - Update re City of Lathrop - 7.19.23 Board mtg D. City of Lathrop’s signed staff report re EBCE membership E. City of Lathrop’s signed Resolution to join EBCE;
F. City of Lathrop’s signed Ordinance to join EBCE/implement CCA; G. EBCE Resolution to include the City of Lathrop as a JPA member; H. Current EBCE Joint Powers Agreement including Exhibits A, B and C; I. Proposed updates to JPA Exhibits A, B and C to include the City of Lathrop; J. EBCE Resolution authorizing EBCE staff to update EBCE’s Implementation Plan and submit it to the CPUC by end of calendar year 2023; K. City of Lathrop’s signed EBCE JPA signature page
L. Presentation: City of Lathrop EBCE membership and analysis Attachment Staff Report Item 11A
DRAFT - 2023
Steps to joining East Bay Community Energy (EBCE)
1) In-person meeting(s) with City staff and/or local elected officials; • Submit PG&E load data release forms (Forms 79-1030 & 79-1031); i. May take more than four months to receive accurate PG&E data; • Expedited timeline due to CPUC Res. E-4907;
2) Two or three presentations to Council:
• Informational/Discussion item;
• Vote #1: Ordinance & Resolution to join EBCE’s Joint Powers Authority (JPA) Agreement;
• Vote #2: Ordinance – Completed by August 2023 for 2025 enrollment; 3) EBCE staff conducts quantitative analysis;
• Evaluates cost of service to prospective new community (e.g., impact on EBCE’s revenues/net revenues and 2030 Clean Energy Goal); 4) EBCE Board and Community Advisory Committee review quantitative analysis and corresponding membership request(s); Board considers Resolution to include prospective new community;
5) Pending Board approval, EBCE updates Joint Powers Agreement and files amended Implementation Plan with CPUC before 12/31/23;
2024: Community outreach in new community;
• Elected official of new community entitled to seat on EBCE Board of Directors; 2025: EBCE enrollment of electricity accounts begins in new community City of Lathrop
August 30, 2023
Attachment Staff Report Item 11B
Summary Data
1 2022 MWh % 2022 MWh % 2022 MWh % 2022 MWh %
A1 945,379 14.4% 138,682 12.0% 10,212 5.5% 1,094,273 13.9% A10 1,035,366 15.8% 159,405 13.8% 19,441 10.6% 1,214,213 15.4% AGR 49,044 0.7% 1,462 0.1% 682 0.4% 51,189 0.6%
E19 1,316,623 20.1% 168,757 14.6% 55,779 30.3% 1,541,159 19.5% E20 541,679 8.3% 75,230 6.5% 54,487 29.6% 671,396 8.5%
RES 2,615,021 39.9% 609,383 52.8% 42,344 23.0% 3,266,747 41.4% LS 41,839 0.6% 97 0.0% 1,157 0.6% 43,092 0.5%
TC 7,070 0.1% 804 0.1% 134 0.1% 8,008 0.1%
Total 6,552,021 100% 1,153,821 100% 184,237 100% 7,890,078 100% EBCE Lathrop Combined Rate Class Stockton
Customer Count
Annual Load
(GWh)
Peak Load
(Wholesale MW)
Peak Date & Time
(Hour Starting)
EBCE 641,776 6,552 1,636 2022-09-06 16:00
Stockton 111,740 1,154 438 2022-09-06 16:00
Lathrop 7,339 184 49 2022-09-06 17:00
Combined 760,855 7,890 2,120 2022-09-06 16:00
Attachment Staff Report Item 11B
2022 Hourly Load
2 Attachment Staff Report Item 11B
3 2022 Daily Load
Attachment Staff Report Item 11B

CITY OF LATHROP, CA
¡ San Joaquin County: Between Tracy and Stockton
¡ Pop: 30,700 (2022)
¡ Incorporated:1989
¡ Major transit intersection: Interstate 5 and CA State Route 120 ¡ Top three employers: Tesla, UPS, Army & Air Force Exchange Service ¡ Energy-related opportunities
§ Growing electricity load, particularly commercial & industrial sectors § Central location relative to agriculture, logistics, and shipping hubs § Interstate transit corridors for EV fast charging; light, medium, and heavy-duty fleets; and other transportation electrification projects 1 Attachment Staff Report Item 11C
EBCE
enrolls new
customers
Community
Outreach
(with new
name and
brand)
EBCE
updates JPA
EBCE
considers
including
new
community
EBCE
conducts
analysis
Council
considers
joining JPA
Presentation
to City
Council
TIMELINE: LATHROP’S EBCE MEMBERSHIP
2 March 2023 July 2023 In Process December 2023 2024 2025 Attachment Staff Report Item 11C
3 Attachment Staff Report Item 11C
ITEM 5. 1

CITY MANAGER' S REPORT
JULY 10, 2023 CITY COUNCIL REGULAR MEETING
ITEM: PUBLIC HEARING ( PUBLISHED NOTICE) TO

CONSIDER ADOPTING AN ORDINANCE TO

IMPLEMENT A COMMUNITY CHOICE AGGREGATION

PROGRAM AND ADOPTING RESOLUTION TO

APPROVE A ) OINT POWERS AGREEMENT WITH EAST

BAY COMMUNITY ( EBCE) AUTHORITY TO PROVIDE

ELECTRIC SERVICES IN THE CITY OF LATHROP
RECOMMENDATION: City Council to Consider the Following:

1. Hold a Public Hearing; and

2. First Reading and Introduction of an Ordinance
to Implement a Community Choice
Aggregation Program to Provide Electric
Services in the City of Lathrop

3. Adopt Resolution to Approve a Joint Powers
Agreement with East Bay Community ( EBCE)
Authority to Provide Electric Services in the
City of Lathrop
SUMMARY:

On March 13, 2023 Council received a presentation from East Bay Community Energy EBCE) regarding the benefits of implementing a Community Choice Aggregation CCA) program. The potential benefits include lower electrical rates, local control and investment, and environmental sustainability.

Should Council want to proceed with the implementation of a CCA, the next step is to adopt an ordinance authorizing the City' s implementation of a CCA program through EBCE along with a resolution approving a Joint Powers Agreement ( JPA) to join the EBCE Joint Powers Authority.

BACKGROUND:

Community Choice Aggregation ( CCA) was created in California by AB 117 ( 2002) and are governed by the California Public Utilities Commission ( CPUC). CCAs are governmental entities formed by cities and counties to procure electricity for their residents, businesses, and municipal facilities. CCAs cannot be formed in the jurisdiction of a publicly owned electric utility ( POU) that provides electrical service, this includes the Lathrop Irrigation District ( LID) that provides electrical power within the River Islands Development.

CCA programs have several unique characteristics. When a CCA launches, investor-owned utility ( IOU) electricity customers in the designated service area are automatically opted- in to CCA service, and have to opt out to continue to be served by the IOU.
395 Attachment Staff Report Item 11D
CITY MANAGER' S REPORT PAGE 2
JULY 10, 2023 CITY COUNCIL REGULAR MEETING

PUBLIC HEARING ( PUBLISHED NOTICE) TO CONSIDER ADOPTING AN

ORDINANCE TO IMPLEMENT A COMMUNITY CHOICE AGGREGATION

PROGRAM AND ADOPTING RESOLUTION TO APPROVE A ) OINT POWERS

AGREEMENT WITH EAST BAY COMMUNITY ( EBCE) AUTHORITY TO PROVIDE

ELECTRIC SERVICES IN THE CITY OF LATHROP
For the City of Lathrop the IOU is Pacific Gas & Electric Co. ( PG& E). Once established, a CCA purchases power for its customers. While the CCA is responsible for procurement, the IOU still provides other services such as transmission, distribution, metering, billing, collection, and customer service. Currently there are 25 CCA programs serving more than 11 million customers in California.

EBCE made a presentation to City Council at its March 13, 2023 meeting regarding participation and implementation of the CCA program to provide alternate electric services to City consumers under a JPA. In 2018, the County of Alameda and 11 of its cities launched EBCE as a not- for- profit public agency that governs this Community Choice Energy service. The Joint Power Agency expanded in 2021. The cities currently served are: Albany, Berkeley, Dublin, Emeryville, Fremont, Hayward, Livermore, Newark, Oakland, Piedmont, Pleasanton, San Leandro, Tracy, and Union City. The unincorporated areas of Alameda County ( including Ashland, Castro Valley, Cherryland, Fairview, San Lorenzo, and Sunol) are also served by EBCE. The City of Stockton will begin EBCE service in 2025.

Section 366. 2 of the California Public Utilities Code requires that any agency seeking to implement a CCA in their jurisdiction must do so by ordinance. This item requests that the City Council adopt an ordinance authorizing the City of Lathrop' s implementation of a CCA program. The City Council must also adopt a resolution approving a joint powers agreement ( JPA) thereby authorizing the EBCE to act as the CCA on the City' s behalf.

The JPA contains provisions regarding as EBCE' s powers, governance structure, including voting allocations, its obligation to indemnify the members, and the process for withdrawing from the authority, along with other standard JPA terms. As a member of EBCE, the City will have a representative on the EBCE' s board of directors.

If approved by Council, the JPA would be updated to reference the City of Lathrop.

REASON FOR RECOMMENDATION:

Adopting the proposed ordinance and approving the JPA with EBCE has the potential to provide lower electrical rates, local control and investment, and environmental sustainability.
396 Attachment Staff Report Item 11D
CITY MANAGER' S REPORT PAGE 3
ULY 10, 2023 CITY COUNCIL REGULAR MEETING

PUBLIC HEARING ( PUBLISHED NOTICE) TO CONSIDER ADOPTING AN

ORDINANCE TO IMPLEMENT A COMMUNITY CHOICE AGGREGATION
PROGRAM AND ADOPTING RESOLUTION TO APPROVE A 70INT POWERS

AGREEMENT WITH EAST BAY COMMUNITY ( EBCE) AUTHORITY TO PROVIDE

ELECTRIC SERVICES IN THE CITY OF LATHROP
FISCAL IMPACT:

There is no direct fiscal impact associated with adopting an ordinance implementing a Community Choice Aggregation Program or approving a Joint Powers Agreement with the EBCE Authority to provide electric services to the City of Lathrop.

ATTACH M ENTS:

A. Ordinance to Implement a Community Choice Aggregation Program to Provide Electric Services in the City of Lathrop
B. Resolution to Approve a Joint Powers Agreement with East Bay Community EBCE) Authority to Provide Electric Services in the City of Lathrop C. ECBE Joint Powers of Agreement
397 Attachment Staff Report Item 11D
CITY MANAGER' S REPORT PAGE 4
ULY 10, 2023 CITY COUNCIL REGULAR MEETING

PUBLIC HEARING ( PUBLISHED NOTICE) TO CONSIDER ADOPTING AN

ORDINANCE TO IMPLEMENT A COMMUNITY CHOICE AGGREGATION

PROGRAM AND ADOPTING RESOLUTION TO APPROVE A JOINT POWERS

AGREEMENT WITH EAST BAY COMMUNITY ( EBCE) AUTHORITY TO PROVIDE

ELECTRIC SERVICES IN THE CITY OF LATHROP
APPROVALS:
23 Cari James Date
Finance Dir or
7- 5 - Zo23
Michael King Date
Assistant City Manager
Zp z.-- 3
Salvador Navarrete Date
City Attorney
7•5•23
Ste en J. Salvatore Date
City Manager
398 Attachment Staff Report Item 11D
RESOLUTION NO. 23- 5338

A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF LATHROP TO APPROVE A 70INT POWERS AGREEMENT WITH EAST BAY COMMUNITY

EBCE) AUTHORITY TO PROVIDE ELECTRIC SERVICES IN THE CITY OF

LATH RO P
WHEREAS, the City of Lathrop has an interest in achieving greater local involvement over the provision of electricity supply services, competitive electric rates, local control and investment, and environmental sustainability; and WHEREAS, Assembly Bill 117 codified as Public Utilities Code Section 366. 2 the Act"), authorizes any California city or county whose governing body so elects, to combine the electricity load of its residents and businesses in a community- wide electricity aggregation program known as Community Choice Aggregation ( CCA); and WHEREAS, The Act allows a CCA program to be carried out under a joint powers agreement entered into by entities that each have capacity to implement a CCA program individually. The joint powers agreement structure reduces the risks of implementing a CCA program by immunizing the financial assets of participants; and WHEREAS, on March 13, 2023 Council received a presentation from East Bay Community Energy ( EBCE) regarding the benefits of implementing a CCA program; and
WHEREAS, implementing a CCA program will likely provide multiple benefits to the residents, including lower electrical rates, local control and investment, and environmental sustainability; and
WHEREAS, Alameda County and cities in Alameda County have developed the EBCE Authority Joint Powers Agreement ( JPA) which creates the East Bay Community Energy Authority ( Authority) which will govern and operate the CCA program; and WHEREAS, the Authority provides alternate electric services to consumers under a JPA with Alameda County and the vast majority of all cities in that county; and
WHEREAS, The Authority is interested in providing potential services to the City of Lathrop; and
NOW, THEREFORE, BE IT RESOLVED, that the City Council of the City of Lathrop does hereby approve a Joint Powers Agreement with East Bay Community EBCE) Authority to provide electric services in the City of Lathrop.

Resolution No. 23- 5338
Attachment Staff Report Item 11E
The foregoing resolution was passed and adopted this 10t" day of July 2023, by the following vote of the City Council, to wit:

AYES: Akinjo, Diallo, Torres- O' Callaghan, and Dhaliwal NOES: None
ABSENT: Lazard
ABSTAIN: None
Sonny Dhaliwal, Mayor
ATTEST: APPROVED AS TO FORM:
resa Vargas, City Cler Salvador Navarrete, City Attorney Resolution No. 23- 5338
Attachment Staff Report Item 11E
ORDINANCE NO. 23- 447

AN ORDINANCE OF THE CITY COUNCIL OF THE CITY OF LATHROP TO

IMPLEMENT A COMMUNITY CHOICE AGGREGATION PROGRAM TO PROVIDE

ELECTRIC SERVICES IN THE CITY OF LATHROP
WHEREAS, The City of Lathrop has an interest in achieving greater local involvement over the provision of electricity supply services, competitive electric rates, local control and investment, and environmental sustainability; and WHEREAS, Assembly Bill 117 codified as Public Utilities Code Section 366. 2 the " Act"), authorizes any California city or county whose governing body so elects, to combine the electricity load of its residents and businesses in a community- wide electricity aggregation program known as Community Choice Aggregation ( CCA); and WHEREAS, The Act allows a CCA program to be carried out under a joint powers agreement entered into by entities that each have capacity to implement a CCA program individually. The joint powers agreement structure reduces the risks of implementing a CCA program by immunizing the financial assets of participants; and WHEREAS, implementing a CCA program will likely provide multiple benefits to the residents, including lower electrical rates, local control and investment, and environmental sustainability; and
WHEREAS, concurrent with the introduction of this ordinance, the City Council considered a resolution approving the East Bay Community Energy Authority Joint Powers Agreement; and
WHEREAS, proper notice of this public hearing was given to all respects as required by law; and
WHEREAS, the City Council has reviewed all written evidence and oral testimony presented to date.

NOW, THEREFORE, THE CITY COUNCIL OF THE CITY OF LATHROP DOES HEREBY ORDAIN AS FOLLOWS:

Section 1 Findings.

Based upon the findings set forth hereinabove, the City Council elects to participate in, and approves the implementation of a Community Choice Aggregation program within the City of Lathrop' s jurisdiction by and through the East Bay Community Energy Authority.

This Ordinance is not intended to and shall not be construed or given effect in a manner that imposes upon the City or any ofFicer or employee thereof a mandatory duty of care toward persons and property within or without the city so as to provide a basis of civil liability for damages, except as otherwise imposed by law.

Ordinance No. 23- 447
Attachment Staff Report Item 11F
Section 2 Environmental.

The passage of this ordinance is not a project under the California Environmental Quality Act ( CEQA) because it does not involve any commitment to a specific project which may result in a potentially significant physical impact on the environment, as contemplated by Title 14, California Code of Regulations, Sections 15378, therefore, not subject to CEQA pursuant to CEQA Guidelines Section 15060.

Section 3. Severalbilitv
If any provisions of this Ordinance or application thereof to any person or circumstances is held invalid, such invalidity shall not effect other provisions or applications of the ordinance which can be given efFect without the invalid provision or application, and to this end the provisions of this Ordinance are severable. The City Council hereby declares that it would have adopted this Ordinance irrespective of the validity of any particular portions thereof.

Section 4. Effective Date
This Ordinance shall take legal effect and be in force thirty ( 30) days from and after the date of its passage.

Section 5. Pubilication
Within fifteen ( 15) days after its final passage, the City Clerk shall cause a copy of this Ordinance to be published in full accordance with Section 36933 of the Government Code.

THIS ORDINANCE was introduced at a regular meeting of the City Council of the City of Lathrop on the lOt'' day of July 2023, and was PASSED AND ADOPTED at a regular meeting of the City Council of the City of Lathrop on the 14th day of August, 2023 by the following vote, to wit:

AYES: Diallo, Lazard, Torres- O' Callaghan, and Akinjo
NOES: None
ABSENT: Dhaliwal
ABSTAIN: None t
U
Paul Akinjo, ? ce Mayor
ATTEST: APPROVED AS TO FORM:
s
eresa Vargas, Cit: CI Salvador Navarrete, City Attorney Ordinance No. 2- 447
Attachment Staff Report Item 11F

STATE OF CALIFORNIA
COUNTY OF SAN JOAQUIN ss.

CITY OF LATHROP
I, Teresa Vargas, City Clerk of the City of Lathrop, California, do hereby certify that the foregoing Ordinance No. 23- 447 was duly and regularly introduced at a regular meeting of the City Council on the lOt'' day of July 2023, and that thereafter said Ordinance was duly and regularly adopted at a regular meeting of the City Council on the 14t" day of August 2023, by the following vote, to wit:

AYES: Diallo, Lazard, Torres- O' Callaghan, and Akinjo
NOES: None
ABSENT: Dhaliwal
ABSTAIN: None
This Ordinance was duly published in accordance with State Law ( G. C. 40806).

I hereby certify that the foregoing is the original of Ordinance No. 23- 447 duly and adopted by the City of Lathrop City Council at its regular meeting held August 14, 2023, and that the Summary of the Ordinance was published on August 1, 2023, and Full Reading on August 18, 2023 in the Manteca Bulletin Newspaper.

IN WITNESS WHEREOF, I have hereunto set my hand and affixed the official seal of the City of Lathrop, California, this 18th day of August 2023.

ERESA VARGAS, M C

CITY CLERK
SEAL)
Ordinance No. 23- 447
Attachment Staff Report Item 11F
Attachment Staff Report Item 11G
RESOLUTION NO. XX

A RESOLUTION OF THE BOARD OF DIRECTORS

OF THE EAST BAY COMMUNITY ENERGY AUTHORITY AUTHORIZING THE CITY OF

LATHROP TO BECOME A PARTY TO THE JOINT POWERS AGREEMENT AND MEMBER

OF EBCE

THE BOARD OF DIRECTORS OF THE EAST BAY COMMUNITY ENERGY AUTHORITY DOES HEREBY FIND, RESOLVE AND ORDER AS FOLLOWS:

WHEREAS, on September 24, 2002, the Governor of California signed into law Assembly Bill 117 (Stat. 2002, Ch. 838; see California Public Utilities Code section 366.2; hereinafter referred to as the “Act”), which authorizes any California city or county, whose governing body so elects, to combine the electricity load of its residents and businesses in a community-wide electricity aggregation program known as Community Choice Aggregation (“CCA”); and
WHEREAS, the Act expressly authorizes participation in a CCA program through a joint powers agency; and on December 1, 2016, the East Bay Community Energy Authority (“EBCE” or “the Agency”) was formed under the Joint Exercise of Power Act, California Government Code sections 6500 et seq., among the County of Alameda, and the Cities of Albany, Berkeley, Dublin, Emeryville, Fremont, Hayward, Livermore, Piedmont, Oakland, San Leandro, and Union City to study, promote, develop, conduct, operate, and manage energy and energy-related climate change programs in all of the member jurisdictions; and
WHEREAS, The East Bay Community Energy Authority (“EBCE”) was formed as a community choice aggregation agency (“CCA”) on December 1, 2016, Under the Joint Exercise of Power Act, California Government Code sections 6500 et seq., among the County of Alameda, and the Cities of Albany, Berkeley, Dublin, Emeryville, Fremont, Hayward, Livermore, Piedmont, Oakland, San Leandro, and Union City to study, promote, develop, conduct, operate, and manage energy-related climate change programs in all of the member jurisdictions. The cities of Newark and Pleasanton, located in Alameda County, along with the City of Tracy, located in San Joaquin County, were added as members of EBCE and parties to the JPA in March of 2020. The city of Stockton, located in San Joaquin County was added as a member of EBCE and party to the JPA in September of 2022; and
WHEREAS, on November 8, 2017, the California Public Utilities Commission (“CPUC”) certified the “Implementation Plan” of EBCE, confirming EBCE’s compliance with the requirements of the Act; and
WHEREAS, Section 3.1 of the EBCE Joint Powers Agreement (“Agreement”) sets forth the procedures for the addition of new member jurisdictions; and Attachment Staff Report Item 11G
WHEREAS, on November 20, 2019, EBCE’s Board of Directors unanimously authorized the cities of Tracy, Pleasanton, and Newark to become new parties to the Agreement with EBCE service beginning in those jurisdictions in April 2021; and WHEREAS, on December 20, 2019, EBCE submitted an updated “Implementation Plan” to the CPUC reflecting the membership of the cities of Tracy, Pleasanton, and Newark to the Agreement and EBCE service area; and WHEREAS, on September 21, 2022, EBCE’s Board of Directors unanimously authorized the City of Stockton to become a new party to the Agreement with EBCE service anticipated to begin in April 2024; and
WHEREAS, on December 8, 2022, EBCE submitted an updated “Implementation Plan” to the CPUC reflecting the membership of the City of Stockton to the Agreement and EBCE service area; and
WHEREAS, including new member jurisdictions within EBCE’s Joint Powers Authority can benefit EBCE communities, customers, and the general public by 1) expanding access to competitively-priced renewable energy, innovative programs and equitable policies; 2) achieving greater economies of scale while accelerating the reduction of greenhouse gas emissions; 3) enhancing EBCE’s financial strength through increased revenues and reserves; 4) diversifying the Agency’s service area while advancing environmental justice in historically marginalized communities; 5) empowering local stakeholders with more direct representation before State-level regulators and elected officials; and 6) inspiring more cities and counties to explore public power options in California and nationwide; and
WHEREAS, on July 10, 2023, through a unanimous vote of its City Council, the City of Lathrop expressed its intention of joining EBCE and participating in the Agency’s CCA program by passing a resolution to request membership in EBCE and introducing an ordinance to implement a CCA program as required by Public Utilities Code section 366.2; and the ordinance was formally adopted on August 14, 2023; and WHEREAS, EBCE conducted a quantitative analysis to examine the cost of service to the City of Lathrop, which indicated positive financial and environmental benefits from their membership to the prospective City as well as to EBCE’s current communities and customer base; and,
WHEREAS, per CPUC rules, prospective member jurisdictions must join EBCE before the end of calendar year 2023 to begin customer enrollments in EBCE’s service options by 2025; and
WHEREAS, Section 3.1 of the Agreement requires the Board of Directors to adopt a resolution authorizing the membership of additional member jurisdictions, and specifying the membership payment and conditions for membership, if any.

Attachment Staff Report Item 11G

NOW, THEREFORE, THE BOARD OF DIRECTORS OF THE EAST BAY COMMUNITY ENERGY AUTHORITY DOES HEREBY RESOLVE AS FOLLOWS:

Section 1. The City of Lathrop is hereby authorized to become a party to the Agreement and a member of EBCE, subject to the following conditions:
(a) The Community Choice Aggregation ordinance adopted by the City of Lathrop becoming effective.
(b) The execution of the Agreement by the duly authorized official of the City of Lathrop.

Section 2. Staff are hereby directed to revise Exhibits A, B, and C of the Agreement to include Lathrop as a member of EBCE and to provide updated energy load information. Revised Exhibits are attached to this Resolution and incorporated herein.

Section 3. The CEO and General Counsel are hereby authorized to take all necessary implementing actions to effectuate this Resolution, including but not limited to filing a revised Agreement with the Secretary of State and applicable Local Agency Formation Commissions, as required by state law.

ADOPTED AND APPROVED this 20th day of September, 2023.

Elisa Márquez, Chair
ATTEST:

Adrian Bankhead, Secretary
East Bay Community Energy Authority
- Joint Powers Agreement -
Effective December 1, 2016
As amended by Resolution No. 2018-23 dated June 20, 2018 and Resolution No. 2022-28 dated September 21, 2022
County of Alameda
City of Albany
City of Berkeley
City of Dublin
City of Emeryville
City of Fremont
City of Hayward
City of Livermore
City of Newark
City of Oakland
City of Piedmont
City of Pleasanton
City of San Leandro
City of Stockton
City of Tracy
City of Union City
Attachment Staff Report Item 11H
-1-

EAST BAY COMMUNITY ENERGY AUTHORITY

JOINT POWERS AGREEMENT
This Joint Powers Agreement (“Agreement”), effective as of December 1, 2016, is made and entered into pursuant to the provisions of Title 1, Division 7, Chapter 5, Article 1 (Section 6500 et seq.) of the California Government Code relating to the joint exercise of powers among the parties set forth in Exhibit A (“Parties”). The term “Parties” shall also include an incorporated municipality or county added to this Agreement in accordance with Section 3.1.

RECITALS

1. The Parties are either incorporated municipalities or counties sharing various powers under California law, including but not limited to the power to purchase, supply, and aggregate electricity for themselves and their inhabitants.

2. In 2006, the State Legislature adopted AB 32, the Global Warming Solutions Act, which mandates a reduction in greenhouse gas emissions in 2020 to 1990 levels. The California Air Resources Board is promulgating regulations to implement AB 32 which will require local government to develop programs to reduce greenhouse gas emissions.

3. The purposes for the Initial Participants (as such term is defined in Section 1.1.16 below) entering into this Agreement include securing electrical energy supply for customers in participating jurisdictions, addressing climate change by reducing energy related greenhouse gas emissions, promoting electrical rate price stability, and fostering local economic benefits such as jobs creation, community energy programs and local power development. It is the intent of this Agreement to promote the development and use of a wide range of renewable energy sources and energy efficiency programs, including but not limited to State, regional and local solar and wind energy production.

4. The Parties desire to establish a separate public agency, known as the East Bay Community Energy Authority (“Authority”), under the provisions of the Joint Exercise of Powers Act of the State of California (Government Code Section 6500 et seq.) (“Act”) in order to collectively study, promote, develop, conduct, operate, and manage energy programs.

5. The Initial Participants have each adopted an ordinance electing to implement through the Authority a Community Choice Aggregation program pursuant to California Public Utilities Code Section 366.2 (“CCA Program”). The first priority of the Authority will be the consideration of those actions necessary to implement the CCA Program.

6. By establishing the Authority, the Parties seek to:
(a) Provide electricity rates that are lower or competitive with those offered by PG&E for similar products;
Attachment Staff Report Item 11H
-2-
(b) Offer differentiated energy options (e.g. 33% or 50% qualified renewable) for default service, and a 100% renewable content option in which customers may “opt-up” and voluntarily participate;
(c) Develop an electric supply portfolio with a lower greenhouse gas (GHG) intensity than PG&E, and one that supports the achievement of the parties’ greenhouse gas reduction goals and the comparable goals of all participating jurisdictions; (d) Establish an energy portfolio that prioritizes the use and development of local renewable resources and minimizes the use of unbundled renewable energy credits; (e) Promote an energy portfolio that incorporates energy efficiency and demand response programs and has aggressive reduced consumption goals;
(f) Demonstrate quantifiable economic benefits to the region (e.g. union and prevailing wage jobs, local workforce development, new energy programs, and increased local energy investments);
(g) Recognize the value of workers in existing jobs that support the energy infrastructure of Alameda County and Northern California. The Authority, as a leader in the shift to a clean energy, commits to ensuring it will take steps to minimize any adverse impacts to these workers to ensure a “just transition” to the new clean energy economy;
(h) Deliver clean energy programs and projects using a stable, skilled workforce through such mechanisms as project labor agreements, or other workforce programs that are cost effective, designed to avoid work stoppages, and ensure quality; (i) Promote personal and community ownership of renewable resources, spurring equitable economic development and increased resilience, especially in low income communities;
(j) Provide and manage lower cost energy supplies in a manner that provides cost savings to low-income households and promotes public health in areas impacted by energy production; and
(k) Create an administering agency that is financially sustainable, responsive to regional priorities, well managed, and a leader in fair and equitable treatment of employees through adopting appropriate best practices employment policies, including, but not limited to, promoting efficient consideration of petitions to unionize, and providing appropriate wages and benefits.

Attachment Staff Report Item 11H
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AGREEMENT
NOW, THEREFORE, in consideration of the mutual promises, covenants, and conditions hereinafter set forth, it is agreed by and among the Parties as follows:

ARTICLE 1

CONTRACT DOCUMENTS

1.1 Definitions. Capitalized terms used in the Agreement shall have the meanings specified below, unless the context requires otherwise.

1.1.1 “AB 117” means Assembly Bill 117 (Stat. 2002, ch. 838, codified at Public Utilities Code Section 366.2), which created CCA.

1.1.2 “Act” means the Joint Exercise of Powers Act of the State of California (Government Code Section 6500 et seq.)

1.1.3 “Agreement” means this Joint Powers Agreement.

1.1.4 “Annual Energy Use” has the meaning given in Section 1.1.23.

1.1.5 “Authority” means the East Bay Community Energy Authority established pursuant to this Joint Powers Agreement.

1.1.6 “Authority Document(s)” means document(s) duly adopted by the Board by resolution or motion implementing the powers, functions and activities of the Authority, including but not limited to the Operating Rules and Regulations, the annual budget, and plans and policies.

1.1.7 “Board” means the Board of Directors of the Authority.

1.1.8 “Community Choice Aggregation” or “CCA” means an electric service option available to cities and counties pursuant to Public Utilities Code Section 366.2.

1.1.9 “CCA Program” means the Authority’s program relating to CCA that is principally described in Sections 2.4 and 5.1.

1.1.10 “Days” shall mean calendar days unless otherwise specified by this Agreement.

1.1.11 “Director” means a member of the Board of Directors representing a Party, including an alternate Director.

1.1.12 “Effective Date” means the date on which this Agreement shall become effective and the East Bay Community Energy Authority shall exist as a separate public agency, as further described in Section 2.1.

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1.1.13 “Ex Officio Board Member” means a non-voting member of the Board of Directors as described in Section 4.2.2. The Ex Officio Board Member may not serve on the Executive Committee of the Board or participate in closed session meetings of the Board.

1.1.14 “Implementation Plan” means the plan generally described in Section

5.1.2 of this Agreement that is required under Public Utilities Code Section 366.2 to be filed with the California Public Utilities Commission for the purpose of describing a proposed CCA Program.

1.1.15 “Initial Costs” means all costs incurred by the Authority relating to the establishment and initial operation of the Authority, such as the hiring of a Chief Executive Officer and any administrative staff, any required accounting, administrative, technical and legal services in support of the Authority’s initial formation activities or in support of the negotiation, preparation and approval of power purchase agreements. The Board shall determine the termination date for Initial Costs.

1.1.16 “Initial Participants” means, for the purpose of this Agreement the County of Alameda, the Cities of Albany, Berkeley, Emeryville, Oakland, Piedmont, San Leandro, Hayward, Union City, Fremont, Dublin, and Livermore.

1.1.17 “Operating Rules and Regulations” means the rules, regulations, policies, bylaws and procedures governing the operation of the Authority.

1.1.18 “Parties” means, collectively, the signatories to this Agreement that have satisfied the conditions in Sections 2.2 or 3.1 such that it is considered a member of the Authority.

1.1.19 “Party” means, singularly, a signatory to this Agreement that has satisfied the conditions in Sections 2.2 or 3.1 such that it is considered a member of the Authority.

1.1.20 “Percentage Vote” means a vote taken by the Board pursuant to Section

4.12.1 that is based on each Party having one equal vote.

1.1.21 “Total Annual Energy” has the meaning given in Section 1.1.23.

1.1.22 “Voting Shares Vote” means a vote taken by the Board pursuant to Section 4.12.2 that is based on the voting shares of each Party described in Section 1.1.23 and set forth in Exhibit C to this Agreement. A Voting Shares vote cannot take place on a matter unless the matter first receives an affirmative or tie Percentage Vote in the manner required by Section

4.12.1 and three or more Directors immediately thereafter request such vote.

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1.1.23 “Voting Shares Formula” means the weight applied to a Voting Shares Vote and is determined by the following formula:
(Annual Energy Use/Total Annual Energy) multiplied by 100, where (a) “Annual Energy Use” means (i) with respect to the first two years following the Effective Date, the annual electricity usage, expressed in kilowatt hours (“kWh”), within the Party’s respective jurisdiction and (ii) with respect to the period after the second anniversary of the Effective Date, the annual electricity usage, expressed in kWh, of accounts within a Party’s respective jurisdiction that are served by the Authority and (b) “Total Annual Energy” means the sum of all Parties’ Annual Energy Use.

The initial values for Annual Energy use are designated in Exhibit B and the initial voting shares are designated in Exhibit C. Both Exhibits B and C shall be adjusted annually as soon as reasonably practicable after January 1, but no later than March 1 of each year subject to the approval of the Board.

1.2 Documents Included. This Agreement consists of this document and the following exhibits, all of which are hereby incorporated into this Agreement.

Exhibit A: List of the Parties
Exhibit B: Annual Energy Use
Exhibit C: Voting Shares

1.3 Revision of Exhibits. The Parties agree that Exhibits A, B and C to this Agreement describe certain administrative matters that may be revised upon the approval of the Board, without such revision constituting an amendment to this Agreement, as described in Section 8.4. The Authority shall provide written notice to the Parties of the revision of any such exhibit.

ARTICLE 2

FORMATION OF EAST BAY COMMUNITY ENERGY AUTHORITY

2.1 Effective Date and Term. This Agreement shall become effective and East Bay Community Energy Authority shall exist as a separate public agency on December 1, 2016, provided that this Agreement is executed on or prior to such date by at least three Initial Participants after the adoption of the ordinances required by Public Utilities Code Section 366.2(c)(12). The Authority shall provide notice to the Parties of the Effective Date. The Authority shall continue to exist, and this Agreement shall be effective, until this Agreement is terminated in accordance with Section 7.3, subject to the rights of the Parties to withdraw from the Authority.

2.2 Initial Participants. Until December 31, 2016, all other Initial Participants may become a Party by executing this Agreement and delivering an executed copy of this Agreement and a copy of the adopted ordinance required by Public Utilities Code Section 366.2(c)(12) to the Authority. Additional conditions, described in Section 3.1, may apply (i) to either an Attachment Staff Report Item 11H
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incorporated municipality or county desiring to become a Party that is not an Initial Participant and (ii) to Initial Participants that have not executed and delivered this Agreement within the time period described above.

2.3 Formation. There is formed as of the Effective Date a public agency named the East Bay Community Energy Authority. Pursuant to Sections 6506 and 6507 of the Act, the Authority is a public agency separate from the Parties. The debts, liabilities or obligations of the Authority shall not be debts, liabilities or obligations of the individual Parties unless the governing board of a Party agrees in writing to assume any of the debts, liabilities or obligations of the Authority. A Party who has not agreed to assume an Authority debt, liability or obligation shall not be responsible in any way for such debt, liability or obligation even if a majority of the Parties agree to assume the debt, liability or obligation of the Authority. Notwithstanding Section 8.4 of this Agreement, this Section 2.3 may not be amended unless such amendment is approved by the governing boards of all Parties.

2.4 Purpose. The purpose of this Agreement is to establish an independent public agency in order to exercise powers common to each Party and any other powers granted to the Authority under state law to participate as a group in the CCA Program pursuant to Public Utilities Code Section 366.2(c)(12); to study, promote, develop, conduct, operate, and manage energy and energy-related climate change programs; and, to exercise all other powers necessary and incidental to accomplishing this purpose.

2.5 Powers. The Authority shall have all powers common to the Parties and such additional powers accorded to it by law. The Authority is authorized, in its own name, to exercise all powers and do all acts necessary and proper to carry out the provisions of this Agreement and fulfill its purposes, including, but not limited to, each of the following:

2.5.1 to make and enter into contracts, including those relating to the purchase or sale of electrical energy or attributes thereof;

2.5.2 to employ agents and employees, including but not limited to a Chief Executive Officer and General Counsel;

2.5.3 to acquire, contract, manage, maintain, and operate any buildings, works or improvements, including electric generating facilities;

2.5.4 to acquire property by eminent domain, or otherwise, except as limited under Section 6508 of the Act, and to hold or dispose of any property;

2.5.5 to lease any property;

2.5.6 to sue and be sued in its own name;

2.5.7 to incur debts, liabilities, and obligations, including but not limited to loans from private lending sources pursuant to its temporary borrowing powers such as Government Code Section 53850 et seq. and authority under the Act;
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2.5.8 to form subsidiary or independent corporations or entities, if appropriate, to carry out energy supply and energy conservation programs at the lowest possible cost consistent with the Authority’s CCA Program implementation plan, risk management policies, or to take advantage of legislative or regulatory changes;

2.5.9 to issue revenue bonds and other forms of indebtedness;

2.5.10 to apply for, accept, and receive all licenses, permits, grants, loans or other assistance from any federal, state or local public agency;

2.5.11 to submit documentation and notices, register, and comply with orders, tariffs and agreements for the establishment and implementation of the CCA Program and other energy programs;

2.5.12 to adopt rules, regulations, policies, bylaws and procedures governing the operation of the Authority (“Operating Rules and Regulations”);

2.5.13 to make and enter into service, energy and any other agreements necessary to plan, implement, operate and administer the CCA Program and other energy programs, including the acquisition of electric power supply and the provision of retail and regulatory support services; and

2.5.14 to negotiate project labor agreements, community benefits agreements and collective bargaining agreements with the local building trades council and other interested parties.

2.6 Limitation on Powers. As required by Government Code Section 6509, the power of the Authority is subject to the restrictions upon the manner of exercising power possessed by the City of Emeryville and any other restrictions on exercising the powers of the Authority that may be adopted by the Board.

2.7 Compliance with Local Zoning and Building Laws. Notwithstanding any other provisions of this Agreement or state law, any facilities, buildings or structures located, constructed or caused to be constructed by the Authority within the territory of the Authority shall comply with the General Plan, zoning and building laws of the local jurisdiction within which the facilities, buildings or structures are constructed and comply with the California Environmental Quality Act (“CEQA”).

2.8 Compliance with the Brown Act. The Authority and its officers and employees shall comply with the provisions of the Ralph M. Brown Act, Government Code Section 54950 et seq.

2.9 Compliance with the Political Reform Act and Government Code Section 1090. The Authority and its officers and employees shall comply with the Political Reform Act (Government Code Section 81000 et seq.) and Government Code Section 1090 et seq, and shall adopt a Conflict of Interest Code pursuant to Government Code Section 87300. The Board of Attachment Staff Report Item 11H
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Directors may adopt additional conflict of interest regulations in the Operating Rules and Regulations.

ARTICLE 3

AUTHORITY PARTICIPATION

3.1 Addition of Parties. Subject to Section 2.2, relating to certain rights of Initial Participants, other incorporated municipalities and counties may become Parties upon (a) the adoption of a resolution by the governing body of such incorporated municipality or county requesting that the incorporated municipality or county, as the case may be, become a member of the Authority, (b) the adoption by an affirmative vote of a majority of all Directors of the entire Board satisfying the requirements described in Section 4.12, of a resolution authorizing membership of the additional incorporated municipality or county, specifying the membership payment, if any, to be made by the additional incorporated municipality or county to reflect its pro rata share of organizational, planning and other pre-existing expenditures, and describing additional conditions, if any, associated with membership, (c) the adoption of an ordinance required by Public Utilities Code Section 366.2(c)(12) and execution of this Agreement and other necessary program agreements by the incorporated municipality or county, (d) payment of the membership fee, if any, and (e) satisfaction of any conditions established by the Board.

3.2 Continuing Participation. The Parties acknowledge that membership in the Authority may change by the addition and/or withdrawal or termination of Parties. The Parties agree to participate with such other Parties as may later be added, as described in Section 3.1.

The Parties also agree that the withdrawal or termination of a Party shall not affect this Agreement or the remaining Parties’ continuing obligations under this Agreement.

ARTICLE 4

GOVERNANCE AND INTERNAL ORGANIZATION

4.1 Board of Directors. The governing body of the Authority shall be a Board of Directors (“Board”) consisting of one director for each Party appointed in accordance with Section 4.2.

4.2 Appointment of Directors. The Directors shall be appointed as follows:

4.2.1 The governing body of each Party shall appoint and designate in writing one regular Director who shall be authorized to act for and on behalf of the Party on matters within the powers of the Authority. The governing body of each Party also shall appoint and designate in writing one alternate Director who may vote on matters when the regular Director is absent from a Board meeting. The person appointed and designated as the regular Director shall be a member of the governing body of the Party at the time of appointment but may continue to serve as a Director following his/her term as a member of the Party’s governing body until a new Director is appointed pursuant to the timing in Section 4.3. The person appointed and designated as the alternate Director shall also be a member of the governing body of a Party and the alternate may continue to serve Attachment Staff Report Item 11H
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as an alternate following his/her term as a member of a Party’s governing body until a new alternate is appointed pursuant to the timing in Section

4.3. 4.2.2 The Board shall also include one non-voting ex officio member as defined in Section 1.1.13 (“Ex Officio Board Member”). The Chair of the Community Advisory Committee, as described in Section 4.9 below, shall serve as the Ex Officio Board Member. The Vice Chair of the Community Advisory Committee shall serve as an alternate Ex Officio Board Member when the regular Ex Officio Board Member is absent from a Board meeting.

4.2.3 The Operating Rules and Regulations, to be developed and approved by the Board in accordance with Section 2.5.12 may include rules regarding Directors, such as meeting attendance requirements. No Party shall be deprived of its right to seat a Director on the Board.

4.3 Term of Office. Each regular and alternate Director shall serve at the pleasure of the governing body of the Party that the Director represents and may be removed as Director by such governing body at the time. If at any time a vacancy occurs on the Board because a Director is no longer a member of a Party’s governing body, the Party shall appoint a replacement to fill the position of the previous Director in accordance with the provisions of Section 4.2.1 within ninety (90) days of the date that such Director is no longer a member of a Party’s governing body or for any other reason that such position becomes vacant.

4.4 Quorum. A majority of the Directors of the entire Board shall constitute a quorum, except that less than a quorum may adjourn a meeting from time to time in accordance with law.

4.5 Powers and Function of the Board. The Board shall conduct or authorize to be conducted all business and activities of the Authority, consistent with this Agreement, the Authority Documents, the Operating Rules and Regulations, and applicable law. Board approval shall be required for any of the following actions, which are defined as “Essential Functions”:

4.5.1 The issuance of bonds or any other financing even if program revenues are expected to pay for such financing.

4.5.2 The hiring of a Chief Executive Officer and General Counsel.

4.5.3 The appointment or removal of an officer.

4.5.4 The adoption of the Annual Budget.

4.5.5 The adoption of an ordinance.

4.5.6 The initiation of resolution of claims and litigation where the Authority will be the defendant, plaintiff, petitioner, respondent, cross complainant or cross petitioner, or intervenor; provided, however, that the Chief Attachment Staff Report Item 11H
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Executive Officer or General Counsel, on behalf of the Authority, may intervene in, become party to, or file comments with respect to any proceeding pending at the California Public Utilities Commission, the Federal Energy Regulatory Commission, or any other administrative agency, without approval of the Board. The Board shall adopt Operating Rules and Regulations governing the Chief Executive Officer and General Counsel’s exercise of authority under this Section 4.5.6.

4.5.7 The setting of rates for power sold by the Authority and the setting of charges for any other category of service provided by the Authority.

4.5.8 Termination of the CCA Program.

4.6 Executive Committee. The Board shall establish an Executive Committee consisting of a smaller number of Directors. The Board may delegate to the Executive Committee such authority as the Board might otherwise exercise, subject to limitations placed on the Board’s authority to delegate certain Essential Functions, as described in Section 4.5 and the Operating Rules and Regulations. The Board may not delegate to the Executive Committee or any other committee its authority under Section 2.5.12 to adopt and amend the Operating Rules and Regulations or its Essential Functions listed in Section 4.5. After the Executive Committee meets or otherwise takes action, it shall, as soon as practicable, make a report of its activities at a meeting of the Board.

4.7 Director Compensation. Directors shall receive a stipend of $100 per meeting, as adjusted to account for inflation, as provided for in the Authority’s Operating Rules and Regulations.

4.8 Commissions, Boards and Committees. The Board may establish any advisory commissions, boards and committees as the Board deems appropriate to assist the Board in carrying out its functions and implementing the CCA Program, other energy programs and the provisions of this Agreement. The Board may establish rules, regulations, policies, bylaws or procedures to govern any such commissions, boards, or committees and shall determine whether members shall be compensated or entitled to reimbursement for expenses.

4.9 Community Advisory Committee. The Board shall establish a Community Advisory Committee consisting of nine members and three alternates, none of whom may be voting members of the Board. One alternate from the pool of three alternates may take the place of a Community Advisory Member when a Community Advisory Committee member cannot attend a meeting. The Community Advisory Committee member that is unable to attend a meeting must notify the alternates of their inability to attend and obtain confirmation that one of the Alternates can attend the Community Advisory Committee meeting in that member’s place.

The function of the Community Advisory Committee shall be to advise the Board of Directors on all subjects related to the operation of the CCA Program as set forth in a work plan adopted by the Board of Directors from time to time, with the exception of personnel and litigation decisions. The Community Advisory Committee is advisory only, and shall not have decision making authority, or receive any delegation of authority from the Board of Directors. The Board shall publicize the opportunity to serve on the Community Advisory Committee and shall Attachment Staff Report Item 11H
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appoint members of the Community Advisory Committee and Alternates from those individuals expressing interest in serving, and who represent a diverse cross-section of interests, skill sets and geographic regions. Members of the Community Advisory Committee shall serve staggered four-years terms (the first term of three of the members shall be two years, and four years thereafter), which may be renewed. A member or Alternate of the Community Advisory Committee may be removed by the Board of Directors by majority vote. The Board of Directors shall determine whether the Community Advisory Committee members will receive a stipend or be entitled to reimbursement of expenses.

4.10 Chief Executive Officer. The Board of Directors shall appoint a Chief Executive Officer for the Authority, who shall be responsible for the day-to-day operation and management of the Authority and the CCA Program. The Chief Executive Officer may exercise all powers of the Authority, including the power to hire, discipline and terminate employees as well as the power to approve any agreement, if the expenditure is authorized in the Authority’s approved budget, except the powers specifically set forth in Section 4.5 or those powers which by law must be exercised by the Board of Directors. The Board of Directors shall provide procedures and guidelines for the Chief Executive Officer exercising the powers of the Authority in the Operating Rules and Regulations.

4.11 General Counsel. The Board of Directors shall appoint a General Counsel for the Authority, who shall be responsible for providing legal advice to the Board of Directors and overseeing all legal work for the Authority.

4.12 Board Voting.

4.12.1 Percentage Vote. Except when a supermajority vote is expressly required by this Agreement or the Operating Rules and Regulations, action of the Board on all matters shall require an affirmative vote of a majority of all Directors on the entire Board (a “Percentage Vote” as defined in Section

1.1.20). A supermajority vote is required by this Agreement for the matters addressed by Section 8.4. When a supermajority vote is required by this Agreement or the Operating Rules and Regulations, action of the Board shall require an affirmative Percentage Vote of the specified supermajority of all Directors on the entire Board. No action can be taken by the Board without an affirmative Percentage Vote. Notwithstanding the foregoing, in the event of a tie in the Percentage Vote, an action may be approved by an affirmative “Voting Shares Vote,” as defined in Section

1.1.22, if three or more Directors immediately request such vote.

4.12.2 Voting Shares Vote. In addition to and immediately after an affirmative percentage vote, three or more Directors may request that, a vote of the voting shares shall be held (a “Voting Shares Vote” as defined in Section

1.1.22). To approve an action by a Voting Shares Vote, the corresponding voting shares (as defined in Section 1.1.23 and Exhibit C) of all Directors voting in the affirmative shall exceed 50% of the voting share of all Directors on the entire Board, or such other higher voting shares percentage expressly required by this Agreement or the Operating Rules Attachment Staff Report Item 11H
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and Regulations. In the event that any one Director has a voting share that equals or exceeds that which is necessary to disapprove the matter being voted on by the Board, at least one other Director shall be required to vote in the negative in order to disapprove such matter. When a voting shares vote is held, action by the Board requires both an affirmative Percentage Vote and an affirmative Voting Shares Vote. Notwithstanding the foregoing, in the event of a tie in the Percentage Vote, an action may be approved on an affirmative Voting Shares Vote. When a supermajority vote is required by this Agreement or the Operating Rules and Regulations, the supermajority vote is subject to the Voting Share Vote provisions of this Section 4.12.2, and the specified supermajority of all Voting Shares is required for approval of the action, if the provision of this Section 4.12.2 are triggered.

4.13 Meetings and Special Meetings of the Board. The Board shall hold at least four regular meetings per year, but the Board may provide for the holding of regular meetings at more frequent intervals. The date, hour and place of each regular meeting shall be fixed by resolution or ordinance of the Board. Regular meetings may be adjourned to another meeting time. Special and Emergency meetings of the Board may be called in accordance with the provisions of California Government Code Section 54956 and 54956.5. Directors may participate in meetings telephonically, with full voting rights, only to the extent permitted by law.

4.14 Officers.

4.14.1 Chair and Vice Chair. Prior to the end of the fiscal year, the Directors shall elect, from among themselves, a Chair, who shall be the presiding officer of all Board meetings, and a Vice Chair, who shall serve in the absence of the Chair. The newly elected Chair and Vice Chair shall commence serving in those capacities on July 1, except that no separate election shall be required for Fiscal Year 2018-2019 and the Chair and Vice Chair elected in 2018 shall continue to serve until the end of the 2018-2019 Fiscal Year. The Chair and Vice Chair shall hold office for one year and serve no more than two consecutive terms, however, the total number of terms a Director may serve as Chair or Vice Chair is not limited. The office of either the Chair or Vice Chair shall be declared vacant and the Board shall make a new selection if: (a) the person serving dies, resigns, or ceases to be a member of the governing body of a Party that person represents, except if the person is continuing to serve on the Board after that person no longer serves on the governing body in conformance with section 4.2.1; (b) the Party that the person represents removes the person as its representative on the Board, or (c) the Party that the person represents withdraws from the Authority pursuant to the provisions of this Agreement.

4.14.2 Secretary. The Board shall appoint a Secretary, who need not be a member of the Board, who shall be responsible for keeping the minutes of all meetings of the Board and all other official records of the Authority.

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4.14.3 Treasurer and Auditor. The Board shall appoint a qualified person to act as the Treasurer and a qualified person to act as the Auditor, neither of whom needs to be a member of the Board. The same person may not simultaneously hold both the office of Treasurer and the office of the Auditor of the Authority. Unless otherwise exempted from such requirement, the Authority shall cause an independent audit to be made annually by a certified public accountant, or public accountant, in compliance with Section 6505 of the Act. The Treasurer shall act as the depositary of the Authority and have custody of all the money of the Authority, from whatever source, and as such, shall have all of the duties and responsibilities specified in Section 6505.5 of the Act. The Board may require the Treasurer and/or Auditor to file with the Authority an official bond in an amount to be fixed by the Board, and if so requested, the Authority shall pay the cost of premiums associated with the bond.

The Treasurer shall report directly to the Board and shall comply with the requirements of treasurers of incorporated municipalities. The Board may transfer the responsibilities of Treasurer to any person or entity as the law may provide at the time.

4.15 Administrative Services Provider. The Board may appoint one or more administrative services providers to serve as the Authority’s agent for planning, implementing, operating and administering the CCA Program, and any other program approved by the Board, in accordance with the provisions of an Administrative Services Agreement. The appointed administrative services provider may be one of the Parties. The Administrative Services Agreement shall set forth the terms and conditions by which the appointed administrative services provider shall perform or cause to be performed all tasks necessary for planning, implementing, operating and administering the CCA Program and other approved programs.

The Administrative Services Agreement shall set forth the term of the Agreement and the circumstances under which the Administrative Services Agreement may be terminated by the Authority. This section shall not in any way be construed to limit the discretion of the Authority to hire its own employees to administer the CCA Program or any other program.

4.16 Operational Audit. The Authority shall commission an independent agent to conduct and deliver at a public meeting of the Board an evaluation of the performance of the CCA Program relative to goals for renewable energy and carbon reductions. The Authority shall approve a budget for such evaluation and shall hire a firm or individual that has no other direct or indirect business relationship with the Authority. The evaluation shall be conducted at least once every two years.

ARTICLE 5

IMPLEMENTATION ACTION AND AUTHORITY DOCUMENTS

5.1 Implementation of the CCA Program.

5.1.1 Enabling Ordinance. Prior to the execution of this Agreement, each Party shall adopt an ordinance in accordance with Public Utilities Code Attachment Staff Report Item 11H
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Section 366.2(c)(12) for the purpose of specifying that the Party intends to implement a CCA Program by and through its participation in the Authority.

5.1.2 Implementation Plan. The Authority shall cause to be prepared an Implementation Plan meeting the requirements of Public Utilities Code Section 366.2 and any applicable Public Utilities Commission regulations as soon after the Effective Date as reasonably practicable. The Implementation Plan shall not be filed with the Public Utilities Commission until it is approved by the Board in the manner provided by Section 4.12.

5.1.3 Termination of CCA Program. Nothing contained in this Article or this Agreement shall be construed to limit the discretion of the Authority to terminate the implementation or operation of the CCA Program at any time in accordance with any applicable requirements of state law.

5.2 Other Authority Documents. The Parties acknowledge and agree that the operations of the Authority will be implemented through various documents duly adopted by the Board through Board resolution or minute action, including but not necessarily limited to the Operating Rules and Regulations, the annual budget, and specified plans and policies defined as the Authority Documents by this Agreement. The Parties agree to abide by and comply with the terms and conditions of all such Authority Documents that may be adopted by the Board, subject to the Parties’ right to withdraw from the Authority as described in Article 7.

5.3 Integrated Resource Plan. The Authority shall cause to be prepared an Integrated Resource Plan in accordance with CPUC regulations that will ensure the long-term development and administration of a variety of energy programs that promote local renewable resources, conservation, demand response, and energy efficiency, while maintaining compliance with the State Renewable Portfolio standard and customer rate competitiveness. The Authority shall prioritize the development of energy projects in Alameda and adjacent counties. Principal aspects of its planned operations shall be in a Business Plan as outlined in Section 5.4 of this Agreement.

5.4 Business Plan. The Authority shall cause to be prepared a Business Plan, which will include a roadmap for the development, procurement, and integration of local renewable energy resources as outlined in Section 5.3 of this Agreement. The Business Plan shall include a description of how the CCA Program will contribute to fostering local economic benefits, such as job creation and community energy programs. The Business Plan shall identify opportunities for local power development and how the CCA Program can achieve the goals outlined in Recitals 3 and 6 of this Agreement. The Business Plan shall include specific language detailing employment and labor standards that relate to the execution of the CCA Program as referenced in this Agreement. The Business Plan shall identify clear and transparent marketing practices to be followed by the CCA Program, including the identification of the sources of its electricity and explanation of the various types of electricity procured by the Authority. The Business Plan shall cover the first five (5) years of the operation of the CCA Program. Progress on the implementation of the Business Plan shall be subject to annual public review.

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5.5 Labor Organization Neutrality. The Authority shall remain neutral in the event its employees, and the employees of its subcontractors, if any, wish to unionize.

5.6 Renewable Portfolio Standards. The Authority shall provide its customers renewable energy primarily from Category 1 eligible renewable resources, as defined under the California RPS and consistent with the goals of the CCA Program. The Authority shall not procure energy from Category 3 eligible renewable resources (unbundled Renewable Energy Credits or RECs) exceeding 50% of the State law requirements, to achieve its renewable portfolio goals. However, for Category 3 RECs associated with generation facilities located within its service jurisdiction, the limitation set forth in the preceding sentence shall not apply.

ARTICLE 6

FINANCIAL PROVISIONS

6.1 Fiscal Year. The Authority’s fiscal year shall be 12 months commencing July 1 and ending June 30. The fiscal year may be changed by Board resolution.

6.2 Depository.

6.2.1 All funds of the Authority shall be held in separate accounts in the name of the Authority and not commingled with funds of any Party or any other person or entity.

6.2.2 All funds of the Authority shall be strictly and separately accounted for, and regular reports shall be rendered of all receipts and disbursements, at least quarterly during the fiscal year. The books and records of the Authority shall be open to inspection by the Parties at all reasonable times.

6.2.3 All expenditures shall be made in accordance with the approved budget and upon the approval of any officer so authorized by the Board in accordance with its Operating Rules and Regulations. The Treasurer shall draw checks or warrants or make payments by other means for claims or disbursements not within an applicable budget only upon the prior approval of the Board.

6.3 Budget and Recovery Costs.

6.3.1 Budget. The initial budget shall be approved by the Board. The Board may revise the budget from time to time through an Authority Document as may be reasonably necessary to address contingencies and unexpected expenses. All subsequent budgets of the Authority shall be prepared and approved by the Board in accordance with the Operating Rules and Regulations.

6.3.2 Funding of Initial Costs. The County shall fund the Initial Costs of establishing and implementing the CCA Program. In the event that the CCA Program becomes operational, these Initial Costs paid by the County and any specified interest shall be included in the customer charges for Attachment Staff Report Item 11H
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electric services to the extent permitted by law, and the County shall be reimbursed from the payment of such charges by customers of the Authority. The Authority may establish a reasonable time period over which such costs are recovered. In the event that the CCA Program does not become operational, the County shall not be entitled to any reimbursement of the Initial Costs.

6.3.4 Additional Contributions and Advances. Pursuant to Government Code Section 6504, the Parties may in their sole discretion make financial contributions, loans or advances to the Authority for the purposes of the Authority set forth in this Agreement. The repayment of such contributions, loans or advances will be on the written terms agreed to by the Party making the contribution, loan or advance and the Authority.

ARTICLE 7

WITHDRAWAL AND TERMINATION

7.1 Withdrawal.

7.1.1 General Right to Withdraw. A Party may withdraw its membership in the Authority, effective as of the beginning of the Authority’s fiscal year, by giving no less than 180 days advance written notice of its election to do so, which notice shall be given to the Authority and each Party.

Withdrawal of a Party shall require an affirmative vote of the Party’s governing board.

7.1.2 Withdrawal Following Amendment. Notwithstanding Section 7.1.1, a Party may withdraw its membership in the Authority following an amendment to this Agreement provided that the requirements of this Section 7.1.2 are strictly followed. A Party shall be deemed to have withdrawn its membership in the Authority effective 180 days after the Board approves an amendment to this Agreement if the Director representing such Party has provided notice to the other Directors immediately preceding the Board’s vote of the Party’s intention to withdraw its membership in the Authority should the amendment be approved by the Board.

7.1.3 The Right to Withdraw Prior to Program Launch. After receiving bids from power suppliers for the CCA Program, the Authority must provide to the Parties a report from the electrical utility consultant retained by the Authority comparing the Authority’s total estimated electrical rates, the estimated greenhouse gas emissions rate and the amount of estimated renewable energy to be used with that of the incumbent utility. Within 30 days after receiving this report, through its City Manager or a person expressly authorized by the Party, any Party may immediately withdraw its membership in the Authority by providing written notice of withdrawal to the Authority if the report determines that any one of the following Attachment Staff Report Item 11H
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conditions exists: (1) the Authority is unable to provide total electrical rates, as part of its baseline offering to customers, that are equal to or lower than the incumbent utility, (2) the Authority is unable to provide electricity in a manner that has a lower greenhouse gas emissions rate than the incumbent utility, or (3) the Authority will use less qualified renewable energy than the incumbent utility. Any Party who withdraws from the Authority pursuant to this Section 7.1.3 shall not be entitled to any refund of the Initial Costs it has paid to the Authority prior to the date of withdrawal unless the Authority is later terminated pursuant to Section

7.3. In such event, any Initial Costs not expended by the Authority shall be returned to all Parties, including any Party that has withdrawn pursuant to this section, in proportion to the contribution that each made.

Notwithstanding anything to the contrary in this Agreement, any Party who withdraws pursuant to this section shall not be responsible for any liabilities or obligations of the Authority after the date of withdrawal, including without limitation any liability arising from power purchase agreements entered into by the Authority.

7.2 Continuing Liability After Withdrawal; Further Assurances; Refund. A Party that withdraws its membership in the Authority under either Section 7.1.1 or 7.1.2 shall be responsible for paying its fair share of costs incurred by the Authority resulting from the Party’s withdrawal, including costs from the resale of power contracts by the Authority to serve the Party’s load and any similar costs directly attributable to the Party’s withdrawal, such costs being limited to those contracts executed while the withdrawing Party was a member, and administrative costs associated thereto. The Parties agree that such costs shall not constitute a debt of the withdrawing Party, accruing interest, or having a maturity date. The Authority may withhold funds otherwise owing to the Party or may require the Party to deposit sufficient funds with the Authority, as reasonably determined by the Authority, to cover the Party’s costs described above. Any amount of the Party’s funds held by the Authority for the benefit of the Party that are not required to pay the Party’s costs described above shall be returned to the Party.

The withdrawing party and the Authority shall execute and deliver all further instruments and documents, and take any further action that may be reasonably necessary, as determined by the Board, to effectuate the orderly withdrawal of such Party from membership in the Authority. A withdrawing party has the right to continue to participate in Board discussions and decisions affecting customers of the CCA Program that reside or do business within the jurisdiction of the Party until the withdrawal’s effective date.

7.3 Mutual Termination. This Agreement may be terminated by mutual agreement of all the Parties; provided, however, the foregoing shall not be construed as limiting the rights of a Party to withdraw its membership in the Authority, and thus terminate this Agreement with respect to such withdrawing Party, as described in Section 7.1.

7.4 Disposition of Property upon Termination of Authority. Upon termination of this Agreement as to all Parties, any surplus money or assets in possession of the Authority for use under this Agreement, after payment of all liabilities, costs, expenses, and charges incurred under this Agreement and under any Authority Documents, shall be returned to the then-existing Parties in proportion to the contributions made by each.

Attachment Staff Report Item 11H
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ARTICLE 8

MISCELLANEOUS PROVISIONS

8.1 Dispute Resolution. The Parties and the Authority shall make reasonable efforts to settle all disputes arising out of or in connection with this Agreement. Before exercising any remedy provided by law, a Party or the Parties and the Authority shall engage in nonbinding mediation in the manner agreed upon by the Party or Parties and the Authority. The Parties agree that each Party may specifically enforce this section 8.1. In the event that nonbinding mediation is not initiated or does not result in the settlement of a dispute within 120 days after the demand for mediation is made, any Party and the Authority may pursue any remedies provided by law.

8.2 Liability of Directors, Officers, and Employees. The Directors, officers, and employees of the Authority shall use ordinary care and reasonable diligence in the exercise of their powers and in the performance of their duties pursuant to this Agreement. No current or former Director, officer, or employee will be responsible for any act or omission by another Director, officer, or employee. The Authority shall defend, indemnify and hold harmless the individual current and former Directors, officers, and employees for any acts or omissions in the scope of their employment or duties in the manner provided by Government Code Section 995 et seq. Nothing in this section shall be construed to limit the defenses available under the law, to the Parties, the Authority, or its Directors, officers, or employees.

8.3 Indemnification of Parties. The Authority shall acquire such insurance coverage as the Board deems necessary to protect the interests of the Authority, the Parties and the public.

Such insurance coverage shall name the Parties and their respective Board or Council members, officers, agents and employees as additional insureds. The Authority shall defend, indemnify and hold harmless the Parties and each of their respective Board or Council members, officers, agents and employees, from any and all claims, losses, damages, costs, injuries and liabilities of every kind arising directly or indirectly from the conduct, activities, operations, acts, and omissions of the Authority under this Agreement.

8.4 Amendment of this Agreement. This Agreement may be amended in writing by a two-thirds affirmative vote of the entire Board satisfying the requirements described in Section

4.12. Except that, any amendment to the voting provisions in Section 4.12 may only be made by a three-quarters affirmative vote of the entire Board. The Authority shall provide written notice to the Parties at least 30 days in advance of any proposed amendment being considered by the Board. If the proposed amendment is adopted by the Board, the Authority shall provide prompt written notice to all Parties of the effective date of such amendment along with a copy of the amendment.

8.5 Assignment. Except as otherwise expressly provided in this Agreement, the rights and duties of the Parties may not be assigned or delegated without the advance written consent of all of the other Parties, and any attempt to assign or delegate such rights or duties in contravention of this Section 8.5 shall be null and void. This Agreement shall inure to the benefit of, and be binding upon, the successors and assigns of the Parties. This Section 8.5 does not prohibit a Party from entering into an independent agreement with another agency, person, or entity regarding the financing of that Party’s contributions to the Authority, or the disposition of Attachment Staff Report Item 11H
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proceeds which that Party receives under this Agreement, so long as such independent agreement does not affect, or purport to affect, the rights and duties of the Authority or the Parties under this Agreement.

8.6 Severability. If one or more clauses, sentences, paragraphs or provisions of this Agreement shall be held to be unlawful, invalid or unenforceable, it is hereby agreed by the Parties, that the remainder of the Agreement shall not be affected thereby. Such clauses, sentences, paragraphs or provision shall be deemed reformed so as to be lawful, valid and enforced to the maximum extent possible.

8.7 Further Assurances. Each Party agrees to execute and deliver all further instruments and documents, and take any further action that may be reasonably necessary, to effectuate the purposes and intent of this Agreement.

8.8 Execution by Counterparts. This Agreement may be executed in any number of counterparts, and upon execution by all Parties, each executed counterpart shall have the same force and effect as an original instrument and as if all Parties had signed the same instrument.

Any signature page of this Agreement may be detached from any counterpart of this Agreement without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this Agreement identical in form hereto but having attached to it one or more signature pages.

8.9 Parties to be Served Notice. Any notice authorized or required to be given pursuant to this Agreement shall be validly given if served in writing either personally, by deposit in the United States mail, first class postage prepaid with return receipt requested, or by a recognized courier service. Notices given (a) personally or by courier service shall be conclusively deemed received at the time of delivery and receipt and (b) by mail shall be conclusively deemed given 72 hours after the deposit thereof (excluding Saturdays, Sundays and holidays) if the sender receives the return receipt. All notices shall be addressed to the office of the clerk or secretary of the Authority or Party, as the case may be, or such other person designated in writing by the Authority or Party. In addition, a duplicate copy of all notices provided pursuant to this section shall be provided to the Director and alternate Director for each Party. Notices given to one Party shall be copied to all other Parties. Notices given to the Authority shall be copied to all Parties. All notices required hereunder shall be delivered to:

The County of Alameda
Director, Community Development Agency
224 West Winton Ave.

Hayward, CA 94612
With a copy to:

Office of the County Counsel
1221 Oak Street, Suite 450
Oakland, CA 94612
Attachment Staff Report Item 11H
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if to [PARTY No. ____]
Office of the City Clerk
__________________________
__________________________
Office of the City Manager/Administrator
__________________________
__________________________
Office of the City Attorney
__________________________
__________________________
if to [PARTY No._____ ]
Office of the City Clerk
__________________________
__________________________
Office of the City Manager/Administrator
__________________________
__________________________
Office of the City Attorney
__________________________
__________________________
ARTICLE 9

SIGNATURE
IN WITNESS WHEREOF, the Parties hereto have executed this Joint Powers Agreement establishing the East Bay Community Energy Authority.

By:

Name:

Title:

Date:

Party:

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EXHIBIT A

LIST OF THE PARTIES
This Exhibit A is effective as of September 21, 2022.

County of Alameda
City of Albany
City of Berkeley
City of Dublin
City of Emeryville
City of Fremont
City of Hayward
City of Livermore
City of Newark
City of Oakland
City of Piedmont
City of Pleasanton
City of San Leandro
City of Stockton
City of Tracy
City of Union City
Attachment Staff Report Item 11H

EXHIBIT B

ANNUAL ENERGY USE
This Exhibit B is effective as of September 21, 2022.

Party kWh (2021)
Albany 51,776,870
Berkeley 370,191,096
Dublin 254,391,482
Emeryville 170,415,886
Fremont 1,152,160,067
Hayward 685,960,209
Livermore 441,369,886
Newark 263,309,620
Oakland 1,749,739,631
Piedmont 29,230,795
Pleasanton 405,288,495
San Leandro 448,938,229
Stockton 1,388,481,371
Tracy 434,861,665
Unincorporated 471,391,155
Union City 269,516,289
Total 8,587,022,746
All data provided by PG&E
Attachment Staff Report Item 11H

EXHIBIT C

VOTING SHARES
This Exhibit C is effective as of September 21, 2022.

Party kWh (2021) Voting Shares
Section 4.12.2
Albany 51,776,870 0.6%
Berkeley 370,191,096 4.3%
Dublin 254,391,482 3.0%
Emeryville 170,415,886 2.0%
Fremont 1,152,160,067 13.4%
Hayward 685,960,209 8.0%
Livermore 441,369,886 5.1%
Newark 263,309,620 3.1%
Oakland 1,749,739,631 20.4%
Piedmont 29,230,795 0.3%
Pleasanton 405,288,495 4.7%
San Leandro 448,938,229 5.2%
Stockton 1,388,481,371 16.2%
Tracy 434,861,665 5.1%
Unincorporated 471,391,155 5.5%
Union City 269,516,289 3.1%
Total 8,587,022,746 100%
All data provided by PG&E
Attachment Staff Report Item 11H
Attachment Staff Report Item 11I

EXHIBIT A

LIST OF THE PARTIES
This Exhibit A is effective as of September 20, 2023.

County of Alameda
City of Albany
City of Berkeley
City of Dublin
City of Emeryville
City of Fremont
City of Hayward
City of Lathrop
City of Livermore
City of Newark
City of Oakland
City of Piedmont
City of Pleasanton
City of San Leandro
City of Stockton
City of Tracy
City of Union City
Attachment Staff Report Item 11I

EXHIBIT B

ANNUAL ENERGY USE
This Exhibit B is effective as of September 20, 2023.

Party kWh (2022*)
Albany 50,016,072
Berkeley 350,111,874
Dublin 250,811,690
Emeryville 173,586,542
Fremont 1,182,339,971
Hayward 681,289,470
Lathrop 183,070,584
Livermore 428,724,628
Newark 244,335,398
Oakland 1,713,563,058
Piedmont 28,595,451
Pleasanton 394,860,960
San Leandro 414,939,109
Stockton
Tracy
1,153,820,553
412,411,899
Unincorporated County 452,054,476
Union City 261,439,720
Total 8,375,971,455
*All data provided by PG&E
Attachment Staff Report Item 11I

EXHIBIT C

VOTING SHARES
This Exhibit C is effective as of September 20, 2023
.

Party kWh (2022*) Voting Shares
Section 4.12.2
Albany 50,016,072 0.6%
Berkeley 350,111,874 4.2%
Dublin 250,811,690 3.0%
Emeryville 173,586,542 2.1%
Fremont 1,182,339,971 14.1%
Hayward 681,289,470 8.1%
Lathrop
Livermore
183,070,584
428,724,628

2.2%

5.1%
Newark 244,335,398 2.9%
Oakland 1,713,563,058 20.5%
Piedmont 28,595,451 0.3%
Pleasanton 394,860,960 4.7%
San Leandro
Stockton
414,939,109
1,153,820,553

5.0%

13.8%
Tracy 412,411,899 4.9%
Unincorporated County 452,054,476 5.4%
Union City 261,439,720 3.1%
Total 8,375,971,455 100%
*All data provided by PG&E
Attachment Staff Report Item 11J
RESOLUTION NO. XX

A RESOLUTION OF THE BOARD OF DIRECTORS OF THE EAST BAY COMMUNITY ENERGY AUTHORITY AUTHORIZING EBCE STAFF TO UPDATE EBCE’s

IMPLEMENTATION PLAN TO REFLECT THE INCLUSION OF A NEW MEMBER

JURISDICTION AND SUBMIT THE UPDATED PLAN TO THE CPUC

THE BOARD OF DIRECTORS OF THE EAST BAY COMMUNITY ENERGY AUTHORITY DOES HEREBY FIND, RESOLVE AND ORDER AS FOLLOWS:

WHEREAS, The East Bay Community Energy Authority (“EBCE”) was formed on December 1, 2016, under the Joint Exercise of Power Act, California Government Code sections 6500 et seq., among the County of Alameda, and the Cities of Albany, Berkeley, Dublin, Emeryville, Fremont, Hayward, Livermore, Piedmont, Oakland, San Leandro, and Union City to study, promote, develop, conduct, operate, and manage energy and energy-related climate change programs in all of the member jurisdictions.

WHEREAS, on November 20, 2019, EBCE’s Board of Directors unanimously authorized the cities of Tracy, Pleasanton, and Newark to become new parties to the Agreement with EBCE service beginning in those jurisdictions in April 2021; and WHEREAS, on December 20, 2019, EBCE submitted an updated “Implementation Plan” to the CPUC reflecting the membership of the cities of Tracy, Pleasanton, and Newark to the Agreement and EBCE service area; and WHEREAS, on September 21, 2022, EBCE’s Board of Directors unanimously authorized the City of Stockton to become a new party to the Agreement with EBCE service anticipated to begin in April 2024; and
WHEREAS, on December 8, 2022, EBCE submitted an updated “Implementation Plan” to the CPUC reflecting the membership of the City of Stockton to the Agreement and EBCE service area; and
WHEREAS, the Board of Directors has approved Resolution XX to authorize the City of Lathrop to become a member of EBCE, with enrollments expected to begin in 2025;
WHEREAS, on February 8, 2018, the California Public Utilities Commission (“CPUC”) passed Resolution E-4907, which requires a one year waiting period for jurisdictions intending to form or join a community choice aggregation (“CCA”) program, like EBCE;
WHEREAS, in order to begin enrolling electricity customers in Lathrop by 2025, EBCE must submit to the CPUC an updated Implementation Plan and Statement of Attachment Staff Report Item 11J
Intent (“Implementation Plan”) reflecting the inclusion of this new member jurisdiction before the end of the 2023 calendar year.

NOW, THEREFORE, THE BOARD OF DIRECTORS OF THE EAST BAY COMMUNITY ENERGY AUTHORITY DOES HEREBY RESOLVE AS FOLLOWS:

Section 1. The Board hereby authorizes EBCE staff to update EBCE’s Implementation Plan, reflecting the membership of the City of Lathrop.

Section 2. The Board hereby directs staff to submit the updated Implementation Plan to the CPUC for certification as soon as reasonably feasible, before December 31, 2023.

ADOPTED AND APPROVED this 20th day of September, 2023.

Elisa Marquez, Chair
ATTEST:

Adrian Bankhead, Secretary
ifto: Citv of Lathrop
Office of the City Clerk
390 Towne Centre Drive
Lathrop, CA 95330
Office of the City Manager
390 Towne Centre Drive
Lathrop, CA 95330
Office ofthe City Attorney
390 Towne Centre Drive
Lathrop, CA 95330
With a co Y to:

Department of Public Works
390 Towne Centre Drive
Lathrop, CA 95330
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Attachment Staff Report Item 11K
ARTICLE 9

SIGNATURE
IN WITNESS WHEREOF, the Parties hereto have executed this Joint Powers Agreement establishing the East Bay Community Energy Authority.

CITY OF LATHROP,
A California municipal corporation of the
State of California
B 7. 2. 23
p
en J. Salvatore Date
City Manager
ATTEST:

City Clerk of and for the City
of Lathrop, State of California
B C' , lz
eresa Vargas Date
City Clerk

APPROVED AS TO FORM BY THE CITY OF LATHROP CITY ATTORNEY By. zo:..-3
Sa vador Navarrete Date
City Attorney
21-
Attachment Staff Report Item 11K
Inclusion of New Communities:

City of Lathrop
September 2023
Attachment Staff Report Item 11L
City of Lathrop, CA
Located between Tracy and Stockton in San Joaquin County Pop: 30,700 (2022)
Incorporated:1989
Major transit intersection: Interstate 5 and CA State Route 120 Top three employers: Tesla, UPS, Army & Air Force Exchange Service Energy-related opportunities
 Growing electricity load, particularly commercial & industrial sectors
 Central location relative to agriculture, logistics, and shipping hubs
 Interstate transit corridors for EV fast charging; light, medium, and heavy-duty fleets; and other transportation electrification projects
2 Attachment Staff Report Item 11L
EBCE
enrolls
new
customers
Community
Outreach
(with new
name and
brand)
EBCE
updates
Imp. Plan
for CPUC
cert
EBCE
Board
considers
including
Lathrop
EBCE
conducts
analysis
City
Council
votes to
join EBCE
EBCE staff
invited to
present to
City
Council
Timeline: Lathrop’s EBCE Membership
3 March 2023 July 2023 Aug 2023 Sept 2023 By Dec 2023 2024 2025 Attachment Staff Report Item 11L
Lathrop Quantitative Analysis: Summary
Notable features:
• Lathrop is similar in size to Albany (number of accounts) and Emeryville (citywide load) • Higher percentage of large commercial & industrial accounts (those with E19/E20 rate classifications) • Lathrop Irrigation District (LID) serves customers of the River Islands housing development Parameters of analysis:
• Based on current EBCE overhead costs and 10-year average energy market values/forecasts; • Assumes 7% account opt out rate (slightly above EBCE’s current service area-wide opt out rate) • Applies EBCE’s 2023 rates from 2023-24 budget development • Data excludes ineligible loads (e.g., Irrigation District and Direct Access customers); • Applies 2022 PG&E load data for Lathrop (the most recent available) 4 Attachment Staff Report Item 11L
Lathrop Quantitative Analysis: Summary
• Financial ‘Stress Test’ measures impact of two key cost variables:
1) Wholesale energy market prices; and 2) Power Charge Indifference Adjustment (PCIA) • Routinely performed by EBCE staff for budget development & power procurement modeling 5 Lathrop 2022 EBCE 2022
EBCE w/Lathrop and
Stockton
2025
Accounts 7,300 642,400 766,000
Annual
Load(GWh/yr)
184 6,552 8,220
Peak Load (MW) 49 1,636 2,237
Net Position % +1.6% +14.5% +8%
(+0.9% specifically due to
Lathrop)
Net Position $ $1.77M $109.99M $197.99M
Attachment Staff Report Item 11L
Summary Data
6 Attachment Staff Report Item 11L
2022 Hourly Load
7 Attachment Staff Report Item 11L
8 2022 Daily Load
Attachment Staff Report Item 11L
Qualitative Considerations
• Diversity, Equity, and Inclusion
• Environmental Justice
• Local Programs
• Legislative and Political Influence
• CCA Proliferation, Public Power, Energy Democracy
9 Attachment Staff Report Item 11L
EBCE Local Programs - Transportation
10 Public DC Fast Chargers
EBCE is developing a portfolio of publicly available fast chargers for passenger electric vehicles. We are partnering with our Cities to identify charging station sites located within multi-family hot spots that have been mapped with EBCE’s proprietary mapping tool. EBCE is developing the first 11 stations now, to begin service in 2024.

Regional Medium-Heavy Electrification
EBCE is developing a regional blueprint to make Alameda County, Tracy and Stockton a first mover for Medium and Heavy duty electrification.

E-Bike Lending program
EBCE released an RFP for an organization to support a 3-year $6M electric bike lending and incentive program. ACTC has recently approved an additional $4M in incentives. Stockton service was included in the solicitation and will be in initial launch plan.

Attachment Staff Report Item 11L
11 Attachment Staff Report Item 11L
City of Lathrop: Key JPA Membership Milestones

1. March 13, 2023: EBCE staff invited to present informational item to City Council • City authorizes EBCE to access citywide PG&E load data

2. May 2023: PG&E provides citywide load data to EBCE

3. July 10, 2023: City Council unanimously passes Resolution and ordinance to join EBCE

4. August 14, 2023: City Council unanimously passes second reading (required by State law) of ordinance to join EBCE
12 Attachment Staff Report Item 11L
Steps to Joining EBCE

1. Meetings with City staff/elected officials

2. 2-3 presentations to the City Council & Council considers joining JPA

3. EBCE staff conducts quantitative analysis

4. EBCE Board & Community Advisory Committee review analysis and Board considers including new community

5. If Board Approves, EBCE updates JPA and files amended Implementation Plan with the CPUC before 12/31/23
2024: Community outreach in new community
2025: EBCE enrolls customers in new community
13 Attachment Staff Report Item 11L
Staff Report Item 12
Staff Report Item 12
TO: East Bay Community Energy Board of Directors
FROM: Annie Henderson, VP Marketing & Account Services
Theresa McDermit, Head of Brand
SUBJECT: Update on Ava Community Energy Visual Identity and Soft Launch Timeline
DATE: September 20, 2023
__________________________________________________________________ Recommendation
Receive an update on the visual identity and plans for the soft launch of Ava Community Energy
Background and Discussion
Background
In recent years, EBCE has dramatically increased its focus on actively promoting and enabling decarbonization and efficiency initiatives while maintaining its ongoing commitment to the delivery of clean power at low prices. Since early 2022, staff have led an effort to define and articulate an updated brand strategy in support of this broadening mandate. As a result of the strategy, a resolution was approved at the June 2023 Board Meeting to transition the name of the agency to Ava Community Energy starting October 2023 or as determined by direction of the CEO.

Visual Identity
The brandmark for Ava Community Energy signals our clarity and optimism as a guide for the energy transition and orchestrator of innovative solutions. Its construction evokes the convergence of a community around a shared direction, in addition to making an iconic statement. The color palette was selected to stand out in our category while remaining approachable and friendly, as well as gender neutral.

Staff Report Item 12
Brandmark
Color Palette
Website Mock-Up
Launch Timeline
Staff Report Item 12
We plan to introduce the Ava brand in two phases. We’ll adopt the Ava brand in late October (our “soft” launch; scheduled to begin Oct. 24). Between October and the end of the calendar year, we’ll work to ensure the brand is applied across all our touchpoints and those of our partners. In early 2024, we’ll commence the main launch of the brand with proactive paid advertising and public relations campaigns designed to inform and engage our constituents. Below is a list of some key activities by phase of our launch:

Pre-launch
• Customer communication teaser within the Power Content Label mailer Phase 1 / Soft-launch
• Website “reskinned” with Ava branding; language update; URL becomes avaenergy.org
• Employee and other public-facing email addresses migrated to @avaenergy.org • Call center scripts and IVR refers to Ava Community Energy • Core registrations and relationship documents required to do business under our new name (e.g. bank accounts, PG&E forms, etc.)
• Adopt Ava templates: powerpoint, email, social media, board memos, etc. • Municipal partner websites updated
• EBCE staff will provide local municipal staff with resources for the soft launch by the end of September.

Phase 2 / Main Launch
• Paid advertising and proactive PR to engage and inform our constituents Official Name Change
Staff is working with legal counsel to determine the appropriate way to do business under the name Ava Community Energy. We are investigating the possible use of a ficticious business name and/or an amendment to the Joint Powers Agreement. For reference, both Central Coast Community Energy and Marin Clean Energy did a JPA amendment which did not require member jurisdictions to resign the document or take other local action.

Fiscal Impact
Funding for all re-branding activities was included in the FY23/24 budget Committee Recommendation
Staff Report Item 12
The Brand Ad Hoc Committees of the Board and Community Advisory Committee were asked to identify any critical red flags on the logo design. There is a Marketing, Regulatory, and Legislative Subcommittee meeting in October. At that meeting, staff will provide any updates to the timeline for soft launch and preview of the plan for full launch in January.

Staff Report Item 13
Staff Report Item 13
TO: East Bay Community Energy Board of Directors
FROM: Izzy Carson, Power Resources Manager
SUBJECT: 2022 Power Source Disclosure Annual Report and Power Content Label
DATE: September 20, 2023
__________________________________________________________________ Recommendation
Adopt a Resolution to accept and attest to the veracity of the 2022 Power Source Disclosure Program Annual Report (PSDR) and the 2022 Power Content Label (PCL).

Background and Discussion
Background
The California State Legislature passed Senate Bill (SB) 1305 in 1997, establishing the Power Source Disclosure Program in order to provide retail electricity consumers “accurate, reliable, and simple to understand information on the sources of energy that are used to provide electric services.” Assembly Bill (AB) 162, adopted in 2009, modified the reporting requirements of SB 1305. AB 162 requires all retail suppliers of electricity in California (CA) to disclose the sources of the electricity they sell to customers using reporting formats developed by the California Energy Commission (CEC). In 2016, AB 1110 was passed which further modified the PSDR reporting requirements, including among other things, changes to reporting for unbundled Renewable Energy Credits (RECs) and requiring retail sellers to disclose the greenhouse gas (GHG) emissions factor associated with each electricity portfolio.

The CEC updated the regulations implementing SB 1305, AB 162, and AB 1100 effective May 2020.

For each year’s filing, East Bay Community Energy (EBCE) is required to 1) submit an Annual Report (the PSDR) to the CEC detailing its actual resource mix for the previous calendar year, and 2) provide an annual PCL to customers and the CEC showing the percentage breakdown by resource type. For 2022, the PCL must be posted online by October 2nd and mailed to customers by the end of 2023.

Staff Report Item 13
Under the CEC’s regulations, private retail electricity suppliers must engage an auditor to verify the accuracy and completeness of data submitted to the CEC in the PSDR; however, public agencies are allowed to provide a self-attestation. Therefore, to fulfill its Power Source Disclosure Program reporting obligations for 2022, EBCE must provide the CEC with the Board’s attestation to the veracity of the PSDR and PCL.

Power Source Disclosure Report and Power Content Label
Each year EBCE reports electricity purchases and retail sales to the CEC through the PSDR.

The PSDR contains a breakdown of energy purchases over a calendar year for each retail plan and is counted as a percent of total sales by source. The CEC uses these reports from each electricity retail seller serving load in CA to generate a total CA system power mix by source.

In addition, EBCE discloses to its customers the power mix for each retail plan alongside the CA power mix on the PCL. The PCL allows customers to compare their power content to the total California power mix and to other electricity providers and is provided to customers through a mailer and posted on the EBCE webpage.

Table 1: EBCE’s 2022 Power Content Label data
Greenhouse Gas Emissions
AB 1110 and the CEC’s regulations require electricity suppliers to disclose the GHG emissions intensity associated with its electricity sources for the previous calendar year. The GHG emissions factor can only be reported through the PCL and not on any third-party platform.

In addition to asking the Board to accept the 2022 PSDR and PCL, this report presents the emissions factor for Bright Choice from 2022 that also appears on the PCL.

Staff Report Item 13
EBCE 2022 Bright Choice Emissions Factor:
496 lb-CO2
e/MWh
Under EBCE’s current retail plan design, the Renewable 100 product is emissions free. The Brilliant 100 product, while no longer offered, is also emissions free. The emissions from Bright Choice will decrease over time as we move towards carbon free content by 2030.

Methodology
In preparing the PSDR, staff populates the template with electricity purchases from generation that occurred during the calendar year. Delivered RECs are tracked using the Western Renewable Energy Generation Information System (WREGIS), and carbon free purchases including electricity from Large Hydroelectric generation is tracked using either meter data or E-tags. The E-tags trace the generation from the source to the delivery location. All the purchased generation is compared against invoices for accuracy, and retail sales are counted using the settlement quality meter data from our accounting service which is EBCE’s system of record for sales. The complete PSDR is then reviewed internally to ensure accuracy in reporting prior to submission to the CEC.

Fiscal Impact
There are no fiscal impacts in accepting and attesting to the veracity of the 2022 Power Source Disclosure Annual Report and the 2022 Power Content Label.

Attachments
A. Resolution of the Board of Directors of East Bay Community Energy Accepting and Attesting to the 2022 Power Source Disclosure Annual Report and the 2022 Power Content Label
B. 2022 Power Source Disclosure Reports - Schedule 3
C. 2022 Power Content Label
D. Presentation of Power Source Disclosure Report and Power Content Label Attachment Staff Report Item 13A
RESOLUTION NO. R-2023-xx

A RESOLUTION OF THE BOARD OF DIRECTORS

OF THE EAST BAY COMMUNITY ENERGY AUTHORITY TO ACCEPT AND ATTEST TO THE VERACITY OF THE 2022 POWER SOURCE DISCLOSURE PROGRAM ANNUAL REPORT AND THE 2022 POWER CONTENT LABEL__
WHEREAS The East Bay Community Energy Authority (“EBCE”) was formed as a community choice aggregation agency (“CCA”) on December 1, 2016, Under the Joint Exercise of Power Act, California Government Code sections 6500 et seq., among the County of Alameda, and the Cities of Albany, Berkeley, Dublin, Emeryville, Fremont, Hayward, Livermore, Piedmont, Oakland, San Leandro, and Union City to study, promote, develop, conduct, operate, and manage energy-related climate change programs in all of the member jurisdictions. The cities of Newark and Pleasanton, located in Alameda County, along with the City of Tracy, located in San Joaquin County, were added as members of EBCE and parties to the JPA in March of 2020. The city of Stockton, located in San Joaquin County was added as a member of EBCE and party to the JPA in September of 2022;
WHEREAS The California State Legislature passed Senate Bill (SB) 1305 in 1997, and in 2009 passed Assembly Bill (AB) 162, which modified the reporting requirements of SB 1305. AB 162 requires all retail suppliers of electricity in California to disclose the sources of the electricity they sell to customers using reporting formats developed by the California Energy Commission;
WHEREAS In 2016, AB 1110 was passed which further modified the Power Source Disclosure Reporting requirements; and
WHEREAS California Code of Regulations, title 20, section 1394.2(a)(2), as modified by the California Energy Commission in May 2020, allows the Board of Directors of a retail supplier of electricity that is a public agency to attest to the veracity of the information contained in the Power Source Disclosure Annual Report and Power Content Label to fulfill the audit requirement for each retail product.

NOW, THEREFORE, THE BOARD OF DIRECTORS OF THE EAST BAY COMMUNITY ENERGY AUTHORITY DOES HEREBY RESOLVE AS FOLLOWS:

Section 1. The Board of Directors accepts and attests to the veracity of the 2022 Power Source Disclosure Annual Report and the 2022 Power Content Label.

ADOPTED AND APPROVED this 20th day of September 2023.

Attachment Staff Report Item 13A
Elisa Márquez, Chair
ATTEST:

Adrian Bankhead, Clerk of the Board
Version: April 2023
Adjusted Net
Procured (MWh)
Percent of Total
Retail Sales
Renewable Procurements 2,509,876 49.4%
Biomass & Biowaste 75,978 1.5%
Geothermal 41,346 0.8%
Eligible Hydroelectric 72,490 1.4%
Solar 917,803 18.1%
Wind 1,402,259 27.6%
Coal - 0.0%
Large Hydroelectric 1,113,227 21.9%
Natural gas - 0.0%
Nuclear 10,805 0.2%
Other 451 0.0%
Unspecified Power 1,441,784 28.4%
Total 5,076,143 100.0%
5,076,143
496

0.6%
Total Retail Sales (MWh)
GHG Emissions Intensity (converted to lbs CO2
e/MWh)
Percentage of Retail Sales Covered by Retired Unbundled RECs
2022 POWER SOURCE DISCLOSURE ANNUAL REPORT
SCHEDULE 3: POWER CONTENT LABEL DATA
For the Year Ending December 31, 2022
East Bay Community Energy
Bright Choice
Instructions: No data input is needed on this schedule. Retail suppliers should use these auto-populated calculations to fill out their Power Content Labels.

Attachment Staff Report Item 13B
Version: April 2023
Adjusted Net
Procured (MWh)
Percent of Total
Retail Sales
Renewable Procurements 12,400 35.8%
Biomass & Biowaste - 0.0%
Geothermal - 0.0%
Eligible Hydroelectric - 0.0%
Solar 6,200 17.9%
Wind 6,200 17.9%
Coal - 0.0%
Large Hydroelectric 22,238 64.2%
Natural gas - 0.0%
Nuclear - 0.0%
Other - 0.0%
Unspecified Power - 0.0%
Total 34,638 100.0%
34,638 - 0.0%
Total Retail Sales (MWh)
GHG Emissions Intensity (converted to lbs CO2
e/MWh)
Percentage of Retail Sales Covered by Retired Unbundled RECs
2022 POWER SOURCE DISCLOSURE ANNUAL REPORT
SCHEDULE 3: POWER CONTENT LABEL DATA
For the Year Ending December 31, 2022
East Bay Community Energy
Brilliant 100
Instructions: No data input is needed on this schedule. Retail suppliers should use these auto-populated calculations to fill out their Power Content Labels.

Attachment Staff Report Item 13B
Version: April 2023
Adjusted Net
Procured (MWh)
Percent of Total
Retail Sales
Renewable Procurements 1,421,427 100.0%
Biomass & Biowaste - 0.0%
Geothermal - 0.0%
Eligible Hydroelectric - 0.0%
Solar 710,713 50.0%
Wind 710,714 50.0%
Coal - 0.0%
Large Hydroelectric - 0.0%
Natural gas - 0.0%
Nuclear - 0.0%
Other - 0.0%
Unspecified Power - 0.0%
Total 1,421,427 100.0%
1,421,427 - 0.0%
Total Retail Sales (MWh)
GHG Emissions Intensity (converted to lbs CO2
e/MWh)
Percentage of Retail Sales Covered by Retired Unbundled RECs
2022 POWER SOURCE DISCLOSURE ANNUAL REPORT
SCHEDULE 3: POWER CONTENT LABEL DATA
For the Year Ending December 31, 2022
East Bay Community Energy
Renewable 100
Instructions: No data input is needed on this schedule. Retail suppliers should use these auto-populated calculations to fill out their Power Content Labels.

Attachment Staff Report Item 13B
2022 POWER CONTENT LABEL
East Bay Community Energy
https://ebce.org/key-documents/
Greenhouse Gas Emissions Intensity
(lbs CO2e/MWh) Energy Resources Renewable
100 Brilliant 100 Bright Choice
2022 CA
Power Mix
Eligible Renewable1 100.0% 35.8% 49.4% 35.8%
Biomass & Biowaste 0.0% 0.0% 1.5% 2.1%
0 0 496 422 Geothermal 0.0% 0.0% 0.8% 4.7%
Eligible Hydroelectric 0.0% 0.0% 1.4% 1.1%
Solar 50.0% 17.9% 18.1% 17.0%
Wind 50.0% 17.9% 27.6% 10.8%
Coal 0.0% 0.0% 0.0% 2.1%
Large Hydroelectric 0.0% 64.2% 21.9% 9.2%
Natural Gas 0.0% 0.0% 0.0% 36.4%
Nuclear 0.0% 0.0% 0.2% 9.2%
Other 0.0% 0.0% 0.0% 0.1%
Unspecified Power2 0.0% 0.0% 28.4% 7.1%
TOTAL 100.0% 100.0% 100.0% 100.0%
Percentage of Retail Sales Covered by Retired Unbundled RECs3: 0% 0% 1% 1The eligible renewable percentage above does not reflect RPS compliance, which is determined using a different methodology. 2Unspecified power is electricity that has been purchased through open market transactions and is not traceable to a specific generation source. 3Renewable energy credits (RECs) are tracking instruments issued for renewable generation. Unbundled renewable energy credits (RECs) represent renewable generation that was not delivered to serve retail sales. Unbundled RECs are not reflected in the power mix or GHG emissions intensities above.

For specific information about this electricity portfolio, contact: East Bay Community Energy 1-833-699-EBCE (3223)
For general information about the Power Content Label, visit: https://www.energy.ca.gov/programs-and-topics/programs/power-source-disclosure-program Renewable 100 Brilliant 100 Bright Choice 2022 CA Utility Average
0 200
400
600
800
1000
Renewable 100
Brilliant 100
Bright Choice
2022 CA Utility Average
Attachment Staff Report Item 13C
2022 Power Source
Disclosure Annual Report
and Power Content Label
SEPTEMBER 21, 2023
Attachment Staff Report Item 13D
Overview
• What is the Power Source Disclosure Program
• How is the Power Source Disclosure Report (PSDR) prepared • What is the Power Content Label (PCL)
• 2022 Power Content
Attachment Staff Report Item 13D
Power Source Disclosure Program
• All electricity providers in CA are required to submit annual report
• The annual report discloses all electricity purchases for a calendar year
• Reported as MWh by source as a percent of total retail sales • Submitted to the California Energy Commission annually Attachment Staff Report Item 13D
PSDR Preparation
Review CY Data
Data Verification
Internal Review
Submission
Populate PSDR Templates
• RECs
• Carbon Free
• Retail sales by plan
• Content Check
• Executive and Marketing review
• Submit to the CEC
• WREGIS
• Meter Data, E-Tags
• Invoices
• Contracts
• Input by generation source
• Purchased MWh as % of sales
• Individual templates for each plan
Attachment Staff Report Item 13D
Power Content Label
• Required annual disclosure to customers, sent by mail • Contains the power mix for each retail plan and the total CA system power mix
• Allows customers to compare their power content to the total CA power mix and to other electricity providers
• Discloses Emissions from retail plans
• The PCL will be posted online by 10/1 and mailed to customers by the end of 2023
Attachment Staff Report Item 13D
2022 Power Content Label
Attachment Staff Report Item 13D
Questions?
Thank You
Izzy Carson
Power Resources Manager
Attachment Staff Report Item 13D
Staff Report Item 14
TO: East Bay Community Energy Board of Directors
FROM: Kelly Brezovec, Director, Account Services
Contributors: Jin Ruan, Energy Analyst - Financial Modeler Shannon Rivers, Virtual Power Plant Manager
Feliz Ventura, Resilience Programs Manager
Doug Allen, Modeler-in-Chief
Michael Quiroz, Sr Regulatory Analyst
SUBJECT: Informational Discussion on the Net Billing Tariff as a Successor to the Net Energy Metering 2.0 Tariff
DATE: September 20, 2023
__________________________________________________________________ Recommendation
Receive an update on staff plans to address the Net Billing Tariff (NBT) as a successor to Net Energy Metering (NEM) 2.0.

Background
EBCE regulatory staff has been tracking the NEM 2.0 successor tariff, and presented on major developments at the December 2022 Board of Directors meeting. At that time the Commission had not yet finalized their decision. Since then, the Net Billing Tariff was approved on December 15, 2022.

In 1995, the first Net Energy Metering tariff was established through the passage of SB 656.

NEM 1.0 was a tariff favorable to mid-day solar production, such that customers were compensated for generating solar in excess of what they consumed. NEM 1.0 is responsible for starting the annual credit cycle and true-up process, which serves as a mechanism to compensate customers for their solar generation. On a monthly interval, credits are provided to customers at the retail rate that can be used to offset energy usage. Annually, at an event called the “true-up,” the customer is paid out at the Net Surplus Compensation (NSC) rate, which is similar to a market-based rate, for excess solar generation. The customer’s NEM credits then reset and they start again for another 12 month cycle. Customers were granted a 20 year interconnection agreement and a guaranteed 20 years on this tariff, which was available through 2017.

NEM 2.0, the successor to NEM 1.0, is very similar to NEM 1.0, but requires a time-of-use (TOU) rate for all NEM customers where rates differ depending on the time of day. Lower retail rates are mid-day in response to the glut of solar on the grid and higher rates are charged in the late afternoon and early evening when demand peaks and solar production wanes. Usage and generation are netted based on the TOU period. NEM 2.0 customers are also responsible for non-bypassable charges, such as the Public Purpose Programs charge. Annual payouts are provided at NSC rates. Customers on this tariff were given 20 years to remain on NEM 2.0, with the legacy period remaining with the solar system itself. NEM 2.0 was offered to solar systems with applications received from 2017 through April 14, 2023. We can expect NEM 2.0 customers to transition to NBT starting in 2037.

Net Billing Tariff (NBT) is the successor to NEM 2.0. Rather than receive the retail rate for generation that is exported to the grid, customers receive compensation at a new Avoided Cost Calculation (ACC) rate, also called the Energy Export Credit. The ACC is a tool used by the California Public Utility Commission (CPUC) to determine the value of onsite solar and other distributed energy resources.The ACC varies by the hour and the month. Spring and summer mid-day ACC prices are the lowest while late summer early evening prices are the highest. ACC pricing is aligned with historic California Independent System Operator, or CAISO, energy demand and availability. There is a “glidepath” for new NBT customers, which provides a small adder, or increase, to the established ACC rates to help ease the transition from NEM 2.0 to NBT.

See Table 1 for a comparison summary of NEM 1.0, NEM 2.0, and the NBT.

Click here to enter text.Table 1: Summary of NEM 1.0, NEM 2.0, and NBT NEM 1.0
1996-2017
NEM 2.0
2017-Apr.14, 2023
NBT
Apr. 15, 2023 - present
Rate Schedule Any TOU rates (4-9 pm peak
rates)
Residential customers
are required to be on a
TOU Electrification
Rates (4-9pm peak,
3pm-12am partial peak)
Value of solar
used
concurrently on-site
Offsets imports,
equivalent to retail rate
Offsets imports,
equivalent to retail rate
Offsets imports,
equivalent to retail rate
Value of solar
exported to grid
Full retail rate Retail rate minus non-bypassable chargesAvoided Cost Calculation (ACC) price per hour,
with an adder for low
income customers.

Netting
methodology
Imports are netted
against exports
Imports are netted
against exports within
each TOU interval
Imports are charged at
the retail rate, exports
are compensated at
ACC. Energy use is no
longer netted.

Net Surplus
Compensation
(NSC) payment at
true-up
Net exports times NSC
rate
Net exports times NSC
rate
Net exports times NSC
rate, minus ACC export
value already granted
Billing and true-up periodAnnual billing, annual
true-up (both charges
and credits roll over for
12 months)
Annual billing, annual
true-up (both charges and
credits roll over for 12
months)
Monthly billing and
payment; annual true-up
(credits roll over for 12
months)
Legacy Period 20 Years, tied to the
system
20 Years, tied to the
system
9 Years, tied to both the
system AND the
customer as a unit.

California Public Utilities Commission Goals
The California Public Utilities Commission (CPUC) has had a different set of goals with each iteration of the Net Metering Tariff (now, Net Billing Tariff).

NEM 1.0 was developed to promote rooftop solar and diversify the energy resource mix. The tariff favored the midday peak solar production and credited customers at the full retail rate.

While NEM 1.0 was successful at its goal of proliferation of rooftop solar, this is when the state started to grapple with the infamous duck curve that aligned with abundant mid-day solar.

Figure 1: The Duck Curve1
NEM 2.0 was the CPUC’s first attempt to align the compensation structure closer to costs by way of TOU rates configured to match supply. NEM 2.0 also included requirements to pay non-bypassable charges, including a minimum delivery fee.

NEM 1.0 and NEM 2.0 have shown to increase pricing to non-NEM customers by paying an artificially high price for inexpensive mid-day energy generation to NEM customers. The CPUC’s study by Energy + Environmental Economics and Verdant estimates that NEM 2.0 customers annually shift about $2,600 of their energy cost burden to non-NEM customers2 (for both generation and delivery).

NBT is designed to better align generation compensation (the ACC, or avoided cost calculation) for customer-sited solar with the actual net benefits provided to the grid. NBT’s structure encourages on-site battery storage, which could help to flatten the duck curve.

Implementation Schedule
There are two groups of customers that will initially be eligible for NBT:

1. Customers that completed their self-generation application after April 14, 2023 will be automatically placed on NBT.

2. Customers that have completed 20 years on NEM 1.0 will transition to NBT at their next PG&E delivery true-up.
1 From As solar capacity grows, duck curves are getting deeper in California, June 21, 2023 from the U.S. Energy Information Administration at: https://www.eia.gov/todayinenergy/detail.php?id=56880 2 From Cost-effectiveness of NEM Successor Rate Proposals under Rulemaking 20-08-020, May 28, 2021.

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Ava Community Energy Board of DirectorsSeptember 20, 2023

Ava Community Energy Board of Directors
September 20, 2023