Agenda packet — Ava Community Energy Executive Committee, May 7, 2025

Executive Committee Meeting
Wednesday, May 7, 2025
3:00 pm
In Person:

Conference Room 5
Ava Community Energy
1999 Harrison St., Suite 2300
Oakland, CA 94612
Or from the following locations:

Hayward City Hall, 777 B St, Hayward, CA 94541
City of Pleasanton, City Council Office, 123 Main St., Pleasanton, CA 94566 Via Zoom:
https://avaenergy-org.zoom.us/j/88267670367
Or join by phone:

Dial(for higher quality, dial a number based on your current location):

US: +1 669 900 6833 or +1 253 215 8782 or +1 346 248 7799 or +1 301 715 8592 or +1 312 626 6799 or 877 853 5257 (Toll Free) or 888 475 4499 (Toll Free) Webinar ID: 882 676 70367
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 Executive Committee, please email it to the clerk by 5:00 pm the day prior to the meeting.

1. Welcome & Roll Call

2. Public Comment
This item is reserved for persons wishing to address the Executive Committee on any Ava Community Energy-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 Committee are customarily limited to three minutes per speaker and must complete an electronic speaker slip. The Executive Committee Chair may increase or decrease the time allotted to each speaker.

Ava Community Energy
Executive Committee Page | 2

3. Closed Session Public Comment

4. Closed Session
PUBLIC EMPLOYEE PERFORMANCE EVALUATION under California Government Code Section 54957: Performance Evaluation of Chief Executive Officer Howard Chang

5. Report Out of Closed Session

6. Approval of Minutes from March 7, 2025

7. 2025-26 Draft Budget Review (Informational Item)
Review first draft of the fiscal year 2025-26 budget

8. CMF Update (Informational Item)
Update on current status of the Critical Municipal Facilities Portfolio

9. San Joaquin County (SJC) 2026 Enrollment Update (Informational Item) Update regarding SJC enrollment timing and process

10.Committee Member and Staff Announcements including requests to place items on future Executive Committee Agendas

11.Adjourn
The next Executive Committee meeting will be held on Wednesday, June 4, 2025 at 3pm.

Executive Committee Meeting
Wednesday, March 5, 2025
3:00 pm
In Person:

Conference Room 5
Ava Community Energy
1999 Harrison St., Suite 2300
Oakland, CA 94612
Or from the following locations:

Hayward City Hall, 777 B St, Hayward, CA 94541
Via Zoom:
https://avaenergy-org.zoom.us/j/88267670367
Or join by phone:

Dial(for higher quality, dial a number based on your current location):

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

1. (14:10) Welcome & Roll Call

Present: Members: Roche (Hayward), Balch (Pleasanton), Gonzalez (San Leandro), and Chair Andersen (Piedmont)
Not Present: Members Marquez (Alameda County) and Fugazi (Stockton)

2. (16:53) Public Comment
This item is reserved for persons wishing to address the Executive Committee on any Ava Community Energy-related matters that are not otherwise on this meeting agenda. Public Ava Community Energy
Executive Committee Page | 2
comments on matters listed on the agenda shall be heard at the time the matter is called.

There were no speakers for public comment.

3. (17:43) Approval of Minutes from March 7, 2025
The Clerk noted that in Item 7. Approval of Minutes, the following sentence was included in error:
“Member Marquez nominated Member Andersen as Chair and Member Gonzalez as Vice-Chair. Member Roche seconded the nomination. Member Andersen and Member Gonzalez accepted the nomination, which was approved 4/0/0/0/1 (yes/no/abstain/recuse/not present)”
That sentence should have read:
“Member Gonzalez motioned to approve the minutes. Member Marquez seconded the motion, which was approved 4/0/0/0/1 (yes/no/abstain/recuse/not present)” Member Gonzalez motioned to approve the minutes as amended. Member Roche seconded the motion, which was approved 4/0/0/0/2 (yes/no/abstain/recuse/not present)
Yes: Members: Roche, Balch, Gonzalez and Chair Andersen No: none
Abstain: none
Recuse: none
Not Present: Members: Marquez and Fugazi

4. (19:43) Critical Municipal Facilities Update (Informational Item) Update on risks associated with CMF projects
JP Ross provided an update on Ava Critical Municipal Facilities program, which aims to install solar and battery storage at city-owned sites to enhance resilience and reduce energy costs.
(1:03:27) Public Comment – Bradley Cleveland, representing IBEW Local 595 and NorCal NECA, spoke in support of building resilience centers to address climate-related emergencies.

Selected topics discussed by the Executive Committee
• Risks of direct asset ownership
• Feasibility of meeting the NEM 2.0 deadline
• The importance of reconfirming interest from participating cities • Market uncertainty and energy price volatility
Ava Community Energy
Executive Committee Page | 3
• Whether Ava would need to restructure or add staff to manage asset ownership

5. (1:05:47) Local Development Business Fund Review (Informational Item) Review of the Local Development Business Fund.

Annie Hendersen presented a reconciliation of the Local Development Fund from FY 2020 through September 2024, outlining how approximately $105 million in board-approved funding has been spent, earmarked, or remains unallocated.

Selected topics discussed by the Executive Committee
• Request for future updates on individual programs
• The balance between administrative costs (both internal and vendor-based) and funds directly benefiting communities
• The trade-offs between offering customer incentives (e.g., rebates) and investing in complex infrastructure projects (e.g., DC fast charging) • How reimbursable funds (e.g., CPUC grants, loans) are tracked and accounted • What factors (e.g., staffing, interconnection timelines, external approvals) are limiting the speed at which programs and earmarked funds are being deployed

6. (1:35:47) Committee Member and Staff Announcements including requests to place items on future Executive Committee Agendas
There were no committee or staff announcements

7. Adjourn at 4:28pm
The next Executive Committee meeting will be held on Wednesday, April 2, 2025 at 3pm.

Fiscal Year 2025-2026
Draft Budget
Executive Committee
Howard Chang | May 7, 2025
Introduction
2 Background & Discussion
3 • Every year in June, Ava Board of Directors (the “Board”) approves the following fiscal year’s budget • The Budget covers the overall categories of the General Operating Fund:
▪ Revenues from Operations
▪ Energy Operating Expenses
▪ Services to Facilitate Energy Operations
▪ Operational Overhead to Energy Operations
▪ Non-Operating Revenues
▪ Non-Operating Expenses, including a Capital Transfer to the Local Development Fund • The Budget typically goes through a few rounds of review prior to Board approval in June, with a full review in the May Board meeting along with reviews from subcommittees—typically the Finance, Administrative, and Procurement Subcommittee and the Executive Committee • Expenses are typically 90%+ energy related with overhead and Local Development funding accounting for 6-8% of total expenses
How Ava Works—Energy Delivery
• Ava sells energy directly to its customers by procuring energy through various market mechanisms and scheduling delivery into California Independent Service Operator (CAISO) • Ava is not responsible for transmission or delivery of the commodity; this is a service retained by PG&E • Per Ava’s risk management policy, much of the expected load is procured and hedged in advance across energy, RECs, and Resource Adequacy
• Ava schedules it's forecasted load with CAISO on a day-ahead basis and real-time basis • This is done regardless of the amount of energy hedges that Ava has procured • The CAISO is California’s regional market balancing authority whose primary purpose is to keep the energy being pulled off the grid balanced by energy being put on the grid to prevent grid damage or area shortages 4 How Ava Works—Revenues & Rates
• Ava offers two electricity products to customers:
• Renewable 100: 100% of the energy is from renewable resources • Originally set at $0.01/kWh above PG&E and has migrated down as Ava financials improved • Currently priced at $0.0025/kWh above PG&E rates
• Bright Choice: In 2025-26 this will be 81% from renewable energy and large hydro, plus ~10% nuclear • Originally set at 1.5% discount to PG&E, reduced to a 1% discount in 2021,increased to a 3% discount in 2022 • The latest adjustment was to a 5% discount to PG&E rates in 2023 • The current percent load of Bright Choice customers is ~72% for FY 2026 5 How Ava Works—Billing Cycle
• Revenues are made from sales of energy to customers based on generation rates that are indexed to PG&E cost of service rates as approved by the CPUC
• PG&E will read Ava customer meters to monitor consumption. These reads are then reported to Ava and its Billing data manager
• The consumption data is processed to generate billing amounts based on Ava’s rates and then sent back to PG&E, who then issues the bills and collects payments on Ava’s behalf • PG&E's bundled customers and unbundled (Ava) customers also pay a power charge indifference adjustment (PCIA) and minor system fees. These are collected by PG&E from customer revenues and retained prior to payment distribution to Ava.
o Additionally, all PG&E bundled and unbundled customers are charged a Transmission & Distribution cost • A billing cycle is typically about three months, meaning it takes about three months for Ava to receive payment from a customer’s consumption
• Consumption occurs in the first month
• A bill is issued in the second month
• Payment is due in the third month
6 PCIA Update
7 How Ava Works—Power Charge Indifference Adjustment (PCIA) • Ava’s generation rates to customers are indexed to PG&E’s generation rate • A portion of PG&E's generation rate is a pass-through charge to PG&E for the PCIA • The PCIA is how PG&E recovers/credits "stranded costs" for legacy generation resources • PCIA rates are based on an annual mark-to-market
• For Energy, Resource Adequacy (RA), and Renewable Portfolio Standard (RPS) resources, the mark-to-market is against "Market Price Benchmarks" (MPBs)
• Forecasts for the MPBs are presented by the Investor-Owned Utilities (IOUs) in May. This is a preliminary outlook of rates and PCIA for the next year
• MPB actuals-to-date are delivered in October and are used to establish the next year’s rates • PCIA and rates are "trued up" from forecast to actual, and any overcollection or under-collection is recovered in rates the following year.
• Higher MPBs higher IOU rates and lower PCIA = more operating headroom for Ava • Lower MPBs lower IOU rates and higher PCIA = less operating headroom for Ava 8 Portfolio
Costs
Portfolio
Value*
Stranded
Costs/credit
*Value calculated using “Market
Price Benchmarks” (MPBs)
Cal. Pub. Util. Comm'n (CPUC) Revisions to MPBs?
According to a February CPUC Staff Report:
• The current RA MPB overstates the market value of the PCIA portfolio RA products, because it:
o Reflects an insufficient number of transactions to provide a robust valuation o Includes transactions that may not purely reflect market value such as affiliate transactions, swaps, and sleeves • The PCIA methodology artificially inflates RA costs attributed to bundled customers and effectively requires bundled customers to pay unbundled customers for the use of the IOU’s resources • The CPUC has opened a new rulemaking to consider MPB changes.

Specific changes under consideration are:
• Include all transactions applicable (not just transacted) for a given delivery year • Combine different types of RA MPBs (flex, local, system) into a single MPB • Exclude affiliate, swap, and sleeve transactions
• Use monthly, or seasonal, values for MPBs
• The CPUC plans to implement any changes in time for the October update, to take effect January 1, 2026.

This rulemaking introduces considerable uncertainty into Ava's budget process! • These possible methodology changes will increase PCIA and decrease rates beginning January 2026 9 The CPUC's PCIA Process – Key Dates
• PG&E makes 2026 ERRA forecast filing - 5/15/25
• PCIA Rulemaking Phase I RA MPB proposed decision -
▪ 5/13/25 or
▪ 5/27/25
• PCIA Rulemaking Phase I RA MPB final decision -
▪ 6/12/25 or
▪ 6/26/25
• 2026 ERRA Forecast "October update filing" - 10/15/26 • 2026 ERRA Forecast final decision - 12/18/25
• New rates go into effect - 1/1/26
10 The "ERRA Forecast
proceeding" at the
CPUC results in PCIA
and PG&E generation
rates for the following
year. In this case, 2026.

Impact of Potential PCIA Reform on Revenues
• If implemented in calendar year 2026, the impact
from the PCIA Reform is estimated to reduce
revenues by approximately $187MM
▪ This reduction is based on retroactive adjustments to the 2025 RA MPBs used in the PCIA calculation
• About $79MM would be realized in the first half
(January – June 2026), which is in the proposed
budget fiscal year
• The remaining $108MM would be realized in the
second half (July – December) and would impact the
next fiscal year (FY 2026-2027)
▪ The third calendar year quarter (July – August) is
expected to have the largest effect ($58MM)
11 35,086,000
79,200,000
137,648,000
186,819,000
-
50,000,000
100,000,000
150,000,000
200,000,000
250,000,000
300,000,000
Q1 Q2 Q3 Q4
Comparative Revenue Performance & Impact of Reform
Upside PCIA Reform Difference Cumulative
Market Price Benchmark Trends 2023-2027
12 • In addition to changes in the PCIA calculation methodology, we are also seeing a softening of prices RA Market Price Benchmark
Brown Power Market Price Benchmark
RPS Adder
Expected Market Environment & Impact to Rates/PCIA
• Currently RA and RPS prices are softening in 2025
• Current market fundamentals are likely to set rates lower and the PCIA higher for the 2026 calendar year • Potential changes to the PCIA methodology will likely further increase PCIA and decrease rates, lowering Ava’s headroom
• For this presentation, two budgets will be considered:
▪ Upside Budget: Rates and PCIA are only affected by changes to market condition MPB’s with no PCIA reform ▪ PCIA Reform Budget: Rates and PCIA are affected by CPUC rulings and market condition MPBs 13 2026-U is the Upside Scenario
2026-R is the PCIA Reform Scenario
0 50
100
150
200
250
300
$/MWh
Month
NP15 Prices from June 2018 through June 2027
with P5-P95 Variance Band from May 2025
Forward
P95 P5 NP15 Prices Annual Avg
0 0.02

0.04 0.06

0.08 0.1

0.12 0.14

0.16 2019 2020 2021 2022 2023 2024 2025 2026-U 2026-R
$/kWh
Fiscal Year
Customer Rate Revenue Profile
Ava Average Rates PCIA Fees Operating Expense Margin
2025-26 Draft Budget
14 Draft Budget Summary
• In the face of this uncertainty, Ava continues to serve our local community and customers with cost competitive & cleaner energy while providing local jobs and equitable programs • Rates have increased and PCIA has decreased since 2021, driven by historic increases in market energy prices starting in 2021. We are seeing some stabilization in energy costs, though overall costs remain elevated.

Calendar year 2026 is forecasted at a reduction in energy market prices and rates relative to 2025. • The 2025-26 budget process has required planning for greater uncertainty due to California regulatory activity
• We modeled multiple scenarios and stress tested our operating budget. There exists a potential ruling with the CPUC that would create a material adjustment to calendar year 2026 PCIA based on retroactive recovery on 2025. In this draft budget we present two scenarios that we view as most likely, though actual results will vary based on market volatility and PCIA-related reform:
• "Upside" Budget scenario reflects status quo PCIA setting methodology with forecasted market conditions • "PCIA Reform" Budget scenario reflects impact from anticipated CPUC ruling on PCIA reform expected in June 2026 and to be implemented in 2026. In this scenario, staff has incorporated recommendations to mitigate the financial deficit and seek board feedback on other potential actions. • There is a high degree of uncertainty at this stage and we expect to have more confidence in the June timeframe on CPUC action
15 Draft Budget Fiscal Year 2025-2026
16 • Current fiscal year budget is presented along with an "Actuals" column reflecting incurred actual costs
through March 2025 and projected costs for the final
quarter
• 2026 "Upside" revenues reflect forecasted changes to
rates and PCIA given changes to market conditions
only
• 2026 "PCIA Reform" revenues reflect the changes to
market conditions and includes the impact from the
potential CPUC ruling with PCIA reform
• 2026 "PCIA Reform" budget results in a deficit of
negative $5.2MM and further actions would be taken
to ensure a neutral to positive Net Position.

Adjustments that are currently incorporated include:
▪ PCIA Reform Budget has reduced Personnel Costs in the Overhead Operating Expenses for lower incremental hiring ▪ PCIA Reform Budget has a $10MM Local Development
contribution in Non-Operating Expenses
AVA COMMUNITY ENERGY FY 2025 FY 2025 FY 2026 FY 2026

BUDGET ACTUALS UPSIDE PCIA REFORM

OPERATING ACTIVITY
TOTAL OPERATING REVENUE 872,854,000 926,835,000 993,564,000 915,155,000

EXPENSES & OTHER USES
Cost of Energy 760,248,000 760,682,000 861,043,000 861,043,000 Cost of Energy Services 11,608,000 11,726,000 14,379,000 14,379,000 Total Energy Operating Expenses 771,856,000 772,408,000 875,422,000 875,422,000 Total Overhead Operating Expenses 44,868,000 36,410,000 50,317,000 48,343,000 TOTAL OPERATING EXPENSES 816,724,000 808,818,000 925,739,000 923,765,000

NON-OPERATING ACTIVITY
TOTAL NON-OPERATING REVENUE 11,449,000 19,160,000 14,767,000 14,767,000 TOTAL NON-OPERATING EXPENSES 25,300,000 23,632,000 26,207,000 11,397,000 NET NON-OPERATING POSITION (13,851,000) (4,472,000) (11,440,000) 3,370,000 TOTAL NET REVENUES 42,279,000 113,545,000 56,385,000 (5,240,000) Budget Uncertainty and Risk Mitigants
• To mitigate a potential deficit in 2025-2026 and 2026-2027 there are a variety of options to consider:
o Adjustments to the customer value proposition (Bright Choice rate discount and R100 Premium)
o Adjustments to renewable energy and large hydro procurement targets - implement procurement periods, adjustment of
procurement floors to minimize over-procurement
o Adjustments to local development funding
o Adjustments to personnel hiring
o Allocating 2024-25 budget surplus to Rate Stabilization Fund to release in 2026-27 timeframe
• Future forecasts (2027 and beyond) are highly uncertain at this time due to market conditions and PCIA reform. There are some probably scenarios in which Ava runs a material deficit in the 2026-27 fiscal year. The scenarios are indicative downside scenarios.
17 AVA COMMUNITY ENERGY FY 2027 FY 2027

UPSIDE PCIA REFORM

OPERATING ACTIVITY
TOTAL OPERATING REVENUE 871,419,000 757,262,000

EXPENSES & OTHER USES
Cost of Energy 904,763,000 904,763,000
Cost of Energy Services 15,754,000 15,754,000
Total Energy Operating Expenses 920,517,000 920,517,000 Total Overhead Operating Expenses 54,228,000 52,056,000 TOTAL OPERATING EXPENSES 974,745,000 972,573,000
NET OPERATING POSITION (103,326,000) (215,311,000)

NON-OPERATING ACTIVITY
TOTAL NON-OPERATING REVENUE 16,009,000 16,009,000
TOTAL NON-OPERATING EXPENSES 26,390,000 11,460,000
NET NON-OPERATING POSITION (10,381,000) 4,549,000
TOTAL NET REVENUES (113,707,000) (210,762,000)
Note: For simplicity all revenue and cost
assumptions for both scenarios for FY 25-26 are
carried over for FY 26-27
Draft Budget Scenario Assumptions
• Revenues assume no changes to value proposition under both scenarios. Ava maintains 5% discount to PG&E for its Bright Choice customers and a 0.25 cent premium for its Renewable 100 customers • Additionally, net revenues assumes Ava maintains a 1% uncollectable rate • Energy costs are derived from a blend of contracted and open positions for all attributes. Also assumes market prices behave at expected volatility throughout the year. Open prices are non-stressed, mean-forecasted market prices. • Both scenarios also assume no changes to Ava’s renewable and carbon free energy targets: 81% carbon free targets for both 2025 and 2026 calendar years • Both scenarios also assume San Joaquin County begins service in March of 2026 (to be finalized) • No draws on credit facility or reserve funds are assumed • No recognition of GASB 62 revenue ($57.6MM)
• Non-operating revenue assumes an average of 3.5% interest rate earned through the fiscal year 18 UPSIDE BUDGET
• Personnel headcount has 14 additional
needed staff for expanding operations
• Local Development allocation is $25MM

PCIA REFORM BUDGET
• Personnel headcount has 7 incremental
additional staff
• Local Development allocation is $10MM
Draft Budget: Fiscal Year Revenue Scenarios
AVA COMMUNITY ENERGY FY 2025 FY 2025 FY 2026 FY 2026

BUDGET ACTUALS UPSIDE PCIA REFORM

OPERATING ACTIVITY

REVENUE & OTHER SOURCES
Electricity Sales 881,671,000 924,006,000 1,003,600,000 924,399,000 Uncollectables (8,817,000) (9,017,000) (10,036,000) (9,244,000) Other Operating Revenue 0 11,846,000 0 0
TOTAL OPERATING REVENUE 872,854,000 926,835,000 993,564,000 915,155,000 19 • Difference in revenues between the two scenarios for FY 2026 is driven by the potential impact from PCIA Reform decision at CPUC (~$79MM for Jan 2026 – Jun 2026) • No change to value proposition under both scenarios
• Bright Choice: 5% discount to PG&E.
• Renewable 100: Premium of 0.25 cents to PG&E
• Uncollectable rates are maintained at 1% of sales
• No planned recognition of GASB 62 deferred revenue balance ($57.6MM) • Other Operating revenue in FY 2025 related to damages for project delays Draft Budget: Fiscal Year Revenue Scenarios
20 At the current 2025 load distribution:
• 1% change in the Bright Choice value
proposition results in a fiscal year change
of $7.2MM
• 0.25 cent change in the Renewable 100
value proposition results in a fiscal year
change of $5.6MM
• The following table evaluates the
respective value proposition changes on
revenues for the first and second half of
the fiscal year separately
Fiscal Year 1% ∆ BC 0.25 Cent ∆ R100
First Half 4,169,000 2,745,000
Second Half 3,009,000 2,873,000

0.078 0.082 0.072 0.083

0.132 0.145 0.135

0.119 0.110

0.026 0.030 0.038

0.037

0.012

0.006

0.008

0.007 0.015
0 0.02

0.04 0.06

0.08 0.1

0.12 0.14

0.16 2019 2020 2021 2022 2023 2024 2025 2026-U 2026-R
$/kWh
Fiscal Year
Customer Rate Revenue Profile
Ava Average Rates PCIA Fees Operating Expenses Margin
Carbon Free & Renewable Procurement Schedule
21 • In April 2022, the Board approved
the “Path to Zero by 2030” for the
Bright Choice product, as shown
in the table to the left
▪ Carbon Free percentages reflect
renewable and large hydro energy
• In previous years, the Board has
approved an increase to carbon
free procurement targets
• June 2024, the Board approved an
additional 5% to calendar year
2025 targets; increasing from
76% to 81%
Year Path Target Increase Updated Target Increase Updated Target Increase Updated Target Increase Updated Target 2022 63% 5% 68% -- -- -- -- -- --
2023 66% 5% 71% 5% 76% -- -- -- --
2024 71% 0% 71% 10% 81% 0% 81% -- --
2025 76% 0% 76% 0% 76% 5% 81% 0% 81%
2026 81% 0% 81% 0% 81% 0% 81% 0% 81%
2027 85% 0% 85% 0% 85% 0% 85% 0% 85%
2022 2023 2024 2025
Optional Procurement Target Adjustments
• In order to address any deficit concerns, Ava can
consider adjustments on the procurement targets
• Implementation of multi-year Compliance Periods
to allow for variability of renewable energy and
large hydro generation year to year
o With 3-year compliance periods that match the
formal California RPS compliance periods, Ava
can reduce costs associated with over-procurement of green attributes by creating a balancing mechanism across the period
• Ava can consider adjusting procurement targets in
the absence of compliance periods as well
22 • The 2024 Power Content Label is
currently being finalized and the latest
estimate indicates Renewable and Large
Hydro energy procurement of ~93%
GASB 62: Revenue Deferred Balance
23 • The GASB 62 Revenue Deferral Fund was
established by Resolution R-2020-26
• Staff is currently evaluating a formalized
Rate Stabilization Fund Policy for review
• Contributions and Recognitions have been
tracked since inception
• Current balance is approximately $57.6MM
• ~$10.5MM is retained for long term
renewable costs to be recognized in 2027
• ~$15.0MM is retained for Net Billing Tariff
incentives from net revenues from FY 2024
• ~$32.1MM is retained for rate stabilization
purposes
FY Contribution Recognition BalancePurpose
2020 12,680,000 - 12,680,000
Stabilize Local Development balance until Fund
is established by Reso R2020-26
2021 15,814,000 12,680,000 15,814,000
Recognized LD balance with fund establishment
via Budget. Contributed to PCIA PUBA balance
through December 2023 as allocated by Audit
2022 - - 15,814,000
2023 37,200,000 - 53,014,000
~$10.5MM each for on-bill credits and PPA
premium plus $16.2MM for rate stabilization as
allocated by audit and Resolution R-2023-37
2024 - 10,504,837 42,509,163
Recognition is for on-bill credits, by Resolution
R-2023-58
2025 37,407,824 22,316,492 57,600,495
Contribution for on-bill credits and NBT from
surplus revenue as allocated by audit and
Resolution R-2024-2. Recognition is net on-bill
credits by Resolution R-2024-73.
2026 - - 57,600,495
2027 - 10,504,837 47,095,658
Recognition is for PPA premium contribution
from 2023, by Resolutions R-2023-58 and R-2024-26
2027 - 14,963,130 32,132,528
Possible recognition of NBT incentives
contributed in FY 2025
Draft Budget: Overview of Operating Expenses
AVA COMMUNITY ENERGY FY 2025 FY 2026 FY 2026

BUDGET UPSIDE PCIA REFORM

EXPENSES & OTHER USES
Cost of Energy 760,248,000 93.1% 861,043,000 93.0% 861,043,000 93.2% Cost of Energy Services 11,608,000 1.4% 14,379,000 1.6% 14,379,000 1.6% Total Energy Operating Expenses 771,856,000 94.5% 875,422,000 94.6% 875,422,000 94.6% Overhead Operating Expenses
Personnel 26,592,000 3.3% 31,637,000 3.4% 29,663,000 3.2% Marketing & Communications 6,168,000 0.8% 4,372,000 0.5% 4,372,000 0.5% Legal, Policy, & Regulatory Affairs 4,104,000 0.5% 4,055,000 0.4% 4,055,000 0.4% Other Professional Services 2,136,000 0.3% 3,423,000 0.4% 3,423,000 0.4% General & Administrative 5,868,000 0.7% 6,830,000 0.7% 6,830,000 0.7% Total Overhead Operating Expenses 44,868,000 5.5% 50,317,000 5.4% 48,343,000 5.2% TOTAL OPERATING EXPENSES 816,724,000 100.0% 925,739,000 100.0% 923,765,000 100.0% 24 • Expenses are divided into three overall
cost center categories:
• Energy Operations which includes all
energy, energy attributes, and ancillary
related costs and required management
services such as scheduling, data
management, and customer billing
▪ This category comprises nearly 95% of Ava’s
total operating expenses
• Overhead Operations which includes all
personnel and staffing needs as well as
work function cost centers required to
manage the organization at large, and is
about 5% of total operating expenses
• Non-Operating Expenses, which are all
capital and capital transfer related costs,
includes the local development budget.

This category is presented and discussed
in a later slide
Draft Budget: Fiscal Year Energy Operations
25 Energy Costs
• Costs are derived from a blend of contracted
and open positions for all energy, attributes,
and RA
▪ Open prices are non-stressed, mean-forecasted
▪ FY 2026 overall prices are expected to be about
13% higher than FY 2025 on average
▪ Material increases in Open and RA costs
• Carbon Free targets are 5% above baseline
targets in calendar year 2025 at 81% and
maintained at baseline target in calendar year
2026 at 81%
• Note: While the last year maintained stabile
market prices, we are still in a period of
historically high brown power prices with FY
2026 prices projected at 70% above 10-year
average, and expected to increase in later
years
AVA COMMUNITY ENERGY FY 2025 FY 2025 FY 2026 FY 2026

BUDGET ACTUALS UPSIDE PCIA REFORM

EXPENSES & OTHER USES
Cost of Energy 760,248,000 760,682,000 861,043,000 861,043,000 Cost of Energy Services 11,608,000 11,726,000 14,379,000 14,379,000 Total Energy Operating Expenses 771,856,000 772,408,000 875,422,000 875,422,000 Approx. 25.3% of cost is with open positions to the market. This gives up to $70MM of potential cost increases from market risk PPAs Hedges Open Resource
Adequacy
RECs Carbon Free
FY 2026 Budget to FY 2025 Actuals by Attribute
FY 2025 FY 2026
Draft Budget: Fiscal Year Overhead Operations
26 Material Overhead Items for FY 25-26:
• Two separate Personnel cost scenarios are presented. This is discussed in more detail on the proceeding slide.
• Marketing costs are established to be in-line with current fiscal year actuals • Legal, Policy, & Regulatory Affairs are established in-line with current budget year as some expected litigation legal expenses were deferred
• Professional services are expected to increase as Ava continues to fill out operational needs • G&A is expected to increase also due to continued growth of operations, but continues to be less than 1% of total Operating Expenses AVA COMMUNITY ENERGY FY 2025 FY 2025 FY 2026 FY 2026 BUDGET %OpEx ACTUALS %OpEx UPSIDE %OpEx PCIA REFORM %OpEx Overhead Operating Expenses
Personnel 26,592,000 3.3% 22,326,000 2.8% 31,637,000 3.4% 29,663,000 3.2% Marketing & Communications 6,168,000 0.8% 4,420,000 0.5% 4,372,000 0.5% 4,372,000 0.5% Legal, Policy, & Regulatory Affairs 4,104,000 0.5% 2,371,000 0.3% 4,055,000 0.4% 4,055,000 0.4% Other Professional Services 2,136,000 0.3% 1,981,000 0.2% 3,423,000 0.4% 3,423,000 0.4% General & Administrative 5,868,000 0.7% 5,309,000 0.7% 6,830,000 0.7% 6,830,000 0.7% Total Overhead Operating Expenses 44,868,000 5.5% 36,407,000 4.5% 50,317,000 5.4% 48,343,000 5.2% Draft Budget: Fiscal Year Personnel Details
27 • FY 2024 Budget was set for 15 additional FTE (83 total) and FY 2025 Budget was set for 15 additional FTE (98 total) to expand on internal expertise, build more depth, and help scale operations further. • FY 2026 Budget seeks to add 7 - 14 additional FTE (105 - 112 total) to continue addressing increased workflow in key areas and meet essential business needs. ▪ Proposed additional hires have been separated to align with the two budget scenarios presented • PCIA Reform (7): 3 Power Resources, 2 Operations, 1 Local Development, 1 Marketing • Upside (14): In addition to PCIA Reform 2 Local Development, 2 Legal/Policy, 1 Marketing, 1 Operations, 1 Power Resources
• Compensation Adjustments:
▪ COLA: 3%; Promotions/Wage Adjustments: 3%; Merit-based Compensation: 13% • Note: In 2023-2024, Ava adjusted compensation structure to standardize pay scales and create merit-based compensation to reduce pay bias in salaries as a DEI initiative 2025 2025 2026 2026 PERSONNEL BUDGET %Cost ACTUALS %Cost UPSIDE %Cost PCIA REFORM %Cost Salaries & Wages 19,765,000 74.3% 16,207,000 80.5% 24,702,000 78.1% 23,159,000 78.1% Health Care/Benefits 3,961,000 14.9% 1,616,000 8.0% 3,458,000 10.9% 3,242,000 10.9% Retirement 2,450,000 9.2% 2,032,000 10.1% 2,951,000 9.3% 2,767,000 9.3% Payroll Expenses 416,000 1.6% 284,000 1.4% 499,000 1.6% 468,000 1.6% Total Personnel Costs 26,592,000 100.0% 20,139,000 100.0% 31,610,000 100.0% 29,636,000 100.0% AB 2561: Ava FY 24-25 YTD
28 FY 2024 - 2025 Budgeted Headcount
Total Active FTE Budgeted 98
New FTE Budgeted 15
New FTE Filled to date 10
Average Time to Hire 82 Days
Vacancy Rate 33%
Retention Rate 94%
Average Turnover Rate 6%
*For recruitment, only new budgeted positions are
included. This does not account for other roles, like
backfill positions.
*Reporting Period: FY 24-25; July ‘24 - April ‘25 (YTD at time of report)
*Average Time to Hire: Days from role posted to start
date.
*FTE: Full-time employee; YTD: Year-to-date
Ava has a strong retention rate of 94%, with only 5 terminations so far this year.

Challenges faced in hiring:
• Finding a great fit can take time, but it’s worth it. ▪ We are prudent in our hiring process, strategically planning the timing of hiring throughout the year, carefully considering all aspects of the role and desired impact.
• Competition for talent is high, especially in the Bay Area What helps us overcome challenges?
• A strategic and robust hiring approach
• Ava is mission-driven
• Ava is a certified Great Place to Work!
▪ Based on the most recent employee engagement survey, 92% of employees say Ava is a great place to work, compared to 57% at a typical US company.

This slide and data presented ensure compliance to AB 2561, which requires local public agencies to present the status of vacancies and recruitment and retention efforts at a public hearing before the governing board of the local agency at least once per fiscal year.

Draft Budget: Fiscal Year Non-Operating Details
AVA COMMUNITY ENERGY FY 2025 FY 2025 FY 2026 FY 2026

BUDGET ACTUALS UPSIDE PCIA REFORM

NON-OPERATING ACTIVITY

NON-OPERATING REVENUE
Interest Income 11,400,000 19,144,000 14,718,000 14,718,000 Grants 0 0 0 0
Other Non-Operating Revenue 49,000 16,000 49,000 49,000 TOTAL NON-OPERATING REVENUE 11,449,000 19,160,000 14,767,000 14,767,000

NON-OPERATING EXPENSES
Borrowing Interest 2,796,000 1,228,000 1,087,000 1,087,000 Local Development Funding 22,404,000 22,404,000 25,000,000 10,190,000 Total Capital Expenditures 100,000 0 120,000 120,000
TOTAL NON-OPERATING EXPENSES 25,300,000 23,632,000 26,207,000 11,397,000 NET NON-OPERATING POSITION (13,851,000) (4,472,000) (11,440,000) 3,370,000 29 Non-Operating Revenue
• Interest Income is based on expected returns
for the managed treasury accounts for reserve
funds and rotating working capital
▪ Rates are estimated at 3.5%
• Other Non-Operating Revenue is rent from the
AT&T tower on the 8th Street building
Non-Operating Expenses
• Borrowing Interest are costs associated with
Ava’s credit facility held with US Bank. This
facility will be up for renewal in October 2025
and current market surveys indicate marginally
more favorable rates
• Local Development Funding is presented as two
options based on budget scenarios and is
discussed in more detail on the following slides
• Capital Expenditures are costs estimated for
tenant improvements at 1999 Harrison St
offices
Draft Budget: Local Development Incremental Funding
Allocation
30 Program Area Upside
Budget
PCIA Reform
Budget
Comments
Ava Charge $5,000,000 $3,000,000 Upside allocation would support expansion to additional cities
Critical Municipal Facilities (CMF) $6,000,000 $0 Upside allocation would support a second future portfolio
Heat Pump Water Heater support $5,000,000 $0 Program funding to support Air District gas water heater phase out
Future Roadmap Funding $5,000,000 $4,000,000 Upside allocation to support 2027 programmatic effort.

PCIA reform allocation could be used for CMF,
expansion of Ava Charge, heat pump support, or future
road map
Consultants for Roadmap $500,000 $500,000 Allocation for external consultants to help inform future roadmap for 2027 forward
Legal expenses $1,500,000 $1,050,000 Expenses associated primarily with Ava Charge and CMF Marketing expenses $2,000,000 $1,640,000 Expenses to support operational programs, such as Ava Charge, Ava Bike Electric, Ava SmartHome Charging, and
the upcoming solar and storage program
Total $25,000,000 $10,190,000
Ava is currently in the execution phase of previously budgeted programs (more details on following slide) and additional strategic planning for future phase implementations is underway Local Development –
FY26 anticipated spend of existing funding
31 Program Area Previously Funded Comments
Ava Charge $1,500,000 Development, Operations and Marketing Critical Municipal Facilities $15,000,000 Capital expenditure and risk mitigation Grants $950,000 Payments for contracted grants
Solar + storage upfront incentives $2,000,000
Incentives and expenses for ongoing programs
Solar + storage ongoing incentives $500,000
Health-e Communities pilot $1,000,000
Building Efficiency Accelerator $1,000,000
Ava Bike Electric incentives $5,000,000
Ava SmartHome Charging incentives $900,000
Total $27,850,000
Next Steps
• Upcoming rate filings and anticipated regulatory proceedings will inform our further development of budget scenarios and recommendations • Review of Draft Budget with the ExComm (5/7), FAP (5/8), and Board (5/21) • Additional review in June with approval at Full board on Wednesday June 18, 2025 • Considerations to evaluate going into the June meetings o Contingent budget approval on both scenarios depending on what CPUC action materials. CPUC actions are anticipated to be resolved before end of calendar 2025, but could delay.
o Bring for a mid-year budget update in December for action depending on CPUC changes
o When reviewing audited results for fiscal year 2024/25 in the fall 2025, consider adjustments to the budget surplus allocation to a rate stabilization fund 32 Critical Municipal Facilities
Executive Committee
May 7, 2025
Agenda
2 1. Transaction Update

2. CMF Program Structure

3. RFP Process

4. Next Steps

1. Transaction Overview
3 Executive Summary • Ava is in the final round of a RFP process to select an EPC Contractor to further negotiate and execute an EPC Agreement to design, construct, and warranty solar and storage systems on up to 12 municipal sites by entering power purchase agreements (“PPAs”) with 6 participating cities. • Ava to own and operate the systems (in lieu of Developer PPA) while levering EPC for project development.
• City project portfolios are designed to provide resiliency benefits to protect against grid outages and extreme weather events, and deliver energy savings and energy hedge over the project term.
• Projects to be constructed to achieve final electrical clearance and NEM2 qualification by PG&E’s April 15, 2026 cliff date.
• Ava to provide 0.5% savings floor to Cities while bearing up to $13.8M in NEM2.0 savings and federal policy risk on City’s behalf. • Ava must execute EPC Agreement and City PPAs in June/July 2025 for NEM2 attainment to be viable.
• Upcoming (May) Board Approval Requests:
1) Authorization to negotiate and execute EPC Agreement with RFP award winner
2) Authorization to negotiate and execute PPAs with Cities and provide Solar and Storage incentives to Cities
4 Cities •Berkeley •Fremont •Hayward •Livermore •Oakland •San Leandro

2. Updates on CMF Program Structure
5 City PPA Overview
Ava to enter long-term energy service agreements with each participating city in which Ava will own and operate the projects. 6 • City PPAs: Ava to enter into individual PPAs with each participating city ▪ Ava to sell energy generation and energy services (e.g. battery for backup energy and savings optimization) to Cities
▪ Ava to deliver construction, operation, and system maintenance (directly or indirectly via Ava’s obligations in the master PPA)
▪ Cities currently confirming participation under revised savings scenarios to make final decision to participate.

The portfolio is likely to become smaller as a result.
• Benefits to Cities:
▪ Resilience through installation of battery at critical municipal facilities to maintain critical site operations during outages and Public Safety Power Shutoff events. Batteries sized to meet critical on-site demands. ▪ Energy hedge: Systems provide energy hedge to sites against rising PG&E costs ▪ Solar / renewables align with Cities’ renewable energy goals ▪ Procurement benefits: Multi-city initiative enables improved commercial terms for Cities relative to single-project development ▪ Trusted counterparty: Ava Board oversight ensures accountability Shift to Ava Ownership & EPC Contractor RFP
As of Feb 2025, Ava has pivoted from negotiating a back-to-back master PPA with a developer to an Ava ownership model to lever an EPC Contractor to develop, construct, and sell the projects to Ava. 7 • Ava previously intended to enter master PPA with Green Bridge to construct, operate, and own the systems and backstop Ava’s obligations of City PPAs.
• With previous developer's withdrawal and NEM2 cliff date in Apr 2026, Ava advancing to develop and own smaller CMF portfolio by entering EPC Agreement with EPC Contractor. • EPC Contractor to backstop key project development and construction obligations of the City PPAs, including:
▪ Project design
▪ Permitting
▪ Equipment procurement
• Ava intends to claim Direct Pay investment tax credit under Inflation Reduction Act to support project capitalization.
• Ava will develop experience in project delivery, project ownership, asset management and capturing ITC
▪ Project construction
▪ Testing, commissioning, and interconnection
EPC Contractor RFP Overview
• Over past 2 months, Ava has designed and run an accelerated RFP to select the EPC Contractor.
• Ava has engaged with TerraVerde (SF-based owner’s rep energy consultant specializing in municipal RFPs) to manage the RFP and advise Ava.
• Participation to date:
▪ RFQ: 10 responses
▪ Round 1 Pricing: 6 responses
▪ Round 2 Final Pricing : 3 finalists (post site walks) • Final round bids and interview to be conducted 4/30 – 5/5, with an expected award date of 5/9.
• All finalists have the following qualifications:
▪ 9+ years in business with >40 FTEs
▪ Substantial experience developing/deploying PV+BESS in PG&E territory ▪ Capability to use union labor on the projects
▪ Adequate insurance and bonding capabilities
▪ Indication of being able to support project timelines around NEM2.0 8 RFP Key Dates
RFQ Posted 3/7 Complete
RFP Posted 4/2 Complete
Final Round
Invites Sent
4/18 (to 3
finalists)
Complete
Project site walks
hosted
4/21 – 4/22 Complete
Final bids due 4/30 Complete
Finalist
interviews
5/5 Scheduled
Expected award /
EPC Contractor
selection date
5/9 Forthcoming
Ava BoD meeting 5/21 Forthcoming
EPC Agreement
Execution
EOM May Forthcoming
Ava initiated a design-build contract RFQ / RFP process in March to select an EPC Contractor to construct the CMF portfolio as a public works project
EPC RFP Evaluation Criteria
9 Ava has named the following evaluation criteria in its Request for Proposal.

Criteria Category Description
Experience and Knowledge • Experience and qualifications developing similar projects • Local presence and demonstration of knowledge of local environment and Financial Wherewithal • Company’s financial position w/r/t to ability to uphold warranties & guarantees Insurance and Bonding Capabilities • Ability to procure requirement construction insurance & meet bonding requirements Equipment and Warranties • Quality of proposed equipment & warranties • Focus on ability to mitigate tariff risk through equipment & procurement Cost, Value, and Savings Potential • Proposed project cost and ability to maximize savings to site hosts Project Management and Execution Capabilities • Focus on project schedule to meet key milestones by NEM2 cliff date • Demonstration of project management, coordination, value engineering, etc.

Client References • Reference checks conducted as part of Round 1 responses Labor Plan • Ability to meet PWA; relationships with union • Ability to comply with Ava’s Workforce and Environmental Justice criteria Ability to accept proposed commercial and legal
terms
• Review of comments on Ava’s draft EPCA
• Focus on ability to provide
Clarity, Completeness, Conformance, Suitability, &
Creativity of Proposal
• Addressed prompts comprehensively and conformed to the format • Demonstrated ability to meet the project objectives
Other capabilities • E.g. ability to provide O&M services and/or extended warranties Transaction Diagram
10 [TBD via RFP]
EPC Contractor
Ava
System Owner & PPA
Seller
Participating
Cities
(multiple)
EPC Agreement City PPA
(Various)
Engineering, procurement,
& construction services
Energy delivery & services
energy services
System cost ($) Monthly payment ($)
Lunar
Prospective grid
services platform
MSA
Platform &
capacity
fees ($)
VPP-enabling
software
services
[Prospective grid services
agreement]
DER capacity commitment
Payment / incentive ($)
Structural Summary

1. EPC Contractor and Ava enter master EPC
Agreement. EPC designs & constructs projects;
Ava purchases and operates the projects.

2. Ava enters Power Purchase Agreements (“City
PPA”) with each participating City as final
offtaker.

3. Ava enters O&M Agreement with O&M Service
Provider to maintain the systems over the PPA
term.

4. Ava maintains optionality to enter future grid
services arrangements with Cities.

Ava to own and operate the projects, while levering third-parties to perform development, construction, and maintenance services. [TBD]
O&M Service Provider
O&M Agreement
Operations &
maintenance services
Monthly payment ($)
Ava Passing Through Incentives to Cities
11 Ava has existing CMF budget that can be applied towards Solar & Storage incentives, similar to upcoming Ava Resilience Hub incentives.
• All projects will receive an incentive of
$2/month/kWh of aggregate BESS nameplate
capacity for 5 years.
• If schedules are not met, NEM3.0 projects will
also receive an upfront incentive of $400/kWh to
account for lower bill savings.
• Incentive to be passed to Cities as a monthly bill
credit on City PPA invoices from Ava for a 5-year
credit term.
“Ava BESS Incentive” represents total incentive to be paid on monthly basis over 5 years.

Specific amounts above subject to change based on final as-built BESS capacities for the projects.

PPA Pricing to Ensure City Savings
12 Ava’s pricing construct ensures each City achieves at least a minimum level of energy savings and resilience benefits, factoring each City’s utility bill savings after PPA payments and Ava incentives.

City Savings Calculation
Estimated site utility costs during term without projects (-) Estimated site utility costs during term with projects = Estimated City utility bill savings
(+) Ava BESS incentives
(-) cumulative PPA payments for the projects
= Cumulative net energy bill savings to City
Site list and capacity figures to be finalized as part of EPC designs Total 25-year energy savings for 12 sites across
6 Cities: ~$130,000
Ava Financial Risk / Return Profile
13 Ava expects to attain cash-flow positivity on its investment after consideration of project revenues, capital expenditures, and 25-year operating expenses. Ava faces material policy risk (ITC/tariff) and development risk that may impact returns.

Ava Risk
Risk Scale
($)
Missing NEM2.0 deadline for projects $(6.0)M
Tariff risk on project equipment5 $(4.4)M
Increased CapEx from EPC $(0.9)M
Risk of repeal of ITC / Direct Pay
provisions1
$(3.6)M
$ Ava at-risk if all events occur $(14.9)M
Nominal CF to Ava if all risks occur6 $(9.7)M
1Assumes 40% Direct Pay (30% base credit + 10% Energy Communities bonus credit) and $8.9M eligible ITC basis.
2 "Net CapEx after ITC Proceeds" means total upfront project costs, less Expected ITC Proceeds. Final CapEx TBD pending final EPC Contractor award through RFP. 3 "Net Cash Flows to Ava" means the sum of expected 25-year City PPA revenue for the projects less the sum of 25-year estimates expenses related to operations & maintenance, project insurance, non-warranty equipment replacements, decommissioning, & other Ava operating overhead for the projects.
4 "Present Value of Net Cash Flows to Ava" assumes a 6% discount rate to the annual cash flows from Net Cash Flows to Ava, which assumes a return with slight premium to municipal cost of debt.

Scenario
Maximum ITC
Proceeds1
Net CapEx after ITC
Proceeds2
40% ITC to Ava $3.6M $5.3M
No ITC to Ava $0M $8.9M
Scenario
Nominal Net Cash
Flows to Ava3
Present Value of Net Cash
Flows to Ava4 @ 6%
discount rate
40% ITC to Ava $5.2M $0.1M
No ITC to Ava $1.6M $(3.5)M
5Tariff subject to federal policy variability. Assumes average 100% tariff on CapEx being 50% equipment.
6$(9.7)M = $5.2M nominal 25-year net CF to Ava less $14.9M $ Ava at-risk if all events occur
Table above excludes potential liquidated damages Ava may recover under EPC Agreement negotiations.

Labor Commitments
14 As part of RFP evaluation criteria, Ava is requiring that Contractor comply prevailing wages and apprenticeship and has prioritized use of union labor.
• Prevailing wages: Commitment to pay prevailing wages across all projects.
• Use of union labor: All three RFP finalists have agreed to use union labor on labor to construct the projects.
• 2 Contractors are signatory contractors with IBEW 595 (Alameda County) and IBEW 6 (San Francisco County)
• Third contractor has agreed to use Union Labor and comply with Ava's Workforce and Environmental Justice Project
Selection Criteria for projects under 20MW including hiring locally and from disadvantaged communities

3. Key Counterparties
15 RFP Advisor:

TerraVerde
• San Francisco-based owner’s representative energy consulting firm proudly supporting clients with the design and deployment of energy projects and programs
• Supported the successful implementation of over $500 million in solar and battery energy storage systems since 2009.
• Focus on supporting municipal agencies with reducing operational costs, supporting over 140 public entities on over 260 energy project assessments and procurements.
• California clients have included the Alameda County Water District, Contra Costa Water District, and the City of Lathrop, amongst many more.
• For Ava’s EPC Contractor RFP, TerraVerde has supported RFP structuring, advisory, and process management
16 EPC Contractor, Equipment, Operations, & Warranties
• Engineering, Procurement, and Construction Contractor: TBD through RFP
▪ Required workmanship warranty: 2 years
▪ Required roof warranty: 10 years
• Major Equipment
▪ Manufacturer and country of original to be further diligence as part of RFP • Solar modules: Minimum 25 year warranty
• Battery energy storage systems: Minimum 10 year warranty • Inverters: Minimum 5 year warranty
• Operations & Maintenance: TBD through RFP
▪ Ava assessing EPC Contractor’s ability to provide O&M and extended warranty as RFP decisioning criteria
17 Other Third-Party Advisors
• Outside counsel: Ava representation and transaction
document drafting by Wilson Sonsini, a leading renewable energy and clean technology law firm.
• Energy modeling: Project site assessment verification services provided by EcoMotion, an experienced
consultancy with specialty in microgrid resiliency projects. • Independent Engineering: Technical and engineering
advisory by NV5, a leading consultancy in the environmental and energy space.
18 Program structure and project consultation has been supported by best-in-class advisory.

4. Next Steps
19 Next Steps & Timing
Key milestones
• Mid May: Award RFP to EPC Contractor
• EOM May: Execute EPC Agreement; commence final design • June-July 2025: Execute City PPAs following remaining City approval process ▪ Note that City PPA approvals follow Ava EPC signing and will incur out of pocket expenses if cities do not end up approving the PPAs
• Q2 – Q4 2025: Permitting and procurement, and construction commencement
• Q1 2026: PV mechanical completion & final electrical clearance • April 15, 2026: PG&E’s NEM2 cliff date to achieve PV final electrical clearance • Q2 - Q4 2026: Complete remaining BESS construction, testing, & commissioning; achieve commercial operation date
20 **Note: Timelines are subject to finalized with final EPC Contractor selected under RFP Appendix – Risk Registers
21 Financial Risk Register (1 of 2)
Risk Sub-Risk or Description
Risk
Level Next Steps / Mitigation
Missing NEM 2.0
Deadline
• If Contractor misses NEM 2.0 cliff dates for project(s), loss of NEM2 export value would deteriorate savings potential for all sites. • Ava would need to materially reduce PPA prices to deliver cost neutrality to Cities
High
• Ability to accept liquidated damages in EPC
Agreement is key decisioning factor for RFP
Tariff Risk on
Equipment
• Recent volatility (and general increases) around tariffs to countries with strong PV and BESS export presence
• Risk of tariffs continuing to change between procurement order and equipment reaching port of entry
High
• Contractor’s supply chain, OEMs, and tariff
mitigation strategy are diligence requests and
decisioning criteria in RFP
• Negotiating termination for cause for material tariff increases in EPCA
Federal repeal of IRA
provisions around
ITC impacting Ava
• Non-zero chance of federal repeal of Inflation Reduction Act provisions that would enable Ava to claim up to 40% investment tax credit via Direct Pay on eligible project costs
High
• Ava pricing City PPAs to minimal savings, with ability to reduce PPA rates to increase savings if Direct Pay
credits can be claimed
Contractor change
orders on project
cost
• Project costs may change as Contractor finalizes technical review and completes 90-100% design Medium
• Ava requesting adherence to 60% designs
• Conducted site walks and requesting pricing
contingencies as part of RFP
City PPA Execution
Timeline
• Ava does not yet have clarity from each City on council approval and execution timelines
Medium
• Pushing cities for short timeline and clarity on
approval timelines
• Proactively engaging City attorneys to condense
execution timelines
Risk Key:
• High = Portfolio at Risk;
• Medium = 3+ Day Delay;
• Low = Low probability &/or 1-2 Day Delay
**Note: Mitigation strategies are subject to further negotiation with EPC Contractor under EPC Agreement Financial Risk Register (2 of 2)
Risk Sub-Risk or Description Risk Level Next Steps / Mitigation City Permitting Approval
Timeline
• Signing/permitting delays risk NEM 2.0 deadline & create an “out” for EPC to pay damages owed for NEM 2.0 delays
• Ava will proceed with design work under EPC Agreement prior to City PPA execution. Medium
• Cities have reviewed 60% designs for projects
• Ava will not proceed past design phase to
procurement until City PPAs are signed. Maximum
potential design phase spend capped at $0.9M
under EPC Agreement.

EPC Agreement
terminates or not
executed
• Ava must successfully execute EPC Agreement to proceed with the portfolio
• In event the EPC Agreement terminates after City PPAs are executed (e.g. due to EPC Contractor default), Ava would need to engage a replacement EPC to proceed with the
projects.

Medium
• Ava to sign EPC Agreement before City PPAs
• Ava has right to terminate City PPAs prior to
Construction Start if EPC Agreement terminates
• Ava to use commercially-reasonable efforts to
replace EPC after Construction Start; otherwise
agreement can be terminated under Ava default
Ava procurement of
O&M Contract
• In lieu of building internal O&M function, Ava will need to sign O&M services agreement to monitor system for billing, and uphold its operations & maintenance and performance guarantee obligations
Low
• Requested O&M and extended warranty pricing from
RFP finalists
• Ava has 9-12 months to run O&M-specific process
as needed before initial projects reach COD
Risk Key:
• High = Portfolio at Risk;
• Medium = 3+ Day Delay;
• Low = Low probability &/or 1-2 Day Delay
**Note: Mitigation strategies are subject to further negotiation with EPC Contractor under EPC Agreement Ava Project Risk Register (1 of 2)
24 Issue Risk(s) Mitigation
Development Timing • Project construction and commissioning runs late, causing certain projects to miss NEM2.0 deadline and/or inconvenience at project sites
• EPC Contractor to owe liquidated damages, which are passed through to Cities in event project does not meet NEM2.0 cliff date.
• If COD is severely delayed, City PPAs may be terminated. Ava’s damages obligations capped at passthrough damages from EPC Contractor Equipment
Performance
• Poor solar or battery performance result in reduced
energy savings delivered to the site
• 85% solar performance guarantee and 92% BESS availability guarantee, with damages payable to Cities if not met
• Ava working to backstop guarantees through its O&M agreement via back-to-back guarantees and/or fulsome SLAs around system maintenance Project Operation &
Maintenance
• Solar or BESS equipment fails or underperforms during contract term
• Ava has modeled City PPA pricing to cash-flow positivity after expected O&M and equipment replacement costs
• Ava to lean on EPC Contractor workmanship and roof warranties during EPC Agreement warranty period
• Ava to enter O&M agreement following EPC Agreement execution to have reputable third-party responsibility for project monitoring and issue resolution Equipment Selection &
Procurement
• Equipment does not meet industry standards around
performance and/or warranty
• Sourcing practices conflict with federal/state/local
regulations
• Ava and its technical consultants vetting RFP shortlisters’ proposed equipment as part of RFP decisioning
• EPC Agreement to require Tier 1 PV and BESS equipment with minimum manufacturer’s warranties
• Ava to have explicit approval rights under the EPC Agreement on OEMs prior to placement of major procurement orders
Project / Portfolio
Termination Rights
• Project terminations or default by City impacts on EPC Agreement
• Project termination or default by EPC Contractor to leave Ava at risk to its City PPA obligations
• Ava requesting termination for convenience in EPC Agreement, along with ability to terminate individual project(s)
• In City PPA, Ava to have right to terminate City PPA prior to construction start if EPC Agreement terminates.

Program has been designed to offer cost-neutral renewable-based energy resiliency for Cities. Ava directly provides services to Cities, while mitigating risk to Ava as owner. **Note: Mitigation strategies are subject to further negotiation with EPC Contractor under EPC Agreement 25 Issue Risk Mitigation
Insurable damage to
System
• Unforeseen installer liability during construction
• Disaster, wildfire, extreme weather, or other insurable event results in system loss during operation
• Ava requiring EPC Contractor to procure construction all-risk insurance during the design & construction phases
• Ava to procure operational all-risk insurance during City PPA operational term
• Force majeure language limits performance obligation
Project Removal • Cities left bearing the responsibility and expense of removing systems from their sites at end of term
• Ava bears obligation to pay for end-of-term project removals • In event Ava loses investment grade status, Ava to post cash or LC security at City’s benefit for use in system removals
Ava Project Risk Register (2 of 2)
Staff Report Item 9
Staff Report Item 9:

To: Ava Community Energy Authority Executive Committee
From: Alex DiGiorgio, Sr. Manager, Public Engagement
Subject: Seeking feedback from the Executive Committee regarding the 2026 enrollment process for customers in unincorporated San Joaquin County Date: May 7, 2025
__________________________________________________________________ Summary/Recommendation
This memo proposes to inform the Executive Committee about the start of Ava service to unincorporated San Joaquin County in March of 2026 and to highlight key considerations supporting this enrollment timeline.

Analysis and Context
On December 20, 2024, the California Public Utilities Commission (CPUC) certified Ava’s Implementation Plan Addendum #4 (IPA4) to begin service to unincorporated San Joaquin County (SJC) in 2026. Per the CPUC’s certification, the earliest Ava may begin serving SJC customers is January of that year. Apart from this condition, CPUC precedent allows community choice aggregators (CCAs), like Ava, broad discretion when it comes to the timing and implementation of service to a new jurisdiction.

For example, Ava’s initial launch of service to Alameda County jurisdictions occurred in phases by customer type (e.g., residential vs commercial) over the course of 2018. Subsequent enrollments (i.e., those for the cities of Tracy, Pleasanton, and Newark in 2021; and for Stockton and Lathrop in 2025) all occurred during April of the year corresponding to the CPUC’s certification of Ava’s previous Implementation Plan addendums.

As discussed in more detail below, Ava staff have identified March as the optimal 2026 enrollment month for customers in SJC.

Staff Report Item 9
When determining the timing, sequence, and implementation of an initial customer enrollment, Ava staff primarily evaluate three criteria: 1) financial impacts; 2) operational efficiency; and 3) overall customer experience. These are discussed in more detail below.

Financial Impacts
To help ensure Ava provides competitive rates to both new and existing customers, staff continuously analyzes the dynamics between retail rates and wholesale power prices.

Consequently, staff aims to enroll new communities during historically lower cost months of the year. This allows Ava to maximize net revenues while minimizing costs to customers.

Based on historical usage data, electricity costs are typically the lowest from February to April.

While energy prices are generally higher during winter months, by March solar and hydroelectric resources are usually abundant, which helps to reduce costs. By late Spring and early Summer, however, customer usage tends to increase as temperatures rise (e.g., due to increased air conditioning); and increased solar output does not align with peak demand, which typically occurs in the early evening hours. As such, staff has identified March as the optimal month for SJC’s enrollment, particularly given the additional considerations discussed below regarding Ava operations and overall customer experience.

Regarding Ava's separate energy capacity obligations (i.e., compliance with the CPUC’s Resource Adequacy/“RA” requirements), March also works well for SJC’s enrollment. This is largely due to the timing of the RA procurement cycle, which occurs on a calendar year basis.

As such, increasing load during the first half of the calendar year does not increase RA costs; it utilizes the RA that has already been procured.

In short, a March enrollment capitalizes on historically lower energy costs without increasing Ava’s near-term RA obligations.

Operational Efficiency
Operational considerations related to Ava’s new community enrollments primarily involve 1) the development and sequencing of required customer notifications; 2) call center coordination and web-based functionality for customer options (i.e., ‘opt outs’ and voluntary Renewable 100 enrollments); and 3) community outreach planning.

Per CPUC rules, Ava is required to send at least two enrollment notices to all eligible customers before their transition to Ava service (as well as two more afterwards). The first two notices are sent to customers during the immediate two months prior to enrollment according to each customer’s billing date. By enrolling in March, Ava will send these notices in January and February of 2026—avoiding the holiday season. This timing would help ensure more customers see their notices, rather than lose track of them during the holidays.

Staff Report Item 9
Similarly, Ava’s marketing and community outreach activities would largely occur after the holidays (i.e., ramping up in January 2026), which would likewise help ensure they meaningfully inform customers about the transition to Ava service. This outreach typically involves a multi-media advertising campaign, as well as participation with local community groups and events.

By focusing on these activities after the holidays (i.e., Jan-April 2026), Ava staff will more effectively engage members of the public and inform them of their new energy options.

Customer Experience
In addition to maintaining competitive rates and increasing the likelihood of successful community outreach, March also provides optimal enrollment timing from a customer-oriented perspective.

Unsurprisingly, Ava’s ‘value proposition’ to customers (i.e., Bright Choice rates that are lower than PG&E’s rates, and Renewable 100 rates that are only slightly higher) is one of the primary reasons communities pursue Ava service in the first place. By enrolling earlier in the year, Ava’s new customers will be able to reap the benefits of Ava’s service sooner. This also includes access to Ava’s customer programs, such as Ava SmartHome Charging for electric vehicles and Ava Bike Electric, an e-bike discount program.

Additionally, by enrolling in March when weather tends to be milder and energy usage tends to be lower, customers are less likely to experience high energy bills and attribute these to Ava service.

South San Joaquin Irrigation District (SSJID): Recommendation to defer enrolling customers within SSJID’s service area to provide time for inter-agency negotiations As Ava prepares to begin service to SJC in 2026, a novel issue has surfaced which will require direction from the Board regarding the enrollment status of approximately 7,000 customers, roughly 10-12% of all eligible SJC accounts located within the overlapping service areas of Ava and SSJID.

For context, SSJID has been seeking to expand its services to include municipal electric service (e.g., similar to Alameda Municipal Power or Sacramento Municipal Utility District) via an eminent domain proceeding of PG&E's local infrastructure. This effort has been twenty years in the making and has slowly made progress—although the timeline and ultimate outcome remain uncertain.

The vast majority of SSJID's service area, customer base, and prospective electric load are located within the cities of Manteca, Ripon, and Escalon—none of which are included within Ava's expanding service area. However, SSJID also serves a swath of unincorporated San Joaquin County which is now preparing to begin service with Ava in 2026. As noted above, this overlap involves approximately 7,000 customers with a corresponding load of about 100 Gigawatt-hours per year (roughly 1.3% of Ava's total, forecasted load for 2026).

Staff Report Item 9
Figure 1: SSJID territory
The question for Ava’s Board to consider: How should Ava proceed with the enrollment of unincorporated SJC, while mitigating the potential cost of SSJID customers departing Ava service if/when SSJID acquires PG&E's infrastructure and begins its electric utility service?
According to SSJID staff and related CPUC filings, SSJID is scheduled to begin litigating the acquisition of PG&E’s infrastructure via eminent domain in June 2025. It is unknown how long this process will take or what the final outcome of it will be. Ava staff have been unable to find any recent examples (i.e., within the last fifty years) of a successful eminent domain proceeding against PG&E to create a municipal utility.

To be clear, Ava’s goal is not to interfere with SSJID's municipalization endeavor; it is simply to serve eligible SJC customers, while exploring risk mitigation strategies that best serve all of Ava's customers and communities. Accordingly, Ava has no intention of retaining customers within SSJID’s service area if/when SSJID acquires PG&E’s infrastructure and launches its municipal utility service.

As such, Ava staff recommends the Board approve the following action: Defer the enrollment of eligible, overlapping Ava/SSJID customers, while Ava and SSJID negotiate risk mitigation strategies for temporary-but-indefinite Ava service and to allow the June Staff Report Item 9
2025 eminent domain proceeding to begin.

To date, Ava staff have held several meetings with SSJID staff and have broadly discussed how Ava might temporarily serve SSJID customers. While Ava and SSJID staff have been unable to resolve how the two agencies would share and mitigate financial risks associated with temporary-but-indefinite Ava service, they will continue to hold more meetings to explore such possibilities.

Ava staff members have also met with San Joaquin County’s Chief Administrator and staff. All parties have expressed a shared desire to avoid undermining SSJID municipalization efforts, while acknowledging Ava’s need to mitigate any financial risks created by temporarily serving customers who may eventually depart when SSJID launches municipal utility service.

Staff recommends Ava defer the enrollment of SSJID customers. Staff and SSJID will attempt to develop a risk-mitigation strategy to allow for temporary Ava service; a deferral will also provide time to understand how and when the eminent domain proceeding may conclude.

Risks vs. benefits of deferring the enrollment of SSJID customers There are risks and benefits associated with deferring the enrollment of overlapping Ava/SSJID customers. These are summarized in the table below:

Risks Benefits
• Equity: These ~7,000 customers
would not have access to Ava’s Bright
Choice rate discount, bill credits,
programs, Solar Billing Plan adders,
etc., unless or until Ava enrolls them
at a later, undetermined time.
• Financial: Ava would forfeit revenues
generated by serving these
customers; and would be doing so
indefinitely unless the Board sets a
deadline for an agreement and/or
future date for enrollment regardless
of the progress made negotiating with
SSJID. Meanwhile, there would be
new operational costs involved with
developing and implementing novel
electronic and administrative
processes to defer SSJID customer
enrollments.
• Equity: If/when SSJID customers
begin municipal utility service
w/SSJID, they could ultimately benefit
from a larger rate discount than what
Ava currently offers through its Bright
Choice option. SSJID estimates a
15% savings on the overall PG&E
electric bill.
• Financial: Ava could avoid the risk of
over procuring power if/when SSJID
customers depart for municipal utility
service following SSJID’s successful
eminent domain proceeding to
purchase PG&E’s infrastructure.

Staff Report Item 9
• Political: Customers within SSJID’s
service area may express frustration
at not having access to Ava service.
• Operations: Ava has not managed a
deferred enrollment based on
geography within municipal
boundaries; there may be fees and
complications associated with
managing a separate customer group
within the County.

Financial Impact
As discussed above, the financial impact of Ava enrolling SJC customers in March 2026 will optimize revenue generation relative to the cost of service, while also considering non-financial factors.

Regarding SSJID’s service area: There is financial risk involved with serving customers that may ultimately depart Ava’s service area for separate municipal utility service. This risk is largely due to the potential over-procurement of wholesale power when temporarily serving a subset of customers. While it is possible Ava could sell any excess power on the market for a profit, it is also possible this power would have to be sold at a loss compared to its purchase price. This would depend on the market environment at the time these transactions occur.

Due to the uncertainty around SSJID’s municipalization effort (i.e., its likelihood of success and timing of service, if successful), it is difficult to quantify the specific financial risk. The scope of the risk, however, would be limited to the size of the departing load.

As referenced above, based on PG&E’s 2023 load data, the amount of departing load SSJID represents is approximately 100 GWh annually. Meanwhile, Ava’s current 2025 load forecast is approximately 7,600 GWh (including service to the cities of Stockton and Lathrop); and Ava’s 2026 load forecast is approximately 8,800 GWh (including service to unincorporated San Joaquin County). As such, SSJID’s potential departing load amounts to roughly 1.1% to 1.3% of Ava total projected load. While this is a relatively small amount, it could still represent millions of dollars in surplus wholesale energy costs. Actual costs, of course, will depend on market conditions at the time of any future transactions that result from SSJID’s departing load—the timing of which remains uncertain.

Should the Board direct Ava to defer service to the overlapping Ava/SSJID customers, staff anticipates some ongoing expenses associated with correctly dispositioning the Ava enrollment status of meters within SSJID’s portion of San Joaquin County. Similarly, Ava would not collect revenue from these customers for the duration of their deferral. Meanwhile, as Ava proceeds with launching service to SJC customers in March of 2026, Ava staff would continue to engage Staff Report Item 9
with SSJID staff to negotiate risk mitigation strategies that would allow Ava to eventually enroll SSJID customers and serve them until SSJID begins its municipal utility service.

Recommendation
Ava staff proposes the Executive Committee receive staff’s recommendation to enroll SJC customers in March of 2026 and consider deferring service to customers within SSJID service area pending the outcome of SSJID’s eminent domain proceeding before the CPUC on June 23, 2025.

Attachments
A. Power Point Presentation (PPT)
Ava Executive Committee:
2026 Unincorporated San
Joaquin County enrollment
Attachment Staff Report Item 9A

1. Update: 2026 unincorporated SJC
enrollment
2 2. South San Joaquin Irrigation
District (SSJID) enrollment status
recommendation
Attachment Staff Report Item 9A

1. Update: 2026 unincorporated SJC
enrollment
3 Attachment Staff Report Item 9A
Unincorporated SJC enrollment: March 2026
Key considerations re enrollment month:

1. Financial impact

2. Operational efficiency

3. Overall customer experience
4 Attachment Staff Report Item 9A
Unincorporated SJC enrollment: March 2026
Key considerations re enrollment month:

1. Financial impact
o Historically, wholesale energy costs are relatively
lower (e.g., solar and hydro resources are
becoming more abundant)
o Customer usage is relatively low due to seasonally
temperate climate
o Enrolling earlier in year (Q1 or Q2) = more revenue
o Resource Adequacy (RA) already procured
5 Attachment Staff Report Item 9A
Unincorporated SJC enrollment: March 2026
Key considerations re enrollment month:

2. Operational efficiency
o Legally required customer notification begin in
January/New Year (two months prior to
enrollment)
o Call center coordination avoids holidays
o Community outreach events/activities ramp up
after holiday season
6 Attachment Staff Report Item 9A
Unincorporated SJC enrollment: March 2026
Key considerations re enrollment month:

3. Overall customer experience
o Earlier access to Ava service options (Bright
Choice & Renewable 100) and programs
o Historically temperate weather month + lower
usage = less likely to experience high bills
o Ava outreach activities more likely to reach
customers/communities
7 Attachment Staff Report Item 9A
8 2. South San Joaquin Irrigation
District (SSJID) enrollment status
recommendation
Attachment Staff Report Item 9A
SSJID: Background
9 o Began pursuing municipal utility (electric) service 20+ years ago o Scheduled to begin litigating eminent domain acquisition of local PG&E infrastructure in June 2025
o Includes 7,000 customers/100 GWh/year in unincorporated SJC (approx 10-12% of all eligible accounts/load in unincorporated SJC) o Represents ~1.3% of Ava's forecasted 2026 load
Attachment Staff Report Item 9A
SSJID: Recommend deferring customer enrollment
10 Recommendation to Ava Board:

Defer enrollment of SSJID
customers to allow:
▪ Ava/SSJID staff explore
risk mitigation strategy for
temporary-but-indefinite
Ava service, and
▪ Time to understand how
and when the eminent
domain proceeding may
conclude
Attachment Staff Report Item 9A
Attachment Staff Report Item 9A

Ava Community Energy Executive CommitteeMay 7, 2025

Ava Community Energy Executive Committee
May 7, 2025