California is the poster child for distributed energy resources (DERs).
It has huge volumes of distributed assets, ambitious flexibility targets, progressive interconnection rules, and, as of today, is the only ISO/RTO to have fully implemented FERC Order 2222. And California is still moving forwards: new legislation and regulatory work are creating more ways for DERs to support the grid and be valued for doing so.
But one of its biggest VPP programs still faces an uncertain funding future.
California’s Demand Side Grid Support (DSGS) program has grown to more than 448,000 participants and over 1 GW of estimated flexible capacity. Yet its future beyond 2026 remains uncertain, after proposals to end dedicated DSGS funding and transition participants into a separate demand-response program.
This tension raises an important question about what happens after we’ve proved distributed flexibility works.
How do we move from solely relying on individual programs and funding cycles towards an ecosystem in which DERs have enduring and repeatable routes to provide value?
California is getting serious about DER orchestration
Let’s take a look at where California is moving forwards.
The CPUC is working with stakeholders to develop a DER orchestration framework for the state’s investor-owned utilities. It is looking at how utilities gain greater visibility of DERs, make them more dispatchable, improve TSO–DSO coordination, and use them more effectively as part of the grid.
That builds on several regulatory moves:
- FERC Order 2222: CAISO completed implementation in November 2024, opening wholesale markets to aggregated DERs.
- Rule 21: California is developing more flexible approaches to DER interconnection. This includes limited generation profiles that allow exports to respond to available grid capacity.
- Senate Bill 905: Signed into law in September 2026, this requires greater scrutiny of how efficiently utilities use existing grid capacity, creating a stronger basis for comparing traditional investment with lower-cost alternatives such as flexibility.
- Senate Bill 913: In September, California enacted SB 913, creating a pathway for aggregated DERs to qualify as resource adequacy capacity and opening a more enduring route for VPPs to be valued for what they can provide to the grid.
Together, these moves are creating more ways for DERs to participate in the grid and be recognised for the value they provide. The next question is how those opportunities become repeatable, scalable, and economically sustainable.
Orchestration only gets us so far
Orchestration can help a utility understand where DERs are, what they are doing, and when they could support the network.
I.e. A battery that can relieve a constraint in one neighbourhood at 6pm tomorrow could be more useful to a distribution utility than simply knowing there are thousands of batteries somewhere on its system.
The CPUC is considering that as part of its orchestration framework, but has not prescribed a specific mechanism. The next question is how that flexibility should be procured and valued.
That is where markets can play an important role. It offers another mechanism for utilities to procure flexibility from VPPs and aggregators, where and when it is needed.
VPPs need more than individual programs
DSGS shows what aggregation can achieve. Hundreds of thousands of customers can collectively become a significant grid resource.
However, programs dependent on individual funding decisions may struggle to provide the certainty needed to build a mature flexibility ecosystem.
DSGS isn’t the only place where California has wrestled with how flexibility becomes a more permanent part of the system. In 2025:
- AB 740 proposed a state VPP deployment strategy, including assessing VPP potential and barriers to providing resource adequacy. It was vetoed.
- AB 44 sought to allow reliable aggregated behind-the-meter flexibility to be incorporated into electricity demand forecasts. It was vetoed.
- SB 541 sought to integrate load shifting more systematically into state energy planning. This includes using DERs to reduce peak demand and infrastructure needs. It was vetoed.
In each case, the veto reflected concerns about cost, overlap with existing processes or disruption to work already underway.
Those vetoes showed how unsettled the route from successful flexibility programs to enduring grid participation remained. A year later, SB 905 and SB 913 are starting to address that gap, by creating stronger ways to recognise DER value in grid investment decisions and opening a pathway for aggregated DERs to provide resource adequacy.
But no single pathway will be enough. Programs can provide valuable long-term certainty. Markets can create more dynamic opportunities where grid needs are frequent, locational, or changing. Both have a role in meeting changing grid needs while giving DERs more opportunities to participate and earn.
The opportunity now is to build an ecosystem of programs, markets, and commercial models that gives DERs varied and repeatable routes to value. That will create the longevity needed to build performance history, improve, and ultimately become a dependable part of grid operations and planning.
FERC 2222 opens one door, not all of them
This is why FERC Order 2222 is a milestone on the road to capturing the full value of DERs.
Wholesale participation gives aggregators another opportunity to monetise distributed flexibility. But the same battery participating in CAISO could also have value to its local utility by relieving a distribution constraint.
Those opportunities need to coexist.
Our experience is that flexibility providers benefit from having multiple routes to participate. Concurrently, utilities need visibility of where assets are participating, what services they are providing, and whether commitments across different markets conflict.
The goal should be an ecosystem in which VPPs can respond dynamically to different grid needs and get paid for the value they provide.
The UK offers a useful glimpse of what comes next
Great Britain isn’t a perfect comparison for California. However, its experience with distribution system operation and flexibility markets offers a useful lesson.
As DER penetration grew, distribution networks began taking a more active role in identifying where flexibility could help manage constraints and procuring it as an alternative to, or alongside, traditional network investment.
Markets provided a mechanism to secure that flexibility. Rather than relying solely on individual programs, networks can signal where and when flexibility is needed, so that DSOs can procure it repeatedly, and build evidence of what it can deliver.
Repeated procurement creates a feedback loop that pilots simply can’t.
In markets, flex providers participate, networks procure, assets perform, data accumulates, prices become clearer, and market design improves. At the end of the loop, both utilities and regulators build a better evidence base for where flexibility works and what it is worth.
From DER participation to DER value
California is well on its way to developing the technical foundations to see, access, and orchestrate an enormous distributed resource base. VPPs provide a way of turning those individual assets into meaningful grid resources.
But technical optimization therefore needs to be matched by economic optimization.
Markets provide one mechanism to translate grid needs into opportunities for flexibility. They allow it to be procured at different timescales and in the specific locations where it can deliver value, alongside programs and longer-term arrangements where greater certainty is needed.
That gives VPPs repeatable opportunities to participate and earn, while giving utilities the performance and price signals needed to understand when flexibility is the better option.
Over time, that is how DER flexibility builds the track record needed to become dependable grid capacity.
That is the opportunity California now has: creating the conditions in which VPPs – and other sources of flexibility – can keep working without fully depending on the next pilot or funding cycle.
