Valley Clean Energy Board Meeting – Thursday, June 12, 2025 Item 11 – Summer Preparedness Outlook 1
PUBLIC COMMENTS
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2025 VCE SUMMER ASSESSMENT
ITEM 11 – VALLEY CLEAN ENERGY BOARD THURSDAY, JUNE 12, 2025 MEETING 6/10/2025 4
California 2025 Summer Overview
o CAISO and CEC report an overall positive outlook for meeting peak summer demand o Peak load forecasted at 46,094 MW in September at HE18 (minimally less than last year) o Forecast is based on 1-in-2 weather year (also known as weather-normalized) o 5,534 MW of added nameplate capacity of solar, battery, and hybrid expected by June 30, 2025 o Surplus of 1,451 MW above peak forecasted summer needs o Warmer than normal temperatures are expected especially in Inland CA and PNW o California had an average water year, with reservoirs at healthy levels o Upper PNW has below normal runoff volumes and therefore less hydro generation available o As always, there remain concerns regarding a west-wide heat events, wildfires, transmission interruption, and unexpected unit outages
6/10/2025 5
Summer (June – August) Temperature Outlook
6/10/2025 6
Summer (June – August) Precipitation Outlook
6/10/2025 7
Western US Hydro Outlook
6/10/2025 8
California Seasonal Water Storage
Late-May Data
Current Level
Historical Median
6/10/2025 9
CAISO 2025 September Peak Load & Resources Analysis
6/10/2025 10
VCE Summer Readiness Overview
o VCE has fully hedged its energy supply for Summer 2025 o VCE’s Wholesale Energy Procurement Risk Management Policy hedging requirements for the summer are 80% to 130% in Q3 with at least 100% in Heavy Load Hours (Monday – Saturday 6 am to 10 pm)
o VCE has fully procured all necessary RA to meet compliance for Q3 o VCE has multiple years of summer operating history to inform decisions, including both challenging and relatively mild summers
o VCE and TEA have an established procedure for Volatile Incoming Pricing Event Response (VIPER) to ensure alignment on CAISO market operations and reporting in the case of a summer pricing event caused by heat or other conditions 6/10/2025 11
VCE Summer Energy Position
o Aquamarine Solar
o Type: 50 MW PV (Solar Only)
o Status: Generation is strong and expected to continue o Resurgence Solar + Storage
o Type: 90 MW PV + 75 MW BESS (Co-located Resource)
o Status: Generation optimization is occurring as intended o Putah Creek Solar + Storage
o Type: 3 MW Hybrid
o Status: Software issues are currently limiting generation optimization – developer working on resolution o Willy 9 Chap 2 (Willow Springs) Solar + Storage
o Type: 72 MW PV + 36 MW BESS (Hybrid)
o Status: Solar generation strong; experiencing some start-up issues with new battery – developer working on resolution
o Indian Valley Hydro
o Type: 3 MW Hydro
o Status: Expected to generate through mid-June, with generation decreasing in July before going offline for the summer
6/10/2025 12
VCE Contracted Generation
Valley Clean Energy Board Meeting – Thursday, June 12, 2025 Item 12 – 2025 Mid-Year Financials Update 13
Public Comments
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Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 15 Item 12 – 2025 Mid-Year Financials Update : Overview Overview
VCE Staff continues to monitor and update the Board on budget performance for long-term financial sustainability and customer affordability.
Mid-year financial findings:
• 2025 load actuals have been lower than forecasted due to wet winter and lower spring temps.
• Regulatory actions are having significant impacts on forecasted 2026 revenues.
This presentation includes:
• Summary of 2025 Budget Development
• 2025 Financials Update
• Short-term 2026 Outlook
• Recommendation & Discussion
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 16 Item 12 – 2025 Mid-Year Financials Update : Budget Development 2025 Rates & Budget Summary: Key objectives
• Operating Days Cash – Achieve Board approved cash target of +180 days • Rate Stabilization Reserve – Achieve Board Approved Target of +60 days • Customer Discounts (Increased)
• 5% Standard Green Discount
• 10% Care/Fera Discount
• Power Purchase Agreement (PPA) Covenants – Maintain PPA covenants (no letters of credit)
• Investment Grade Credit Rating – Update Timeline (Possible 2025) 0 days
50 days
100 days
150 days
200 days
250 days
300 days
350 days
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
2019 2020 2021 2022 2023 2024
Millions
VCE Reserves and Net Position
Operating Expenses Reserve Balance without Line of Credit Reserve Balance with Line of Credit Total Days' Liquidity without Line of Credit Total Days' Liquidity with Line of Credit Item 12 – Mid-Year Financials: 2024 VCE Reserve and Net Position 2024 17 Extremely
Strong Very Strong Strong Adequate Vulnerable Highly Vulnerable Total Days =>270 150 - 270 90 - 150 45 - 90 12 – 45 <=15 Total Reserves ($MMs) =>250 100 - 250 50 - 100 10 - 50 2 – 10 <=2 Item 12 – Mid-Year Financials: VCE Reserve and Net Position 18 -
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
F A F A F A F A F A F A F A F A F A F A F A F A
January February March April May June July August September October November December MWh Lighting Industrial Large Commercial Med. Commercial Small Commercial Agriculture Residential Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] Item 12 – 2025 Mid-Year Financials Update : Load Update VCE Retail Load Update
2025 Forecast vs. Actuals 2025 Forecast
19 Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 20 Item 12 – 2025 Mid-Year Financials Update : Proforma 2025 Budget Proforma Update (4 Months Actuals – unaudited) Note: The table does not account for anticipated increased power market price, renewable energy credits, and resource adequacy costs Key Highlights
• Revenues are lower than forecasted primarily due to lower load during wet winter and cool spring. • Power Costs have been higher than budgeted due to solar curtailment and lower winter temperatures.
Description Variance
Revenue $ 102,146 $ 100,849 $ (1,297)
Power Cost $ 63,992 $ 64,728 $ (736)
Other Expenses $ 8,853 $ 7,560 $ 1,293
Net Income $ 29,301 $ 28,561 $ (740)
APPROVED
2025 BUDGET
2025 Proforma
(8 Month Actuals +
2 Month Budget)
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 21 Item 12 – 2025 Mid-Year Financials Update : RA Outlook (Example) -
5,000
10,000
15,000
20,000
25,000
30,000
35,000
2020 2021 2022 2023 2024 2025 2026 2027
Resource Adequacy Costs
RA Costs (Thousands) RA MW Required Capacity RA $/MW
CPUC
Slice of Day Decision
2024 Test Year / 2025 Compliance Year
VCE Fixed Price Contracts (PPAs)
Reduce RA and power costs.
$MM
$
MW
Item X – Short
Title and Slide
Description
[Calibri (Body)
29 font (not
bold)]
22 Item 12 – 2025 Mid-Year Financials Update: 2026 MPB Impact Scenarios (20,000)
(10,000)
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
PG&E June Filing
Avg. $9.5 KWH
(Lowest Avg. MPB)
Avg. $15 KWH
(Inflation Adj. Avg. MPB)
Dollars ($1,000)
RA Market Price Benchmark - Financial Impacts
Revenues Costs 2025 PCIA Impact 2026 ERRA Impact Net Income $12 Net Income= 67 days ($14M Net Loss)= 77 days ($17M Net Loss)= 95 days Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 23 Item 12 – 2025 Mid-Year Financials: 2026 Outlook
PG&E 2026 ERRA (IOU Rates) & RA MPB Order Instituting Rulemaking (OIR) - Retro to 2025 Lower power costs reduce PG&E portfolio value, resulting in higher PCIA for CCA’s. • PCIA is currently forecasted to increase significantly in 2026 • Key factor: CPUC’s proposed decision in the OIR is to apply the RA Market Price Benchmarks retroactively to 2025 which will increase the PCIA in 2026 • PG&E Bundled Rates are currently forecasted to decrease significantly in 2026 2026 Budget Outlook (No action needed)
• VCE’s Forecasted 2025 Net Position and Reserves allow us to maintain strong balances while absorbing a forecasted net loss ~$17M in 2026.
• VCE’s forecasts include current approved customer rate discounts. • Forecasted RA market price benchmarks are based on information currently available to VCE and its consultants.
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 24 Item 12 – 2025 Mid-Year Financials: 2026 Outlook
As part of the 2026 budget process, VCE has options to mitigate financial impacts from the current CPUC proposed decisions.
Possible Mitigation Steps for 2026 budget (If needed):
• Use Reserves (Rate Stabilization Fund)
• Reduce Customer Discounts in 2026 – Lower PG&E rates result in lower financial impacts of VCE discounts.
• Sell Long RA positions & Renewable Energy Credits – current market value has reduced from all-time highs in 2024 (Procurement Policy)
• Raise Rates for Power Costs (Standard Green higher than PG&E) (Rate Policy) Additional Considerations:
• Provider of Last Resort Proceeding – Additional collateral requirements • PCIA OIR Proceeding (Phase II) – There are additional unknown outcomes from the phase II. [e.g. Renewable Portfolio Standards Market Price Benchmark (MPB)] Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 25 Item 12 – 2025 Mid-Year Financials: Next Steps / Discussion Next Steps
• Monitor and update the Board on current year financial performance and decisions impacting PCIA and Generation rates.
• Continue to Develop Financial Model for Rate & Reserve Forecasts with New Gen (VCE Consultant)
• October Update – Release of CPUC final decision and evaluate revenue /cost mitigation strategies.
• November – Preliminary Budget Update
• December 2025 – Proposed 2026 Customer Rates and Budget Recommendation & Discussion
Continue Current 2025 customer rate discounts:
• 5% for all (Standard Green/Ultra Green)
• 10% for CARE/FERA customers for the
Valley Clean Energy Board Meeting – Thursday, June 12, 2025 Item 13 – 2024 Net Margin Allocation 26
Public Comments
27 To Provide Public Comment on any agenda item please:
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Join the Public Comment Queue by
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Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 28 Item 13 – Allocation of 2024 Net Margin: Overview
Overview
In Q2 each year, VCE conducts a review and allocates its net margin from the previous fiscal year.
VCE’s draft audited financial statements resulted in $26.9 M net income for FY 2024.
Taking into account the Dividend Program parameters, as well as available and forecast cash reserves, Staff is recommending allocations towards cash reserves, programs, and continued customer rate discounts.
This presentation will provide:
• Summary of 2024 Net Margin
• Present the 2024 Net Margin Allocation Scenarios
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 29 Item 13 – Allocation of 2024 Net Margin: Dividend Program Formula The adopted Dividend Program formula
recommends allocating the net margin
as follows:
Net margin up to 5% is to be allocated as
follows:
• At least 5% (of the 5%) goes to Local
Programs Reserve (LPR) for program
implementation
• The balance goes to cash reserves
Net margin above 5% is to be allocated
as follows:
• At least 75% to cash reserves –
Operational and Stabilization
• Remainder allocated amongst
customer dividends and LPR
VCE Dividend Program Allocation - 2025
Description
2024
Financials
($1,000s)
Avg. Days
Cash ($1,000s)
Electricity Sales 98,929
Operating Expense 71,948
Operating Margin 26,981
Principal Debt Payments -
Adjusted Net Margin less principal Debt Payments 26,981 Adjusted Net Margin Percentage 27.27%
Allocation Amount <=5% 4,946
Allocation Amount > 5% 22,035
2025 Beginning Reserves Balance 26,395 134
Allocation of Net Margin up to 5% Percentage
Allocation
Amount
Operating
Days Cash
Total
Operating
Days Cash
Operating Reserves Allocation 95% 4,699 24 158 Minimum
Local Programs Allocation 5% 247 1 0 Minimum
Allocation of Net Margin above 5% Percentage
Allocation
Amount
Allocation to Operating Reserves 20% 4,407 22 180 Minimum Allocation to Rate Stabilization Reserves 55% 12,009 61 61 Minimum 197
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 30 Item 13 – Allocation of 2024 Net Margin: Discretionary Allocation Scenario 1: Balanced Allocation (Staff Recommended) Staff considered the following factors in related to this recommendation.
Cash Reserves Allocation. VCE’s
strategic goal of obtaining its initial
investment credit rating by 2028 will
require a minimum of +180 days of
operating cash reserves and +60 days of
rate stabilization reserves.
Customer Dividend Allocation. Available
funds for dividends would be designated
to maintain, if possible, our current
customer 5% rate discount for all
customers and 10% for CARE/FERA
customers beyond 2025.
Scenario 2: Increased Rate Stabilization
Scenario 3: Equal Allocation
Percentage
Allocation
Amount
Operating
Days Cash
Total
Operating
Days Cash
Discretionary Allocation (After Cash Reserves) 25% 5,509 28 0 Maximum Allocation to Operating Reserves 0% - 0 180
Allocation to Rate Stabilization Reserves 5% 275 1 62
Local Programs (Targeted 2025/26 Spend) 25% 1,377 7
Customer Dividends (Targeted 2025/26 Spend) 70% 3,856 20 Percentage
Allocation
Amount
Operating
Days Cash
Total
Operating
Days Cash
Discretionary Allocation (After Cash Reserves) 25% 5,509 28 0 Maximum Operating Reserves Allocation 0% - 0 180
Allocation to Rate Stabilization Reserves 15% 826 4 65
Local Programs (Targeted 2025/26 Spend) 25% 1,377 7
Customer Dividends (Targeted 2025/26 Spend) 60% 3,305 17 Percentage
Allocation
Amount
Operating
Days Cash
Total
Operating
Days Cash
Discretionary Allocation (After Cash Reserves) 25% 5,509 28 0 Maximum Operating Reserves Allocation 25% 1,377 7 187
Allocation to Rate Stabilization Reserves 25% 1,377 7 68 Local Programs (Targeted 2025/26 Spend) 25% 1,377 7
Customer Dividends (Targeted 2025/26 Spend) 25% 1,377 7 Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 31 Item 13 – Allocation of 2024 Net Margin: Summary Discussion Summary
Staff believes that these scenarios represent a disciplined and financially prudent approach to building reserves and continue providing some additional level of rate relief.
VCE Recommendation
Adopt a resolution approving the allocation of the $26.9M 2024 Audited Net Margin as follows:
a) $9,106,000 (34%) of Net Margin to operational cash reserves; b) $12,284,000 (46%) of Net Margin to rate stabilization reserves; c) $1,624,000 (6%) of Net Margin to the Local Programs Reserve (LPR). d) $3,856,000 (14%) of Net Margin designated to the Dividends Program in the form Rate Credits