— by Kristina Shih

The CA PUC’s rejection of the Net Value Billing Tariff – which would have opened up an 8 GW community solar market and was supported by an unprecedented broad base of stakeholders – is a sobering reminder of the political and economic barriers to the future growth of distributed energy resources (DERs). It’s simply not enough to rely upon ambitious RPS goals to compel utilities to accommodate new DERs. As self-interested entities controlling energy access, they are naturally threatened by anything that empowers consumers with more choice and less reliance on their monopolistic business models. This paradox is reflected in a highly fragmented energy market for DERs, with policies subject to the political whims of regulators and utility influence.

The community solar industry has done a tremendous job creating a financeable asset class by advocating for enabling legislation benefiting third-party ownership models, expanding the addressable market for new projects and subscriber customers. But the CA PUC’s decision highlighted the limit to this approach for industry expansion, and the “next wave” of new markets in Pennsylvania, Wisconsin, Michigan, and Ohio still have a long road from passing enabling legislation to program implementation. At the Community Solar Policy Innovation Summit last week in Denver, there was general agreement among attendees that the industry will face a “long winter” before another new market opens up; following the failure of NVBT, most developers are now focused on executing in their current core markets rather than investing in new market expansion over the near term.

It’s time for community solar advocates to re-think how current business models can evolve as part of a broader DER solution within regulated and unregulated energy markets. Given the reality of who controls the grid, we need to think about the political/economic nexus where utilities and DERs can co-exist, rather than relying solely on policies that are essentially cramming a square peg into a round hole. CCSA has successfully crafted community solar policies that demonstrate energy savings to all ratepayers, but the utilities continue to sideline the debate with the age-old stance that DERs hurt ratepayers. Instead, the industry should reframe the benefits to address key categories the utilities can’t ignore: reliability, resource adequacy, and customer engagement.  

This is not a ground-breaking new concept, as the major residential players have already pivoted towards this path. Sunrun and Sunnova are now branding themselves as virtual power plant (VPP) providers for residential and commercial customers, and have invested heavily into policy advocacy and lobbying for the future growth of VPPs. They’re working with utilities on first-of-a kind pilots with their third-party ownership models to prove that VPPs can operationalize at scale quickly and provide load modification services during critical peak periods. This model for DER integration is more palatable to utilities as it achieves grid reliability through load management, and engage customers as “prosumers” (i.e. mitigating future pissed-off customers as rates continue to increase).     

VPPs are a hot DER topic again as community solar struggles to gain traction beyond current markets and microgrid business models have yet to scale. The term originally grew out of the world of demand response driven by large energy users and has since evolved to encompass aggregations of residential thermostats/smart controls and behind-the-meter resources like rooftop solar and battery energy storage systems. Examples of the major DER aggregators focused on demand response include OhmConnect, Leap, CPower, and Voltus, and these companies are increasingly integrating with battery, rooftop solar, EV charging and smart home energy system providers to create more value for the grid. Utilities are eagerly embracing VPPs to manage load growth as they face fossil plant retirements and huge demand increases from increasing electrification. A DOE report estimates that increasing VPP capacity from 30–90 GW today to 80–160 GW by 2030 could meet 10–20% of peak demand and save $10 billion in grid costs.

However, the current regulations defining what is included in a VPP and what type of services they should provide are far from clear. While DERs encompass many technologies impacting grid dynamics from the demand or supply side, policymaking has remained siloed amongst DER interests. Ted Ko of the Energy Policy Design Institute categorizes VPPs in tiers based on their type (individual vs. aggregation) and ultimate use for the utility (standby resource for grid services vs. ongoing resource in the wholesale or retail markets). Most utilities and ISOs treat VPPs as behind-the-meter resources, but there’s no reason why the definition can’t include front-of-the-meter DERs to address the supply side of the grid. In fact, they should be doing so because only focusing on the demand side of the equation is not going to be enough to get us a truly decarbonized future. The growth of community solar and energy storage has given utilities and regulators a road map on how to successfully integrate front-of-the-meter generators into the distribution grid, a concept that was unproven just ten years ago.

At the highest regulatory level, FERC 2222 defines “DERs as small-scale generation or storage technologies that can be located on an electric utility’s distribution system, a subsystem of the utility’s distribution system or behind a customer meter.” The ruling enables DERs to participate in the wholesale markets through aggregations, whether behind-the-meter or front-of-the-meter. So while VPPs are specifically defined by utilities based on the type of grid services provided (i.e. load reducing vs. standby capacity), the regulatory landscape is gradually setting up the VPP market to trend towards a mixed-asset model where aggregators can use renewable generation sources, controllable flexible loads and energy storage assets to better serve and balance the grid.

A more heterogenous VPP market means a greater need for clearer rules of engagement, but policy discourse has historically been focused on those issues most relevant to today’s community solar programs (i.e. interconnection, bill credit mechanics), at the expense of higher-level and more creative thinking around DERs. The community solar industry should be engaging with other stakeholders to think holistically about how heterogenous DERs can interact together, creating a foundation upon which DER platforms can develop and finance assets at scale. We all should be working together collectively to influence distribution system planning, establish interoperability standards, and create market mechanisms that compensate DER aggregators on both the demand and supply side of the grid. Doing so will enable existing community solar platforms to unlock additional revenue streams beyond bill credit sales or REC monetization and diversify their product offerings.

Community solar and other front-of-the-meter distributed generation remains a relevant part of the future decarbonized grid. With transmission-level solar and storage projects facing increasing queue congestion, NIMBY-ism, and increasing concerns about their environmental impacts, utilities must consider distribution-level projects as critical resources for meeting their clean energy goals. Despite what they might argue, there is still a lot of headroom to integrate more solar at the distribution level without being too disruptive. California’s recent policies have called into question its ability to be a thought leader for a decentralized grid, but other states like New York and Illinois have embraced distributed generation as a key pathway for their state decarbonization goals. New York has integrated over 5.5 GW of DG solar (behind-the-meter and front-of-the meter, including 2 GW of community solar) into a grid which had 32 GW of peak load in 2023. Maryland is another example where political will has been intentional – the state’s current Distribution System Planning Group emerged out of a broader initiative launched eight years ago by the Public Service Commission and has updated interconnection regulations, completed a time-of-use, EV, and energy storage pilots, and implemented changes to the retail supply market. Maine’s Governor’s Office of Energy is embarking on an even more ambitious initiative by currently conducting a feasibility study to establish a Distribution System Operator.

It’s tough for developers to track all the various changing regulations, let alone invest in resources to influence policymaking. But developers that want to get ahead of the game will only gain an edge by getting into the policy weeds. This involves the tedious task of wading through complex dockets, tariffs, program rules, etc., but I’ve found that the smartest developers in the room tend to be the ones that actually read the fine print. Traditional community solar programs will continue to bring a lot of near-term impact to the grid, but there will be pockets of new DER participation models with different utilities and ISOs, and speeding up new market creation can only be achieved by pushing the industry’s various trade associations to collaborate on intentional policymaking. Instead of partaking in adversarial policy fights with regulators, we should be working together to design DER policies grounded on shared goals between the utilities, private sector and customer interests.