Earlier this month, the California Public Utilities Commission (CPUC) issued its Proposed Decision to implement the customer community renewable energy tariff adopted in 2024. While it purports to advance implementation, critics argue it does not establish a workable community renewable energy program. According to national trade association the Coalition for Community Solar Access (CCSA), it will hurt the state at a time when it urgently needs affordable, clean energy.
In an interview with Factor This, James McGarry, CCSA’s West regional director, explains why the decision doesn’t work and how it creates barriers to meaningful customer savings and impedes the development of new projects. The conversation has been lightly edited for conciseness and clarity.
Paul: Let’s start by explaining the community renewable energy tariff recently adopted by the CPUC. What’s in it, and what does it do?
James: The CPUC’s 2024 decision (D.24-05-065) created a Community Renewable Energy Program, but left many of the key design details for a later phase. At a high level, it’s built on existing wholesale tariffs—primarily the Renewable Energy Market Adjusting Tariff (ReMAT)—with a subscription model layered on top, so customers can participate and receive bill credits tied to a project’s output. Importantly, that 2024 decision recognized that wholesale compensation alone wouldn’t support projects, and was premised on “topping up” those revenues with external state and federal funding to make the program viable.
The 2026 proposed decision is intended to finalize that program, but it largely confirms the same wholesale-based structure while acknowledging that those external funding sources are no longer available, and does not replace them with an alternative. It also directs utilities to work out many of the remaining implementation details through advice letters.
So it establishes a framework for community solar, but key practical and economic elements needed to make the program work, particularly a viable compensation structure and core program design details, are not included.
Paul: CCSA has called this decision “a significant step backward” for California community solar. Why is that?
James: The concern is that the program, as proposed, doesn’t provide a workable pathway to actually build projects or deliver customer savings.
On the economics side, the Commission is relying on a wholesale compensation structure through ReMAT that has supported only one successful distributed solar development over the last six years, while also acknowledging that the external funding that was expected to make the program viable is no longer available. At the same time, developers would be required to take on additional obligations (such as serving subscribers and providing bill credits) without any additional revenue to support them. That combination makes projects very difficult to finance.
When it comes to program design, several foundational elements are still not fully defined—particularly how bill credits translate into real customer savings, how those savings are presented, and how the program functions in practice for both low-income and market-rate customers. Rather than resolving those issues, the decision largely defers them to future utility filings.
Finally, the decision takes a narrow view of the value these projects can provide, without fully evaluating how solar paired with storage—when properly sited and operated—can reduce peak demand and lower system costs.
Taken together, the structure is unly to support meaningful project development. It also underscores the need for a fundamentally different approach—one that both compensates projects for the full range of grid services they can provide and includes a clear, workable program design that delivers real bill savings to customers and meets the program’s equity and affordability goals.
Paul: Do you really anticipate fewer projects will be constructed?
I think there’s a real risk that we don’t see any project development under the current framework.
At the end of the day, these projects need to be financeable, and that depends on both the compensation structure and the clarity of the program design. Until those pieces are more fully defined, it’s going to be challenging for developers to move forward at scale.
Paul: If you could make one or two immediate changes to the tariff, what would they be? What’s it missing?
James: The biggest opportunity is to rethink how these projects are valued.
Right now, the program relies on a narrow wholesale compensation framework that doesn’t reflect the full range of grid services these resources can provide. The Commission has acknowledged that those values depend on where and how projects are built and operated—but the tariff doesn’t incorporate that into compensation. As a result, it treats these projects generic wholesale resources, even though distributed solar paired with storage can be designed to deliver during peak-demand periods, reduce local grid stress, and avoid more expensive system investments.
A more effective approach would be to compensate projects based on the value they can actually deliver when properly sited and dispatched. The record shows that when these resources are targeted to the right locations and hours, they can reduce peak demand and lower overall system costs. Without reflecting that in the compensation structure, it’s difficult to support projects that can both deliver grid benefits and provide meaningful bill savings to customers.
Paul: This isn’t the first time distributed solar policy has furrowed some eyebrows in California. NEM 3.0 significantly reduced compensation for solar energy, to the dismay of many. Is there a trend here?
James: There is a clear trend toward more closely scrutinizing the value provided by distributed energy resources and tying compensation more directly to avoided costs. The Commission is trying to ensure that programs are cost-based and avoid shifting costs to non-participating customers—that’s an important and legitimate objective.
At the same time, it’s important that we’re capturing the full range of value these resources can provide. Distributed solar, particularly when paired with storage, can be sited close to load and operated to deliver energy during the peak demand periods that actually drive system costs. When that happens, these resources aren’t just avoiding costs—they can help reduce the need for new infrastructure and lower overall system costs.
So the opportunity for California is to build on this avoided-cost framework by making sure it reflects those capabilities. Other leading states are starting to move in that direction—treating distributed resources not as a source of cost shift, but as a tool for delivering ratepayer savings when they’re deployed and operated in the right way.
Paul: How can California better leverage distributed solar, in general? Any promising developments to look forward to?
James: One promising development is the state’s Demand Side Grid Support (DSGS) program, which is showing in real time how distributed resources, especially batteries, can support the grid when it matters most. DSGS has grown quickly into one of the largest virtual power plants in the country—potentially the largest—aggregating more than a gigawatt of flexible capacity from customer-sited resources rooftop solar, batteries, and smart devices. By compensating customers to reduce demand or export power during peak periods, it demonstrates that when distributed resources are coordinated and dispatched at the right times, they can deliver real, measurable grid value—reducing peak demand, avoiding expensive emergency resources, and lowering costs for all ratepayers.
Front-of-the-meter distributed resources (community solar paired with storage) can deliver many of these same benefits, at scale and with siting preferences that maximize grid value. Because they can be located close to load within transmission constraints and paired with storage, they can be designed to deliver during peak demand periods and relieve stress on specific parts of the grid.
And that’s especially important right now. California is facing the need for historically high build rates for new clean energy resources over the next decade just to maintain reliability. To meet that need in an affordable way, the state is going to have to lean into resources that can be deployed quickly, located near load, and targeted to the hours that matter most. Distributed solar and storage are clear opportunities to do that if we design the programs to fully capture their value.
Paul: Finally, is there any legislation in the works that might positively impact small-scale solar in CA?
James: Yes—there’s growing recognition in the Legislature that the current framework isn’t delivering a workable community solar market, and AB 1813 is a good example of that.
The bill would direct the CPUC to either fix the existing program or adopt a new one that works for customers—particularly renters and low-income households who can’t install rooftop solar. It focuses on ensuring that subscribers receive meaningful bill savings, that projects are compensated based on the avoided costs they provide to the grid, and that programs are designed in a way that benefits all ratepayers while minimizing cost impacts.
Importantly, it also pushes toward better alignment with how the state evaluates distributed energy resources more broadly—recognizing that these projects can reduce system costs when they’re sited and operated effectively. And it includes guardrails program caps, evaluation periods, and requirements to serve low-income customers, which help ensure the program delivers on its goals.
Sumber Artikel:
Renewableenergyworld.com
