Desert Community Energy Board of Directors
November 20, 2025

List of Acronyms
BESS battery energy storage system
DC direct current
C battery C-rate (units are 1
ℎ
, so 0.5 C or “C/2” means charging or discharging in 2 hours) CAISO California Independent System Operator
CPUC California Public Utilities Commission
DAM day ahead market
DCE Desert Community Energy
DER distributed energy resource(s)
FERC Federal Energy Regulatory Commission
FTM front-of-the-meter
kV kilovolt
kVA kilovolt-amperes (apparent power only)
kW kilowatt (1000 W)
kWh kilowatt-hour (one kW over a period of one hour)
kWp kilowatt photovoltaic (solar PV DC capacity)
LCOE levelized cost of energy
LCOS levelized cost of storage
LFP lithium iron (Fe) phosphate (battery chemistry)
MVA megavolt-amperes (apparent power only)
MW megawatt (1000 kW)
MWh megawatt-hour (1000 kWh)
NMC nickel manganese cobalt
NREL National Renewable Energy Laboratory
NSRDB National Solar Radiation Database
PF power factor (kW/kVA, ratio of real power to apparent power) PPA power purchase agreement
PV photovoltaic (solar)
SCE Southern California Edison
TMY typical meteorological year
TOU time of use
TPC total project cost
WDAT Wholesale Distribution Access Tariff
WRDB Wind Resource Database

Executive Summary
Desert Community Energy (DCE) commissioned this Phase 1 Renewable Energy Assessment for its ACCESS Renewable Energy project, aiming to integrate solar or wind generation and possibly battery storage in the larger ACCESS road and bridge reconstruction. The aim is to provide clean and local generation to DCE's Palm Springs consumers at a reasonable price. muGrid Analytics performed a techno-economic evaluation of the requested new energy resources at the site, notably the walkway along Indian Canyon Drive and the Amtrak station parking lot, and the adjacent 14-acre parcel. A range of solar PV array types was studied for the ACCESS site, including a solar carport parking lot, a walkway shade structure, and fixed-tilt and tracking solar fields. Only the solar carport is technically feasible due to a change in the ACCESS project requirements likely eliminating the walkway, and due to the parcel being in a flood plain with a low likelihood of rerouting the flow with a new berm. Any wind turbine foundations would likely require reinforcement due to the flood water erosion and debris, and a battery energy storage system (BESS) container would need to be sited above or away from the flood plain.

Economic analysis shows that wind and battery storage offer the most favorable economics. While the two wind turbines have a higher levelized cost of energy (LCOE) than any of the solar designs, the wind generation occurs more often outside the daytime hours when prices are more often low or negative. However, the fixed-tilt solar field also showed generally positive economics and could be considered at a different site. In addition to being technically infeasible, the solar walkway is prohibitively expensive as designed. The battery can be considered independent of the other resources in design and analysis except regarding maximum interconnection capacity and the calculation of resource adequacy (RA) payments. Confidence in costing and modeling results is high due to rigorous techniques and outside validation, however, the final economic results have uncertainty due to the current volatile international trade tariffs and decreasing future wholesale energy and RA prices.

Interconnection is expected via the nearby Southern California Edison (SCE) Garnet substation on a 33 kV feeder, with no major upgrades anticipated for capacities close to 3 MW. Previous information suggests 3 to 7 MW of capacity could be available, however, the SCE Wholesale Distribution Access Tariff (WDAT) Pre-Application Request response was not available before the publication of this report to confirm the available capacity or inform the cost of any required grid upgrades.

Next, we advise DCE to:
• Review the SCE Pre-Application Request and determine the site interconnection capacity • Consider different ownership structures from a legal and cost standpoint • Decide whether DCE would keep (“retire”) or sell any RECs • Continue with Phase 2 to refine the economic performance and technical implementation considerations, as well as to look for areas of improvement

Table of Contents
1 Introduction 7

1.1 Purpose 7

1.2 Approach 8
2 Background 8

2.1 Phase 1 Goals 9

2.2 Site Overview 11

2.3 Project Objectives and Metrics 13

2.4 Technologies Under Consideration 13
3 Analysis 14

3.1 Wholesale Energy Prices 14

3.2 Interconnection 14

3.3 Load 17

3.4 Business and Policy 17
4 Design 18

4.1 New Assets Under Study 18
5 Results 25

5.1 Economic Feasibility 25

5.2 Technical Feasibility 31

5.3 Environmental Impact 32
6 Conclusions 33

6.1 Key Takeaways 33

6.2 Next Steps 34
7 Acknowledgements 34

List of Figures
Figure 1. Project Approach 9
Figure 2. ACCESS Site Overview (Oriented West) 12
Figure 3. Indian Canyon Dr. Walkway Shade Structure Rendering 13 Figure 4. ACCESS Amtrak Parking Lot Solar Carport Rendering 14 Figure 5. Amtrak Parking Lot Adjascent Parcel 14
Figure 6. Heatmap of Anuual Wholesale Energy Prices by Hour of Day and Week of Year 16 Figure 7. Garnet Substation Location With MV Lines 17
Figure 8. DCE Hourly Load Power Overlaid Weekly 19
Figure 9. Solar Carport at Amtrak Station Parking Lot (No Expansion) 21 Figure 10. Solar Walkway Along West Side of Indian Canyon Dr. 22 Figure 11. Solar Field (Fixed Tilt) Adjacent to Amtrak Parking Lot 23 Figure 12. Solar Field (Fixed Tilt) Production Heatmap by Hour of Day and Day of Year 23 Figure 13. Solar Trackers Adjacent to Amtrak Station Parking Lot 24 Figure 14. Solar Trackers Production Heatmap by Hour of Day and Day of Year 24 Figure 15. Wind Turbines at Parcel Adjacent to Amtrak Parking Lot 25 Figure 16. Wind Production Heatmap by Hour of Day and Day of Year 26 Figure 17. Battery Modules uses in the BESS Design 27

List of Tables
Table 1. SCE Garnet Substation Interconnection Information From DRPEP DataBase 16 Table 2. Solar Carport Annual and Lifetime Economics 27 Table 3. Solar Walkway Annual and Lifetime Economics 28 Table 4. Solar Field (Fixed-Tilt) Annual and Lifetime Economics 29 Table 5. Solar Trackers Annual and Lifetime Economics 30 Table 6. Wind Turbines Annual and Lifetime Economics 31 Table 7. Battery Energy Storage Annual and Lifetime Economics 32 Table 8. Summary of Technical Feasibility by Resource 32

1 Introduction
A grid-connected and front-of-the-meter (FTM) renewable energy generator or storage resource is not connected to pre-existing loads. Compared to a behind-the-meter source, such as a solar PV array on a factory or school rooftop, these projects are often much larger and have very different operational programs and regulations. The incentives and regulations change depending on the capacity and location of the resource, the ownership structure, market conditions, and intended operation. With these uncertainties it is not a simple problem to choose the best renewable technology, capacity, and operate it. This techno-economic optimization is one of muGrid’s core competencies.

Generally renewable FTM generators like wind and solar are owned and operated for profit and to meet renewable energy requirements. Therefore assessing and optimizing their benefit depends on estimating the production times series and the valuation. The production is valued at what a buyer is willing to pay in a forward (pre-agreed) or more real-time market, or what a distribution utility is required by law to pay by law. Storage is similar but must also consider the sell price, paid during charging, since it’s not a net generator of energy. The main remaining factors of the techno-economic analysis are capital and operational costs, operational strategy, hardware capabilities, limitations injecting or withdrawing from the grid, and site constraints.

Some examples of FTM resources are: a transmission-connected 100 MW wind farm selling all of its production at a Power Purchase Agreement (PPA) price to an industrial buyer, a 5 MW solar PV array selling all its production to a distribution utility at the day ahead market (DAM) rate, or a battery energy storage system (BESS) participating in real-time markets.

1.1 Purpose
The Desert Community Energy (DCE) ACCESS Renewable Project is investigating new solar PV or wind generation potentially coupled with battery storage connected to the local distribution grid. The energy production is intended to provide clean energy to DCE’s customer base and further its goals of sustainable and low cost electricity. The resources will not be interconnected with existing or substantial load, so will not need to island or provide other microgrid features.

The larger ACCESS Indian Canyon Dr road and bridge reconstruction project is the intended site for any new generation or storage. This is to take advantage of any design synergy between ACCESS and the renewable generators. In particular a shade structure walkway is envisioned along Indian Canyon Dr and a carport shade structure at the nearby Amtrak station parking lot. While DCE will consider projects in other locations up to 50 MW in size it is not the primary goal of the ACCESS Renewable Project, but could be informational for future development.

Therefore DCE commissioned a Renewable Energy Assessment at the Indian Canyon Dr location to interconnect to the nearby Southern California Edison (SCE) distribution network.

This study is conducted at a high, system-of-systems level, with the purpose of evaluating the broad-brush costs, technical requirements, and benefits of a renewable generation project for DCE. The aim is to size the main system components to an order of magnitude, to identify possible infrastructure updates needed, and to point DCE in the right direction for more detailed studies. Lower level design studies, including utility impact studies or power injection studies must yet be done prior to project

implementation, but the work of this study will inform and focus those studies so that they can lead directly to project implementation.

1.2 Approach
To understand all of the design options, we explore a tradespace. A tradespace represents all possible design options from minimum sizes of various technology options to the maximum size. We can quickly eliminate large sections of the tradespace due to cost or failure to meet resilience requirements.

Then we focus on those designs that would meet requirements and perform trades between them.

In order to complete this study, we used the following approach:

Figure 1. Project Approach
2 Background
DCE is a community choice aggregation program serving Palm Springs, California, with the goal of providing cleaner, carbon-free electricity at competitive rates. Launched in April 2020, DCE automatically enrolls all residential and commercial customers into its default Carbon Free plan, which sources electricity from renewable and carbon-free sources such as solar, wind, geothermal, and large hydroelectric power. Southern California Edison (SCE) still retains a crucial role in the metering and distribution of energy to consumers. Customers have the flexibility to opt down to the Desert Saver plan, offering lower-cost electricity with a less green energy mix, or to opt out entirely and remain with Southern California Edison (SCE) for both generation and delivery. While DCE handles the procurement of electricity, SCE continues to manage transmission, distribution, metering, and billing. In 2023 DCE and SCE delivered 376 GWh to consumers.

DCE is the largest program in the Energy and Sustainability Department of the Coachella Valley Association of Governments (CVAG). CVAG is a joint powers authority that unites local governments across the Coachella Valley to collaboratively address regional challenges in areas such as transportation, housing, conservation, and sustainability. Within CVAG, the Energy & Sustainability Department is dedicated to promoting the sustainable use of natural resources and supports initiatives like Desert Community Energy (DCE).

The Energy Authority (TEA) is the main energy purchaser for DCE, and is a nonprofit corporation that provides energy trading, risk management, and advanced analytics services to public power utilities across the United States. Established in 1997 and headquartered in Jacksonville, Florida, with a regional office in Bellevue, Washington, TEA is wholly owned and directed by its public power members. The organization supports over 70 public power clients, representing more than 30,000 MW of peak demand and 25,000 MW of installed generation capacity nationwide. TEA offers a range of services, including portfolio management, renewable energy integration, and advisory solutions, enabling utilities to navigate the complexities of the energy market and achieve their sustainability goals.

In Palm Springs, California, Southern California Edison (SCE) serves as the primary utility responsible for delivering electricity to homes and businesses. Although most utilities in California are no longer vertically integrated, SCE still owns some hydroelectric generation in addition to its transmission and distribution networks. While DCE manages the procurement of electricity, SCE continues to handle the transmission, distribution, and maintenance of the electrical infrastructure.

Customers receive a single monthly bill from SCE, which includes charges for both SCE's delivery services and DCE's electricity generation. This collaborative arrangement allows Palm Springs residents to benefit from locally sourced, carbon-free energy through DCE, while relying on SCE's established infrastructure for reliable power delivery.

The Indian Canyon ACCESS Renewable Project, led by DCE, focuses on integrating renewable energy infrastructure into the broader ACCESS Project, which aims to address frequent road closures due to sandstorms and flooding near Palm Springs, CA. The project is evaluating the feasibility of installing solar energy systems — including solar shade structures paired with battery storage — along Indian Canyon Drive and at the nearby Amtrak station parking lot. Wind energy options and stand-alone battery storage are also being considered. DCE is seeking to maximize clean energy production at these sites, enhance community resiliency, and contribute to California’s climate goals, with the ultimate goal of achieving a renewable energy generation capacity in the range of up to 50 MW. The bridge and road portion of the project has received significant grant funding from the California Transportation Commission and the Southern California Association of Governments. The ACCESS Renewable Project has a capacity goal of approximately 3 to 7 MW based on what can be interconnected to SCE, with information requested on the economics and feasibility of larger capacities up to as much as 50 MW.

2.1 Phase 1 Goals

4.1.A. Transmission Availability

1. Confirming available firm transmission capability
muGrid will work with SCE to understand transmission and distribution interconnection capacity at candidate local points of interconnection for the considered system. We also discuss processes and costs for any required system impact studies and interconnection review gates. This preliminary analysis of the interconnection process will set up detailed analysis during Phase 2, as the project architecture solidifies.

4.1.D. Economic Feasibility and Financial Analysis

1. Estimated Installed Costs per MW for Each Renewable Energy Option To assess the estimated installed costs per MW for each renewable energy option, muGrid will assess the total costs associated with installing and operating each renewable energy option. muGrid will conduct a detailed market analysis, examining current trends in solar PV systems, wind energy systems, and BESS. Our approach will involve getting quotes and pricing structures from equipment suppliers and vendors. Having done many similar projects in the past, muGrid is adept at ensuring all associated costs including but not limited to hardware, equipment, direct labor, and indirect labor costs, permitting, inspection, interconnection, and other overhead will be considered for each site and system design.

4. Economic Feasibility Evaluation
To evaluate the economic feasibility of solar, wind and battery storage projects, muGrid will perform a comprehensive analysis that considers various financial aspects. muGrid has developed a detailed cost and economic model based on real world experience that has been gained over the years.

Our model consists of detailed system construction costs and operating and maintenance (O&M) costs, which include the cost of bi-annual service and maintenance schedules and cleaning/washing of the solar panels, as well as potential revenue streams from energy generation. We will study the impact of incentives and tax credits such as carbon tax credit, investment tax credit and production tax credit on improving the economic attractiveness of the proposed project, performing a detailed sensitivity analysis for this purpose.

To evaluate the financial attractiveness of each renewable option, muGrid will calculate several important economic measures including levelized cost of electricity production (LCOE), payback period (PBP), return on investment (ROI) and benefit cost ratio (BCR). ● LCOE is the ratio of the total cost of the project during its lifetime including both capital cost and O&M cost to the electricity generated over the lifetime of the project. It is a robust measure to compare the cost of electricity generation of solar systems for each facility against other electricity generation sources and cost the city is paying to purchase electricity from the utility company.
● ROI is calculated to measure the profitability of the investment made by DCE in renewable energy systems installation and PBP is calculated to determine the period of time required to recover this investment.
● BCR is calculated to determine the relative profitability of the project defined as the ratio of the benefits of a project relative to its costs. The higher BCR shows a more profitable investment.

We will analyze various scenarios to understand how factors such as energy pricing and production variability may impact overall project viability. This assessment will also include sensitivity analyses to evaluate the impact of different assumptions on financial outcomes.

2.2 Site Overview
The ACCESS Renewable Project sites are adjacent to the ACCESS bridge reconstruction project, on Indian Canyon Drive in Palm Springs, CA. The bridge is being reconstructed due to sand and water inundation, so special consideration has been paid to the possibility of either affecting any new energy resources in the area. The Palm Springs Amtrak station and parking area is located near the Indian Canyon Drive bridge. The two sites available for new renewable generation and storage are (1) the parking area, including the asphalt surface parking lot and 14.3 acre parcel around it, and (2) a new construction walkway along Indian Canyon Drive from the Amtrak station to Sunrise Parkway. Below is the Location Map Exhibit from Attachment C of the RFP, which is oriented such that up is due west.

Figure 2. ACCESS Site Overview (Oriented West)
The two sites available for new generation and storage are further explored in the next two sections.

2.2.1 Indian Canyon Drive Walkway
The west side of Indian Canyon Drive is envisioned to include an impermeable surface walkway with protective guardrails between pedestrians and traffic. A shade structure solar array above the walkway could provide shade and reduced temperatures for pedestrians while adding a significant amount of solar capacity to the existing built environment. The length of the walkway is estimated at 1.8 miles and 25 feet wide.

Figure 3. Indian Canyon Dr. Walkway Shade Structure Rendering

2.2.2 Amtrak Station Parking Lot
The Amtrak station includes existing parking as well as turnaround lanes for bus and other transit pickup. The parking lot may be expanded to the south. Solar canopies are feasible over the passenger vehicle parking. Canopies may be feasible over the turnaround lanes with sufficient height to accommodate bus traffic.

Figure 4. ACCESS Amtrak Parking Lot Solar Carport Rendering Solar may also be feasible in the undeveloped area adjacent to the Amtrak parking lot as a standard ground mount solar array or in a similar nearby area. Concerns for development in this area are the impacts of blowing sand and periodic seasonal flash flooding.

Figure 5. Amtrak Parking Lot Adjacent Parcel

2.3 Project Objectives and Metrics

1. Local renewable generation for Palm Springs

2. Cost effectiveness

2.4 Technologies Under Consideration
For this study, we consider some combination of solar PV and wind generators, with optional battery storage for economic benefits. These technologies are described in more detail in Section 4.4. ● Solar PV
○ Carport shade structure
○ Walkway shade structure
○ Ground mount “field”
● Wind
● Battery storage
Solar (both PV and thermal): Solar usually has zero local emissions, very low lifecycle emissions, high technology maturity, and high cost effectiveness.

Wind power: Wind also has very low lifecycle emissions and often has a complimentary production profile relative to solar. Wind siting faces some challenges depending on the size of the turbine and blades, such as keep out zones for adjacent development and wildlife impacts.

Battery Storage: Solar PV and wind aren’t inherently dispatchable. Battery energy storage can enable targeted dispatch of electrical energy to match demand, regardless of time of day or weather. Of the many options, lithium ion, lithium iron phosphate (LFP), and lead acid chemical storage are the most

economical and technologically mature at this scale. Flow batteries represent an upcoming affordable option for long duration energy storage, and are rapidly maturing. 3 Analysis

3.1 Wholesale Energy Prices
The analysis of wholesale energy prices highlights significant variability in market conditions, which directly impacts the financial performance of renewable energy projects. In particular, the Day-Ahead Market (DAM) serves as a key indicator, with 2023 representing a high-price scenario and 2024 reflecting a lower-price case. This downward trend in wholesale prices poses challenges for project developers, especially as prices have occasionally turned negative—meaning generators must pay to inject power into the grid.

Figure 6. Heatmap of Annual Wholesale Energy Prices by Hour of Day and Week of Year Notably, in 2024, prices ranged from a high of $1,275/MWh to a low of -$67/MWh, with negative pricing occurring in approximately 8% of hourly intervals. Solar energy systems are especially vulnerable to these low and negative prices due to their peak production aligning with times of market saturation.

In contrast, wind energy, which often generates during off-peak hours like nighttime, is less susceptible to such pricing issues, thereby offering a more stable and potentially profitable revenue stream under current market conditions. These insights were informed by data provided by The Energy Authority, which also supported the project’s revenue modeling.

3.2 Interconnection
Interconnection to the SCE grid is a key factor for this project. The closest SCE substation is Garnet, and the distribution line along Indian Canyon Drive operates at 33 kV, which is favorable for interconnection of a project of this size. It had been previously estimated that injecting roughly 3-7 MW is possible without major grid upgrades. The "maximum remaining generation capacity" figure for the Garnet substation in SCE’s DRPEP platform suggests as much as 71 MW could be available, however the

same platform shows a distribution generation penetration level of 133% so the 71 MW number may be an error. For a total capacity likely under 10 MW, all energy resources would likely connect to the nearby SCE MV distribution rather than at the transmission level. The exact MV hosting capacity will be determined through the SCE WDAT Pre-Application Request, which will be filed .

Figure 8. Garnet Substation Location With MV Lines (Pink 33 kV, Blue 12 kV) At 33 kV and within 2.5 circuit miles from the substation, projects under 5MW may be eligible for a “fast track” interconnection project, while a larger project would go through the longer “cluster” process. The timeline can vary quite a bit, but fast track interconnection can be completed in 4-6 months, while the traditional cluster interconnection process can take around two years.

Table 1. SCE Garnet Substation Interconnection Information From DRPEP Platform Substation Name Garnet (Id 1613)

Substation Type D -- Distribution
System Name Devers 220/115 System
Existing Generation (MW) 77.89
Queued Generation (MW) 19.30
Total Generation (MW) 97.19
Projected Load (MW) 73.20
Penetration Level (%) 132.75
Maximum Remaining
Generation Capacity
(MW)

70.81 On the SCE distribution grid, compensation for solar and other distributed energy projects generally follows one of two main pathways. The first option is Rule 21, which applies to small- to medium-sized projects that interconnect to the distribution system, usually behind-the-meter. Under this framework, projects are subject to SCE’s tariff structure and are typically compensated through Net Energy Metering (NEM) 3.0, which values exported solar energy based on SCE’s avoided cost rather than retail rates. Although these projects operate within SCE’s grid, they remain regulated by the California Public Utilities Commission (CPUC). The second option is the Wholesale Distribution Access Tariff (WDAT), which is designed for medium- to large-sized projects—typically those connecting at 220 to 500 kV—and falls under Federal Energy Regulatory Commission (FERC) jurisdiction. WDAT is generally required for projects that plan to sell electricity to third parties, not just offset on-site load. Additionally, under WDAT, the tariff also governs costs associated with non-battery auxiliary loads, such as station lighting and power for facility operations.

When interconnecting a battery to the SCE distribution grid, there are two main operational approaches to consider: firm charging and charging schedule. Under firm charging, the battery is allowed to draw power from the grid at any time, providing maximum operational flexibility. However, this option requires participation in a cluster study, a comprehensive interconnection review process, and may result in the need for incremental grid upgrades to accommodate the battery’s unrestricted demand. In contrast, the charging schedule limits when the battery can charge from the grid. SCE

provides a predefined schedule—based on specific days or months and restricted hours—that is tailored to the characteristics of the local distribution circuit and the battery project itself. A preliminary version of this schedule becomes available only after completion of the interconnection study report, and it may be refined over time. This option reduces potential grid impacts but also limits the operational autonomy of the battery system.

3.3 Load
The DCE load time series data show typical dual morning and evening peaks of 30 to 40 MW on median, or typical, days. In high load scenarios the peaks combine into one late-afternoon peak and exceed 120 MW. These observations combined with a very low midday load suggest the provided data is what we refer to as net load - the true consumption of less behind-the-meter renewable generation, typically solar PV. This is common and not unexpected, and does reflect the true amount of energy that DCE must supply to its customers.

Figure 9. DCE Hourly Load Power Overlaid Weekly
Since new solar and wind would be connected FTM, according to CAISO rules the generation will be sold completely through the CAISO markets via SCE and therefore DCE’s load does not have a direct role in the techno-economic analysis.

3.4 Business and Policy
We recognize that some of the most important constraints on the system are imposed, not by physical or technical limitations, but by regulatory or policy limitations. As a community with its own established municipal utility, DCE has more leeway than many site hosts. However, there are still constraints. The main business consideration is ownership structure.

This has an impact on financing because DCE, not an entity with tax liability, would be applying for the federal Investment Tax Credit (ITC) under the Direct Pay program for non-taxable entities if the

ITC is preferred over the Production Tax Credit (PTC). Direct Pay is a powerful mechanism to help governmental entities to recoup 30% of project costs, possibly more if certain labor requirements are met, and has worked for other nontaxable entities successfully and recently in muGrid’s experience.

After commissioning, DCE or other owner would register each resource and file a tax return, even if not otherwise required to do so. The payment is executed after the tax filing deadline, and should happen within 45 days. The main risk to the ITC and direct pay is new legislation which may shorten the lifetime of the ITC, incentivizing quicker commissioning.

If DCE chooses not to own it could buy energy and possibly storage at a PPA price, compared to hiring a construction company outright. TEA has suggested solar PPA prices between $44 and $88 per MWh. This is calculated as the sum of the PTC and resource adequacy (RA) payment price, under an assumption that PPA prices will closely reflect the revenue-side value. The PTC is somewhat fixed at $20 per MWh, whereas the RA (for PCC1) price has ranged between 24 and 68 in 2025 and 2024, respectively. Also TEA has indicated real prices have recently been between $50 and $60 per MWh in recent years. muGrid performs our own estimations of solar, wind, and battery resources from a cost-plus methodology, designing each system and pricing the components, labor, and other costs. These are the prices formally used in the analysis. The costs are therefore not strictly dependent on the owner, but should be revisited if at some point DCE decides that it has a preference to own or not. 4 Design
In the design phase muGrid chooses or optimizes various design parameters and models each asset as a whole. Each design is performed at an appropriately high level for this phase of the study. The solar PV layout is built in the commercial software Helioscope and production estimates are based on Typical Meteorological Year (TMY) solar radiation data from the National Solar Resource Database (NSRDB).

4.1 New Assets Under Study
Any considered new assets must be interconnected to the SCE distribution grid to participate in the CAISO markets. The following section are all designs modelled by muGrid and are not necessarily representative of the final design choices.

4.1.1 Solar Carport
The modeled solar PV carport has a capacity of 0.59 MWp and is oriented south-west at 218° with a 10° tilt. It uses Axitec 550 W modules mounted on a generic racking system, assuming standard structural configurations. Based on this setup, the system is expected to achieve a specific yield of 1,699 MWh per MWp, indicating good performance relative to its layout and location.

Figure 10. Solar Carport at Amtrak Station Parking Lot (No Expansion)

4.1.2 Solar Walkway
This modeled solar walkway has a capacity of 2.25 MWp and is west-facing with a 10° tilt. It utilizes Axitec 550 W modules mounted on a “2-in-portrait” racking configuration, which is considered a conservative design choice. The walkway is understood to span 1.8 mi in length and is 24 ft in width.

With these parameters, the system is projected to deliver a specific yield of 1,624 MWh per MWp, reflecting the expected energy output relative to its installed capacity.

Figure 11. Solar Walkway Along West Side of Indian Canyon Dr.

A unique aspect of the solar walkway is its long and narrow layout. Power from the southern-most part of the array must be sent all the way back to the beginning, where there would normally be a single point of interconnection with the grid. To avoid losing much of the power produced, the long array was divided into several sections, each with its own MV transformer and connection to a new MV circuit spanning the whole length of the walkway. Large solar fields also must do this, but the denser layout means fewer transformers and feet of expensive MV line. Connecting to the grid at multiple points along the Indian Canyon Dr. 33 kV feeder could be possible, but would require close design coordination with SCE.

4.1.3 Solar Field
The modeled fixed-tilt solar field has a capacity of 4.35 MWp, with the array south-facing and tilted at 30° to optimize sun exposure and minimization of collected dust. It uses Axitec 550 W modules mounted on a 2-in-portrait racking system, with 25 ft spacing between rows to minimize shading and maintain efficiency. The modeled layout is designed to maximize production while adhering to spatial constraints, though it's likely that some of the smaller rows would be excluded from the final buildout due to cost-effectiveness or site limitations. Overall, the system is expected to achieve a specific yield of 1,973 MWh per MWp, indicating strong energy performance relative to capacity.

Figure 12. Solar Field (Fixed Tilt) Adjacent to Amtrak Parking Lot Figure 13. Solar Field (Fixed Tilt) Production Heatmap by Hour of Day and Day of Year

4.1.4 Solar Trackers
The modeled solar PV tracking array is designed with a total capacity of 2.76 MWp, oriented south-facing and tilted at 30°. It features Axitec 550 W modules mounted on a 1-in-portrait racking system, with 25-foot row spacing to reduce shading and allow for optimal sun tracking. While the modeled layout aims to maximize energy production, it is anticipated that some of the smaller rows may be excluded from the final design due to efficiency or site constraints. The system is projected to deliver

a specific yield of 1,973 MWh per MWp, reflecting strong performance under typical operating conditions.

Figure 14. Solar Trackers Adjacent to Amtrak Station Parking Lot Figure 15. Solar Trackers Production Heatmap by Hour of Day and Day of Year

4.1.5 Wind
The modeled wind design is based on two Vestas V100 2 MW turbines, which would provide a combined capacity of 4 MW. These turbines can be sited with generous spacing of 2 to 3 rotor diameters, which helps mitigate wake effects—though the layout is limited to a single row . A 500-foot setback from Indian Canyon Drive is considered, and for the evaluated area, this requirement does not pose a major obstacle. However, it remains unclear whether adjacent features like the parking lot or railway are subject to the same setback restrictions, which could affect final placement. Alternatively, using smaller turbines (0.5 to 1 MW each) would not significantly increase capacity, as the total potential would still be capped at around 3 MW due to spacing and site limitations. At 3900 MWh/MW, we project the production yield to be quite good relative to average wind site production.

Figure 16. Wind Turbines at Parcel Adjacent to Amtrak Parking Lot

Figure 17. Wind Production Heatmap by Hour of Day and Day of Year

4.1.6 Battery
The modeled Li-Ion NMC battery energy storage system (BESS) is 7 MW 28 MWh, in line with the largest expected possible power injection at the SCE substation. The BESS may be easily scaled down from this maximum size according to available capital. The 4-hour duration is required to be eligible for RA payments and the SCE charging schedule fast track interconnection scheme, but it also ensures a low C-rate extending the battery’s usable lifetime. The modeled battery is planned as a standalone AC-coupled asset, technically and financially distinct from any co-located solar or wind. Its operational strategy is based on participation in the day-ahead energy market. A simple strategy can be applied such as a "top 4 / bottom 4" approach—charging during the four lowest-priced hours and discharging during the four highest-priced hours each day to maximize revenue. However muGrid used the proprietary Redcloud software to further optimize production, cycling the battery slightly more than once per day.

The system is expected to be AC-coupled, offering flexibility and ease of integration with grid infrastructure.

Figure 18. Battery Modules used in the BESS Design
5 Results
The following sections detail the modeled economic and technical feasibility of the various solar, wind, and battery configurations. For clarity solar is divided into different results for each potential type of array, noting that a final design could certainly combine array types together and therefore the costs and revenues simply add together as well.

5.1 Economic Feasibility
Economic feasibility is represented as annual revenue, broken down into its components, and then lifetime costs, revenue, and net costs/revenues. The lifetime values consider a scenario where the renewable energy credits (REC) are kept rather than sold. Keeping the REC ensures the buyers of the renewable generation are consuming low carbon energy. Other metrics such as NPV and IRR can be calculated but require knowing the ownership structure, which is undecided at this early phase of study.

The results are given for two scenarios: based on 2023 and 2024 prices. The first is a relatively high wholesale market price scenario, and the second reflects relatively low prices. This is important because with the increase of renewable generation in California prices in the wholesale markets, especially day-ahead, are generally declining partially due to the near-zero marginal cost of these resources. For projects with a 25+ year lifetime, forecasting future prices is a challenge and requires assumptions about both state and national policy and legislative decisions. For this high level study a range of possible revenues is appropriate.

5.1.1 Solar Carport
The modeled solar carport has an LCOE of $100 per MWh and a generally negative net balance between total expenditure and revenue, however not egregiously so. In particular, at these prices the ITC would be more beneficial than the PTC, reducing the installed cost by around $250,000. Generally in Southern California grid-scale solar PV plants have a low enough LCOE that the $20 per MWh PTC generates more value than the 30% ITC. For these smaller sub-arrays with lower production yield, that may not be true.

Table 2. Modeled Solar Carport Annual and Lifetime Economics 2023 2024
Annual
Revenues
Wholesale Market $35,000 $11,000
Production Tax Credit $20,000 $20,000
Resource Adequacy $10,000 $10,000
Selling RECs $24,000 $24,000
Lifetime
(25 years)
Revenue $2,225,000 $1,625,000
Revenue (keep RECs) $1,625,000 $1,025,000
Total Expenditure $2,495,700 $2,495,700
Net -$270,700 -$870,700
Net (keep RECs) -$870,700 -$1,470,700

5.1.2 Solar Walkway
The modeled solar walkway produces energy with an LCOE of $212 per MWh and has negative economic results due to the high installation cost. Greatly reducing the length would reduce the need for the unique MV distribution system, but would also reduce the total energy generated and decrease

the economies of scale. Alternatively working with SCE to interconnect the array several times along Indian Canyon Dr. could be a possibility.

Table 3. Modeled Solar Walkway Annual and Lifetime Economics 2023 2024
Annual
Revenues
Wholesale Market $121,000 $37,000
Production Tax Credit $73,000 $73,000
Resource Adequacy $38,000 $38,000
Selling RECs $86,000 $86,000
Lifetime
(25 years)
Revenue $7,950,000 $5,850,000
Revenue (keep RECs) $5,800,000 $3,700,000
Total Expenditure $19,282,500 $19,282,500
Net -$11,332,500 -$13,432,500
Net (keep RECs) -$13,482,500 -$15,582,500

5.1.3 Solar Field
The modeled solar field has the best solar generation LCOE of $52 per MWh, very close to the $50-$60 per MWh range of solar PPA prices estimated by TEA. This is a helpful validation of muGrid’s cost-plus approach. The net economics are generally positive but would not likely improve by taking the ITC over the PTC, due to the reasons discussed above.

Table 4. Modeled Solar Field (Fixed-Tilt) Annual and Lifetime Economics 2023 2024
Annual
Revenues
Wholesale Market $301,000 $97,000
Production Tax Credit $172,000 $172,000
Resource Adequacy $74,000 $74,000
Selling RECs $203,000 $203,000
Lifetime
(25 years)
Revenue $18,750,000 $13,650,000
Revenue (keep RECs) $13,675,000 $8,575,000
Total Expenditure $11,179,500 $11,179,500
Net $7,570,500 $2,470,500
Net (keep RECs) $2,495,500 -$2,604,500

5.1.4 Solar Trackers
The modeled solar tracking design is calculated at a slightly higher LCOE of $57 per MWh, which is somewhat unexpectedly higher than the fixed-tilt field and could likely be improved somewhat with refinement of the design and cost estimation. Similar to the fixed-tilt field, the net economics are generally positive and also aren’t likely to improve by opting for the ITC over PTC.

Table 5. Modeled Solar Trackers Annual and Lifetime Economics 2023 2024
Annual
Revenues
Wholesale Market $246,000 $87,000
Production Tax Credit $132,000 $132,000
Resource Adequacy $47,000 $47,000
Selling RECs $156,000 $156,000
Lifetime
(25 years)
Revenue $14,525,000 $10,550,000
Revenue (keep RECs) $10,625,000 $6,650,000
Total Expenditure $9,356,400 $9,356,400
Net $5,168,600 $1,193,600
Net (keep RECs) $1,268,600 -$2,706,400

5.1.5 Wind
The modeled wind turbines have a higher LCOE, $64 per MWh, than either the solar field or trackers but achieve all positive balances between lifetime cost and revenue. This appears counter intuitive but can be explained by the much larger percentage of total annual revenue from the wholesale market (the LCOE calculation does not depend on revenue sources). Put another way, more wind production occurs outside of the 7:00 AM to 6:00 PM window when wholesale prices are often much lower or even negative.

Table 6. Modeled Wind Turbines Annual and Lifetime Economics 2023 2024
Annual
Revenues
Wholesale Market $1,005,000 $539,000
Production Tax Credit $311,000 $311,000
Resource Adequacy $68,000 $68,000
Selling RECs $368,000 $368,000
Lifetime
(20 years)
Revenue $35,040,000 $25,720,000
Revenue (keep RECs) $27,680,000 $18,360,000
Total Expenditure $18,200,000 $18,200,000
Net $16,840,000 $7,520,000
Net (keep RECs) $9,480,000 $160,000

5.1.6 Battery
The modeled battery achieves a levelized cost of storage of $253 per kWh and positive net economics for each price scenario. Since the battery does not quality for RECs there is no revenue associated with it. A 30% ITC is assumed. Again the battery was designed and modelled as completely separate from solar or wind, aside from the consideration of maximum interconnection power and the RA price calculation (which changed with co-located solar and battery, but is a layer of complexity more appropriate for a later phase of study). In principle DCE could install just a battery and pass on the savings to its rate payers.

Table 7. Modeled Battery Energy Storage Annual and Lifetime Economics 2023 2024
Annual
Revenues
Wholesale Market $758,000 $532,000
Resource Adequacy $439,000 $439,000
Lifetime
(20 years)
Revenue $9,480,000 $7,768,000
Total Expenditure $7,078,000 $7,078,000
Net $2,402,000 $690,000

5.2 Technical Feasibility
Technical feasibility for each resource type ranges from okay to excellent, in qualitative terms, however the solar carport, field, and trackers have been identified as technically incompatible with the ACCESS project or at too large of a risk of flooding. This primarily leaves wind and the solar carport as generation choices.

Table 8. Summary of Technical Feasibility by Resource
Asset Feasibility Note
Solar good walkway incompatible with ACCESS updates,
field and trackers understood to be flooding
prone, pending SCE review
Wind okay not much space at project site, setback
concerns, reinforced foundations

Battery excellent location above flood plain, pending SCE review Combination
of above
good need to manage maximum injection at SCE
substation
Having SCE’s completed interconnection pre-application response will help refine estimates of the interconnection capacity, and conceptualize and cost any needed infrastructure upgrades. This work will be completed in Phase 2.

5.3 Environmental Impact

5.3.1 Renewable Generation
At first approximation, estimating environmental impact and carbon savings for renewables-based microgrids, seems simple: solar and wind generate zero-carbon energy. Calculate the estimated solar production from the array or wind turbine and use the EPA Greenhouse Gas Equivalencies Calculator to estimate carbon reductions. Indeed, this is the method with which we begin.

Figure 19. Tons of CO2 Offset vs Solar Size
Carbon offset usually scales linearly with solar size or wind turbine size for the same geographic location, spacing, and tilt. Therefore, we can show the curve for carbon offset at DCE in the above figure.

5.3.2 Circular Economy
Another component of holistic environmental impact, especially when it comes to technological solutions like distributed energy resources, is the total life cycle of the equipment. That is, we must ask

where the raw material came from and how the equipment was manufactured. We must also ask where the equipment will go after it is no longer needed or no longer working.

Asking where the material comes from has long been a question in the lithium-ion battery industry, especially for Nickel Manganese Cobalt (NMC) chemistries that rely on cobalt that is rare and often unethically sourced. Luckily, lithium iron phosphate (LFP) along with other non-lithium chemistries on the horizon use more abundant materials with lower extraction impacts and also higher recyclability. Solar panels and battery modules are still largely manufactured in China, where a large percentage of power is still produced using coal and other fossil fuels. This is also changing, as the global interest in renewable power generation increases and global awareness of manufacturing sustainability increases. Therefore DCE may or may not be able to select all technologies that have a “clean” supply chain. But an awareness of the issues and a willingness to stay at the forefront of technology developments will also help.

End-of-life planning is something that is much more controllable. Some in the energy industry now believe that all projects should have an end-of-life plan as part of their initial design documentation. This is relatively new thinking for the industry. For end-of-life planning we ask:
● Can any equipment be reused? (and if yes, what is the path?) ● Can any part of this equipment be recycled?
● Of the parts of this equipment that go to a landfill, is there anything that could be toxic? ● Of the parts of this equipment that go to a landfill, how fast will they break down? For the current “state of the industry,” It is not yet clear how participating in a circular economy can be accounted in a “carbon target.” However, it is undoubtedly an important part of considering the environmental impact of a technological solution.
6 Conclusions

6.1 Key Takeaways
Transmission availability, interpreted here as interconnection or hosting capacity, is likely adequate but must be better informed by findings in the SCE WDAT Pre-Application Request. Given that the total project capacity is expected to remain below 10 MW of generation, all energy resources— solar, wind, and battery—would most likely interconnect through the nearby SCE distribution under the WDAT program. The precise interconnection capacity and any required infrastructure upgrades will need to be answered in a later phase of the study. Consideration should be paid to the combined capacity of renewable generation and battery storage, which will either be constrained by the interconnection capacity or discharge limitations would be placed on the battery.

Economic feasibility is reasonable to good for the resources that are technically feasible. The solar, wind, and battery can largely be analyzed and designed independently, with the exception of shared constraints related to hosting capacity and RA revenue. Among the generation options, wind power is more cost-effective than solar, primarily because of reduced exposure to low or negative wholesale electricity prices, but the solar carport is reasonable to pursue as well. Battery storage is also economically favorable and doesn’t necessarily depend on having co-located wind or solar, but may be

more vulnerable to high foreign import tariffs. Other factors affecting financial viability include projected declines in both wholesale energy and resource adequacy prices.

6.2 Next Steps
Building on the success of this initial, high-level feasibility study, we advise the following steps:
● Review the SCE Pre-Application Request and determine the site interconnection capacity ● Consider different ownership structures from a legal and cost standpoint ● Continue with Phase 2 to refine the economic performance and technical implementation considerations, as well as to look for areas of improvement ● Consider whether DCE would keep (“retire”) or sell any RECs muGrid Analytics looks forward to supporting DCE in continuing to achieve their energy goals. 7 Acknowledgements
This study was performed and report written by staff at muGrid Analytics:

Amy Simpkins, CEO and Lead project manager
Dr. Travis Simpkins, CTO and technoeconomic specialist
Michael Wood, Senior Engineer
Special thanks to The Energy Authority for contributing price data and revenue calculations.

The study was conducted in collaboration with Southern California Edison.

ITEM 7C

STAFF REPORT
Subject: Pre-Pay Bond Financing Overview and Selection of Initial Services Contact: Lisa McNeilly, Director of Energy & Sustainability ([email protected]) and Claude T. Kilgore, Director of Finance ([email protected]) Recommendation: Authorize the Executive Director to take the necessary steps to establish pre-payment bond financing including 1.) executing, in partnership with Redwood Coast Energy Authority (RCEA), agreements with Municipal Capital Market Groups, Inc. managing directors John Norman and Tyler Noble to provide prepayment advisory and related services for a total, shared cost not to exceed $350,000 and 2.) select and negotiate agreements with Project Participant Legal Counsel at a total, shared cost not to exceed $300,000 and 3) work with RCEA to apportion costs of the pre-pay equitably Background: Renewable energy pre-payment bonds (also known as green bonds) are a way to reduce the cost of renewable energy and provide savings to customers through a special legal framework available to public entities like Community Choice Aggregators (CCAs), including DCE.

Such bonds have been in use for years by cities and other tax-exempt entities to contract for natural gas at discounted prices, and used by CCAs since 2021 to achieve substantial savings for customers. In general, the costs of long-term renewable energy contracts (like Power Purchase Agreements or PPAs) are pre-paid for a supply of electricity from a taxable entity and the CCA funds that prepayment with tax-exempt municipal bonds.

The California Community Choice Financing Authority (CCCFA), a California joint powers authority founded by five CCAs, serves as a low-cost conduit to issue these green bonds. The bonds issued are off-balance sheet and non-recourse to the prepay participant (in this case, DCE), while also remaining ratings neutral to positive. There is no obligation to pay for debt issued, only to pay for power delivered. In this structure, a CCA accesses tax-exempt bonds through CCCFA and uses the bond proceeds to secure a 30-year energy supply from the Prepaid Supplier. The Prepaid Supplier then loans these proceeds to an intermediary bank at a taxable rate. The Prepaid Supplier pays energy sellers the full contract price, while CCCFA charges the CCA a discounted rate. The difference is typically about eight to 10 percent or more depending on market conditions, resulting in a discount for the CCA. Banks accept this discount since they gain underwriting fees and other benefits from the deal.

As part of the broader efforts to address DCE costs and long term financial stability in an ever changing market, DCE staff has started exploring the opportunity of pre-payment bonds for DCE.

Staff is now recommending the Board endorse the approach and provide some initial authorizations to the Executive Director to bring an advisory consultant and specialized legal counsel on board. Additional steps would come back to the Board for additional approvals in the future.

A CCA looking at green bonds must work with current PPA counterparties to assign existing and future PPAs into the prepayment transaction. DCE staff have determined that it does not have enough volume under long-term contract to pursue a pre-pay agreement alone, so staff has Desert Community Energy Board
November 20, 2025
identified a CCA partner – Redwood Coast Energy Authority (RCEA) – on a joint undertaking. If approved by their respective Boards, this will be the first pre-pay deal for both CCAs.

The primary risk in the green bond process is early termination of the prepayment transaction. If the transaction ends before maturity because of supplier default, failure of a related swap or investment agreement, or loss of Qualified Use, DCE would stop receiving the projected future savings and return to ordinary energy procurement. In practical terms, DCE would be in essentially the same position as if the prepayment had never occurred. The financial risk of the bonds lies with the bank. The bonds are issued on the bank’s credit and carry the bank’s rating.

Bondholders have no recourse to DCE upon early termination and would look to the bank and any guarantors under the financing documents. DCE pays only for energy actually delivered and does not assume the prepayment debt or any obligation to make investors whole. A related risk is load variability, including potential large customer departures. Lower retail load could reduce the volumes DCE can take under the prepayment and diminish achievable savings. This does not create liability to bondholders. Typical mitigations include conservative sizing to low-case load and remarketing rights for excess energy. If excess volumes cannot be remarketed to a qualified purchaser, savings may decline and certain tax requirements may require structural adjustments.

As is the case with early termination, DCE would stop receiving the projected future savings and return to ordinary energy procurement, leaving DCE in essentially the same position as if the prepayment had never occurred.

Recommended first steps
An important early step in this green bond process is the selection of a municipal financial advisor to act as fiduciary to DCE and RCEA (the Joint CCAs). This fiduciary serves several roles and will help the Joint CCAs navigate all aspects of the pre-payment transaction. In addition to evaluating other potential consultants (like the prepaid suppliers and underwriters, tax counsel, funding recipients), the fiduciary can assist with bond pricing, research and analytics, disclosure documents, negotiating commodity and interest rate swaps, and guaranteed investment contracts. The services are usually fixed-fee contracts and contingent on the closing of the transaction. The entire pre-payment process could take six months or longer depending on market conditions.

Staff from DCE and RCEA evaluated proposals from the only two known providers of municipal advisory services to CCAs: Municipal Capital Markets Group, Inc. (MCM) and PFM Financial Advisors LLC. CCCFA requires that the financial advisor be certified by the Municipal Securities Rulemaking Board and have previously advised on electricity pre-pay issuance in California1 ,
which limited the pool of applicants. Staff met with representatives from each firm, evaluated the proposals, and contacted reference checks to understand the proposed fee structures and services offered. Ultimately, MCM advisors John Norman and Tyler Noble was selected as finalist.

Mr. Norman and Mr. Noble, both managing directors of MCM, have been the financial advisors in 110 energy prepayments since 1994, totaling over $72 billion. In addition, they assisted in the creation of the CCCFA and led some of the very first green bond deals for CCAs. Their current CCA clients include Marin Clean Energy and Clean Power Alliance of California (CPA). MCM advised CPA on a $1.52 billion green bond deal issued in September 2024 that was a national winner in the Green Financing category by The Bond Buyer, a national trade publication for excellence in financing for a public purpose. They also assisted CPA in a December 2024 deal with Goldman Sachs that is largely recognized as the largest cost-savings for a CCA to date. 1 https://www.cccfa.org/uploads/1/3/8/3/138337146/cccfa_- _policies_and_procedures_for_prepayment_bonds__final__402372.5__with_appendix_v2.pdf In addition to the advisors, DCE staff recommends authorizing the DCE Executive Director to select and enter into a legal counsel agreement for Project Participant Counsel. Specialized legal counsel is essential for advising on counterparties and negotiating agreements in prepayment financing, with Program Participant Counsel being the first required appointment before selecting bond and tax counsel which usually follows once the prepaid supplier is selected. DCE will work with RCEA to identify the best method for procuring legal counsel whether that be a sole-source justification, piggyback of a similar agreement from another CCA, or issuing a standalone Request for Proposals.

With this item, staff is recommending the Executive Director be authorized to execute joint agreements with RCEA contracting Municipal Capital Market Groups, Inc., specifically their managing directors John Norman and Tyler Noble, and to negotiate and execute a contract for specialized legal services. A future staff report will further outline next steps once the prepayment advisory services are approved by the Board, which would include identifying and selecting the prepay counsel, issuing an RFP for counterparty supplier and intermediary bank, selecting bond and tax counsel, and gaining membership in CCCFA.

Fiscal Analysis: The total costs of the recommended agreements is for a not-to-exceed amount of $650,000. These costs will also be split between DCE and RCEA at an equitable rate as to be determined by transaction volume of each respective CCA or similar method. These costs for DCE are currently estimated at between 40 and 50 percent of the total.

The total cost of the agreement with MCM is expected to be DCE’s equitable share of $350,000 based on total transaction volume split between RCEA which is still being finalized. This includes not to exceed $300,000 and related bidding agent services for Guaranteed Investment Contracts (GICs) not to exceed $50,000. These costs are contingent on the transactions closing and payable out of the deal proceeds. Legal counsel fees are being procured and they would be for a not-to-exceed shared amount of $300,000. This amount will be better understood once the CCAs are further in the prepayment process and any amounts over this will come back to the Board.

Prepayment financing is a long-term financing strategy that allows tax-exempt entities such as CCAs to achieve substantial savings on power procurement by capitalizing on the spread between tax-exempt and taxable interest rates. DCE’s primary objective in pursuing a prepayment financing structure is to secure meaningful reductions in energy procurement costs. Based on preliminary analysis, the transaction is projected to generate approximately $0.8 to $1 million in annual savings, though actual results will depend on the PPAs included in the transaction and prevailing market conditions. Any discount in energy costs achieved through the prepayment structure will flow directly into DCE’s financial position. Fees for service providers are contingent on a successful close and will be paid from bond proceeds, resulting in no out-of-pocket costs for DCE. If the transaction does not proceed, DCE’s only direct expenses would be its share of the CCCFA membership and general administrative fees (approximately $75,000) and rating agency fees (estimated at $250,000), the remaining share of these costs would be with RCEA, DCE’s prepay CCA partner.

Staff would add that the debt obligation is non-recourse to DCE. This means DCE only pays for energy when it is delivered. DCE has no liability for bond repayment or other debt obligations in the event of a default by the Prepaid Supplier or the bank. In addition, rating agencies do not treat prepayment transactions as debt or fixed costs for DCE.

ITEM 7D

STAFF REPORT
Subject: Update on Factors Impacting DCE’s Fiscal Year 2025-26 Budget Contact: Lisa McNeilly, Director of Energy & Sustainability ([email protected]) and Claude Kilgore, Director of Finance ([email protected]) Recommendation: Information
Background: In June 2025, the Board approved DCE’s Fiscal Year 2025-26 (FY26) Budget. The approval came after DCE staff shared details on the key assumptions, facts, and figures used to develop the budget and discussed several fiscal policy changes. Notably, the improved budgeting process provides rate-setting flexibility to ensure DCE meets its annual revenue requirements, which is measured in the form of DCE’s Fixed Charge Coverage (FCC) ratio. In the FY26 budget document, DCE staff committed to monitor DCE’s liquidity and FCC ratios throughout this fiscal year. Staff is also monitoring Southern California Edison’s (SCE) Power Charge Indifference Adjustment (PCIA) and Market Price Benchmarks (MPB), regulatory filings, power supply costs, retail sales receipts and customer load, climate impacts, and other elements.

Staff is now tracking several likely impacts to the FY26 budget – both positive and negative – due to factors that have changed since budget adoption. Most significantly, SCE’s 2026 Energy Resource Recovery Account (ERRA) update in October 2025 included drastic increases to the PCIA and changes to the MBPs, directly affecting DCE’s revenue. The full impact of these and other changes to the FY26 budget are still being evaluated by DCE staff, who anticipate a need to bring a budget amendment to the Board in early 2026. At the November 20 meeting, DCE staff and consultants from The Energy Authority (TEA) will provide an overview of some factors that will ultimately be incorporated into a mid-year budget adjustment. These factors are discussed further below.

Power Charge Indifference Adjustment (PCIA or exit fee): The PCIA is a fee charged by SCE to all Community Choice Aggregator (CCA) customers, including those served by DCE. The fee recovers SCE’s above-market costs for power resources contracted before the departure of the CCA customers and can vary widely from year to year because of the complexity of the inputs that determine the fee. The PCIA for DCE is positive when the market value of SCE’s power resources and all its products is lower than the original costs of the underlying energy contract; a positive PCIA reduces DCE’s retail revenue. The market value is determined by the current prices of electricity and the value of products like Resource Adequacy (RA) determined by MPBs. The PCIA can be negative when the opposite is true, and a negative PCIA increases DCE’s retail revenue. In recent years, the PCIA has been negative, which benefited DCE's financial results.

However, as explained below, this trend is now shifting to a less favorable position.

In June 2025, the California Public Utilities Commission (CPUC) released Decision 25-06-048 that adopted changes to the calculation of the RA Market Price Benchmark (MPB). Aiming to reduce the rate volatility caused by the PCIA, this Decision reduces the number of RA MPBs from three to one, and uses more years of data to calculate the 2025 and 2026 RA MPBs. The impact of this change has been to significantly lower the RA MPBs, which will raise the PCIA for DCE Desert Community Energy Board
November 20, 2025
customers by around 300%, switching it from positive to negative. This switch will reduce DCE revenues, since DCE generation rates will reduce to balance out the PCIA rate increase. The material increase in the 2026 PCIA is expected to decrease DCE’s Fiscal Year 2025-26 Retail Revenue projection by $4 million to $6.5 million.

Power Costs and Market Price Benchmarks: While changes in the MPBs and the market value of power resources increase the PCIA, there are some positive impacts on the total budget. The lower RA MPB will have a small beneficial impact on DCE’s power costs, since some of DCE’s RA purchases are priced based on the RA MPB. Similarly, some of DCE’s Renewable Energy Credit (REC) purchases are priced based on the RPS MPB, so a similar reduction in the RPS MPB also benefits DCE’s power costs. Finally, DCE’s power procurement strategy balances risk reduction with market price trends. Over the past calendar year, DCE has been able to execute periodic sales of surplus RECs and surplus RA at prices higher than the current MPBs. Given the lagged nature of the MPB, future prices are currently lower than the MPB, limiting opportunities for additional net revenue generating sales. DCE staff and TEA continue to attempt power procurement optimization by marketing surplus attributes when possible. The decline in the RA and RPS MPBs and the sale of surplus attributes is expected to decrease DCE’s power costs by $4 million to $5.3 million for Fiscal Year 2025-26.

Mid-Term Reliability (MTR) Regulatory Costs: Another recent CPUC Decision (D 25-09-007) eliminates the need to procure short-term ‘bridge’ contracts to cover delays in meeting certain MTR requirements and will also result in lower power costs for DCE by $500,000 to $1 million.

Staff anticipates additional MTR requirements in the future beyond what has already been procured, but the extent of the budget impacts is not known at this time.

SCE Energy Resource Recovery Account (ERRA): As noted above, SCE released its 2026 rate expectations via the Fall Update on October 15, 2025, and via an Amended Fall Update on October 27, 2025. SCE’s Amended Fall Update corrected errors related to SCE’s generation revenues and RA position. DCE staff’s evaluation of DCE’s Fiscal Year 2025-26 financial outlook under the Fall Update and under the Amended Fall Update finds that the 2026 rate expectations per the Amended Fall Update are marginally favorable. Staff will monitor any future revisions to SCE’s Fall Update.

Forecasts versus Actuals for Load and Revenue: Electricity use in DCE territory can be difficult to predict, especially for the hot summer months. The total load can be very dependent on weather, but predictions about the pace of electrification, economic activity, and other factors also impact forecasts. The relative percentage of Carbon Free customers can also impact forecasted revenues. Actual use fluctuates from year to year, with June and September being the most difficult to predict. Recently, retail revenues have been noticeably below forecast, although the trend reversed for September. Staff are now monitoring this trend and working to understand all the factors behind the discrepancies. If a declining load trend were to continue into 2026, Fiscal Year 2025-26 Retail Revenue projections could decrease by $1 million to $5.3 million.

Clean Energy Procurement for Desert Saver Rate Schedules: DCE’s Carbon Free retail product provides 100% carbon-free energy to all Carbon Free customers. This requirement is documented each year in the Power Content Label that is posted online (and also included in the November agenda packet). Since its launch, DCE has procured additional carbon-free energy, based on a percentage of the current year’s forecasted load for Desert Saver customers. If actual loads are higher than forecasted loads, this conservative approach helps guarantee that the Carbon Free product will be 100% carbon free. On occasion, DCE loads have been low enough that this approach has meant that the Desert Saver product was also 100% carbon-free. Staff are evaluating the potential cost impacts of this procurement practice and expects to reduce some excess procurement in 2026, while maintaining full achievement of state mandates and core environmental goals. Continuing to refine this procurement approach and stabilizing Desert Saver Power Content Label outcomes could result in savings between $250,000 to$750,000 annually.

Pre-pay agreement: As discussed in a separate agenda item, DCE staff is recommending working with another CCA on bond pre-payment arrangements. Pre-payment bonds are a way to reduce the cost of purchasing power through a special legal framework available to public entities like DCE. Ultimately, successful prepayment structures will reduce the cost of renewable energy for customers. The cost savings can be anywhere from eight to 10% of total contract costs, depending on market conditions. Some CCAs have saved over 15% on their power contracts. For DCE, the average estimated savings could be roughly $8 million to $12 million over the term of the agreement based on current power purchase and energy storage agreements.

Fiscal Analysis: The financial impact of each of these items is included in the report’s background. DCE staff anticipate a need to bring a mid-year budget adjustment to the Board at an upcoming meeting, likely early in 2026. First quarter’s budget to actuals will be also provided at the next Board meeting; preliminary results through September 30, 2025 indicate a projected decrease in net position of $2.9 million ($1.2 million versus a budgeted amount of $4.1 million).

ITEM 8A DESERT COMMUNITY ENERGY BOARD
FY 2025-26 ATTENDANCE RECORD

FEB MAR APR MAY JUNE
City of Palm Desert * *  *
City of Palm Springs * *  *
Absent
No Meeting *
Voting Members JUL AUG SEP OCT NOV DEC JAN
ITEM 8B

STAFF REPORT
Subject: 2024 Power Content Label
Contact: Lisa McNeilly, Director of Energy and Sustainability ([email protected]) Recommendation: Information.

Background: All retail sellers of electricity, including Community Choice Aggregators such as DCE, are required by Senate Bill 1305, codified in Section 398.1 of the California Public Utilities Code, to disclose “accurate, reliable, and simple-to-understand information on the sources of energy” that are delivered to their customers each year. As part of this process, the DCE Board historically adopted a resolution to approve the Power Source Disclosure (PSD) Annual Reports and Power Content Label (PCL) each year.

The CEC requires DCE to send the annual PCL to all active customers via mail or email, depending on the customer's preference, by December 31, 2025. On June 3, 2025, CEC staff notified DCE that it would generate the 2024 PCLs for all CCAs by mid-September and that it no longer requires Board approval. Because of this, DCE staff is including its 2024 PCL as an informational item.

As noted in the PCL, DCE provided 100% carbon-free energy to Carbon Free customers, including 57% renewable energy eligible under the state’s Renewables Portfolio Standard (RPS) purchased from solar facilities (19%), wind facilities (38%), and small hydropower facilities (1%).

The remaining carbon-free energy was purchased from large hydropower facilities (12%) and nuclear facilities (30%), which are not considered renewable under the RPS.

DCE is estimated to have provided Desert Saver customers with an energy supply consisting of 17% renewable energy eligible under the RPS, which was purchased from geothermal facilities (2%), solar facilities (9%), wind facilities (5%), and small hydropower facilities (less than 1%). The remaining energy was purchased from large hydropower facilities (less than 1%) and nuclear facilities (83%).

This is the first time in which its Carbon Free and Desert Saver products have both achieved a zero-to-low intensity of greenhouse gas emissions (GHG) measured in pounds of CO2e emitted per megawatt-hour. For context, the term CO₂ equivalent (CO₂e) is a standard unit for measuring carbon footprints, quantifying the impact of different greenhouse gases in terms of the amount of CO₂ that would create the same amount of warming.

The attached DCE 2024 PCL for Carbon Free and Desert Saver has been prepared by the CEC.

Based on CEC Staff’s review of DCE’s data, the information presented in the 2024 PCL is determined to be accurate. Per CEC requirements, DCE posted the 2024 PCL to its website on October 1, 2025.

Desert Community Energy Board
November 20, 2025
Fiscal Analysis: There is no additional cost to DCE for this informational item.

Attachment: DCE 2024 Power Content Label

2024 POWER CONTENT LABEL
Desert Community Energy
Carbon Free Desert Saver CA Utility Average
Greenhouse Gas Emissions Intensity
(lbs of CO2e emitted per megawatt hour) 0 3 359
Electricity Sources
■ Renewables and Zero-Carbon Resources
■ Fossil Fuels and Unspecified Power
RPS Eligible Renewables 57% 17% 45%
Biomass & Biogas 0% 0% 2%
Geothermal 0% 2% 5%
Eligible Hydroelectric 1% 0% 2%
Solar 19% 9% 23%
Wind 38% 5% 14%
Large Hydroelectric 12% 0% 10%
Nuclear 30% 83% 11%
Emerging Technologies 0% 0% 0%
Other 0% 0% 0%
Natural Gas 0% 0% 10%
Coal & Petroleum 0% 0% 2%
Unspecified Power (primarily fossil fuels) 0% 0% 22%
Total 100% 100% 100%
Retail sales covered by retired unbundled RECs 0% 4%
■ This label does not reflect compliance with the Renewables Portfolio Standard (RPS), which measures the use of tracking instruments called Renewable Energy Credits (RECs) over the course of multi-year compliance periods. RECs that are purchased separately from the renewable energy ("Unbundled RECs") can be used for RPS compliance, but they do not factor into the power mixes or GHG emissions intensities above. ■ GHG intensity figures exclude biogenic CO2 and emissions from geothermal sources and grandfathered imports of firmed-and-shaped energy. For detailed information about all GHG emissions from California's retail electricity suppliers, visit the CEC webpage at the link below.
■ Unspecified power is electricity purchased from a genericized pool on the open market. https://desertcommunityenergy.org/about/key-documents/
Want to learn more?
Visit https://www.energy.ca.gov/programs-and-topics/programs/power-source-disclosure-program ITEM 8C

STAFF REPORT
Subject: Update on Establishing DCE’s Energy Efficiency Program Contact: Eman Nazir, Management Analyst ([email protected]) Recommendation: Information
Background: At its September 2025 meeting, the DCE Board authorized staff to establish DCE’s first self-administered energy efficiency initiative — the Community Energy Savings Program — including preparing and submitting a Tier 3 Advice Letter and Elect-to-Administer (ETA) application to the California Public Utilities Commission (CPUC). The program, if approved by the CPUC, would be designed to reinvest Public Purpose Program funds to benefit local customers, with a request of approximately $300,000 over three years to support direct installation of energy efficient equipment for small businesses and distribution of free savings kits.

Since the September meeting, staff has worked with Frontier Energy, DCE’s consultant, to finalize and validate the technical components of the application, including detailed modeling using the CPUC Cost-Effectiveness Tool and verifying supporting documentation required for ETA certification.

The Tier 3 Advice Letter and Program Plan is scheduled to be submitted to the CPUC by mid-November 2025. Only minor refinements were made to programmatic design elements, and the overall program remains largely in line with what was presented to the Board in September. The submission package includes the finalized Program Implementation Plan, completed the required cost-effectiveness modeling, a letter of support from the City of Palm Springs, and all required supporting documentation. Once submitted, DCE staff will post the Advice Letter on the DCE website.

Following submittal, the next step in the process will be review and certification by the CPUC.

Staff will continue to monitor the proceeding and provide regular updates to the Board as milestones are reached. Staff will also return to the Board after CPUC approval to finalize the program delivery details and community outreach to ensure the program remains effective, responsive, and aligned with CPUC guidance.

Fiscal Analysis: There cost to DCE for this informational update. All preparation and technical work remain within approved resources, and ETA funds are expected to cover all program implementation costs.

Desert Community Energy Board
November 20, 2025
ITEM 8D

STAFF REPORT
Subject: Summary of October and November 2025 Rate Adjustments Contact: Lisa McNeilly, Director of Energy and Sustainability ([email protected]) and Don Dame, DCE Energy Consultant
Recommendation: Information
Background: On November 16, 2020, DCE adopted a Rate Stabilization Schedule (RSS). The RSS became effective on December 1, 2020, and was amended by the Board on May 12, 2023, with an effective date of June 1, 2023. A second amendment was approved on March 17, 2025, with an effective date of April 1, 2025. The RSS authorizes staff to adjust DCE retail rates in response to changes in Southern California Edison (SCE) rates and/or the Power Charge Indifference Adjustment (PCIA, or exit fee), State of California regulatory mandates, and to follow DCE Board-approved rate guidelines outlined in RSS Exhibit A. The March 17, 2025, RSS amendment clarified that DCE staff may also adjust DCE rates due to revenue and/or cost variances identified through DCE’s budgetary/revenue requirements processes so long as it stays within the Board-approved guidelines.

The Board’s currently approved RSS Exhibit A Rate Adjustment Guidelines include: 1) designing Desert Saver rates within a 0-1% average total bill discount versus SCE’s comparable bundled non-California Alternative Rates for Energy (CARE) base product average total bill; and 2) designing DCE’s 100% Carbon Free residential rates such that DCE meets its annual revenue requirements as identified in DCE’s budget process, as such requirements may change during the budget year. Any single RSS rate adjustment may not exceed a plus or minus five (5.0) percent change to DCE’s average generation rates, without Board approval. A separate agenda item seeks Board’s approval for a clarification of Exhibit A.

The RSS requires DCE staff to prepare a summary report describing RSS-related rate adjustments and to provide this information at the next scheduled Board meeting following implementation of such adjustments. This staff report provides a summary of DCE’s October and November 2025 rate adjustments.

October 2025 Rate Adjustment Summary:

Effective October 1, 2025, SCE implemented a system-wide average rate increase of approximately 13.0% that included an average non-CARE residential customer rate increase of about 12.9%. SCE’s average non-CARE bundled residential customer bill increased by approximately $23.86 monthly, based on average monthly consumption of 541 kWh.1 For customers enrolled in CARE and Family Electric Rate Assistance (FERA) plans, SCE’s average 1 October 2025 SCE average monthly bill changes were derived from SCE’s October 1, 2025 Rate Advisory and CPUC Decision Fact Sheet dated September 18, 2025 for SCE’s General Rate Case Proceeding Number A.23-05-010, and adjusting average monthly residential energy consumption from 500 to 541 kWh per month.

Desert Community Energy Board
November 20, 2025
bundled residential customer bill increased by about $15.49 monthly inclusive of ongoing CARE/FERA average billing discounts of approximately 32.5% and 18%, respectively. As approved by the California Public Utilities Commission (CPUC), SCE’s revised rates reflect changes to multiple components of its consolidated revenue requirement.

Working within DCE Board-approved financial policies and procedures, the provisions of DCE’s RSS, and the concurrence of DCE’s Risk Management Team (RMT), DCE adjusted its Desert Saver rates to maintain an average 0.0 – 1.0% discount versus SCE’s bundle base product average monthly bills for all Desert Saver customers. No adjustments were made to DCE’s generation rates for Carbon Free customers. It should be noted, however, that Carbon Free customers experienced a monthly average bill increase due solely to changes in SCE’s delivery charges. The adjustments to DCE’s Desert Saver rates became effective on October 1, 2025, or as soon thereafter as practicable.

October 2025 DCE Rate Adjustment Details:
• Effective Date: October 1, 2025 (or as soon thereafter as practicable, upon implementation of DCE's revised rate factors)
• RMT review and concurrence: September 30, 2025
• Desert Saver average total bill discount compared to SCE’s bundled base power product average total bill designed to range within 0 – 1% for all Desert Saver customers • No change to DCE’s average Carbon Free generation rates • Rate forecast period utilized: October 1, 2025 – September 30, 2026 • Calculations and estimates are based on known and forecast costs and revenues throughout the rate forecast period
• Any individual customer’s average bill impact may vary depending on enrolled rate schedule and monthly electricity usage pattern
November 2025 Rate Adjustment Summary:

DCE’s RSS provides that DCE Carbon Free generation rates may be adjusted by up to 5.0 percent during any given month due to unplanned and/or unexpected power supply and operating cost changes. As staff will preview at the November meeting, DCE is projecting reduced Fiscal Year 2025-26 net revenues based on several regulatory changes and on lower than forecast retail load levels. Effective November 1, 2025, DCE implemented an average Carbon Free generation rate increase of approximately 4.5 percent to help offset reduced retail revenues and to help preserve financial reserve margins.

Working within DCE Board-approved financial policies and procedures, the provisions of DCE’s RSS, and the concurrence of DCE’s RMT, DCE increased its Carbon Free generation rates approximately 4.5 percent or about $4.90 monthly on an average Carbon Free customer bill. No adjustments were made to DCE’s generation rates for Desert Saver customers in November, and Desert Saver customer average monthly bills were not affected.

November 2025 DCE Rate Adjustment Details:
• Effective Date: November 1, 2025 (or as soon thereafter as practicable, upon implementation of DCE's revised rate factors)
• RMT review and concurrence: October 22, 2025
• Carbon Free average generation rate increase of approximately 4.5 percent • No change to DCE’s average Desert Saver generation rates • Rate forecast period utilized: November 1, 2025 – October 31, 2026 • Calculations and estimates are based on known and forecast costs and revenues throughout the rate forecast period
• Any individual customer’s average bill impact may vary depending on enrolled rate schedule and monthly electricity usage pattern
Fiscal Analysis: DCE’s rate adjustments are designed to fully recover forecast power supply and operating costs, build financial reserves, address cash flow requirements, achieve a 2.0 Fixed Charge Coverage (FCC) ratio per Standard & Poor (S&P) guidelines, meet DCE’s revenue requirements, and exercise fiscal prudence.

As it pertains to the October adjustment, SCE customer retail rates were revised effective October 1, 2025, and DCE coincidently adjusted DCE Desert Saver generation rates. The average monthly bill of SCE bundled non-CARE residential customers increased about $23.86; DCE non-CARE Desert Saver residential customers average monthly bill increased by about $23.74, due to SCE’s increase in delivery rates. DCE Carbon Free residential customer average monthly bill increased by about $23.86, based solely on changes to SCE delivery rates; there were no changes to DCE Carbon Free generation rates. Staff would also note that California residential and qualifying small commercial electricity customers received a State mandated climate credit to October bills which may offset all or a portion of SCE’s rate increase during the first month of implementation.

As it pertains to the November adjustment, DCE’s Carbon Free generation rates increased approximately 4.5 percent effective November 1, 2025, or as soon thereafter as practicable. The corresponding average monthly bill of DCE Carbon Free residential customers increased approximately $4.90. DCE’s average monthly residential customer’s total bundled bill will increase about 2.0 percent, inclusive of both SCE and DCE charges. DCE’s Desert Saver generation rates were not changed.

Staff continues to work with the California Community Choice Association (CalCCA) and other Community Choice Aggregators (CCAs) to collectively address cost-effectiveness, and legislative and CPUC actions impacting CCAs. Additionally, DCE will continue to highlight DCE’s retail product choices as part of community engagement efforts. DCE’s Desert Saver product continues to be the least cost retail electric service in Palm Springs, and DCE’s Carbon Free product results in zero carbon emissions, augmenting electricity-related climate mitigation and helping the City of Palm Springs achieve its greenhouse gas reduction goals.