California has long taken a leading role among states with its energy efficiency, renewable power, and distributed energy-grid integration efforts. But those policies have largely taken separate tracks, with little policy alignment between regulations on rooftop solar, energy storage, demand response, energy efficiency, and broader utility and grid operator investment and planning goals.
Last week, the California Public Utilities Commission quietly released a proposed decision (PDF) that could upend this fractured policy landscape. Authored by green-friendly Commissioner Mike Florio, the “Decision Adopting an Expanded Scope, a Definition and a Goal for the Integration of Demand-Side Resources” could, if approved by vote of the full commission, radically reorganize how the state manages every aspect of planning -- and paying for -- the integration of utility and third-party energy resources on the grid edge.
It’s a bold new vision, especially for a proceeding that started out in October 2014 as a rather humdrum revision of an existing 2008 proceeding, known as integrated demand-side management (IDSM). The original idea was to find better ways for existing utility demand-response and energy-efficiency programs to work to meet broader policy goals.
But in a series of workshops that Florio’s staff set up this year (PDF), distributed energy boosters such as SolarCity, the Center for Sustainable Energy, the California Energy Storage Alliance, the Natural Resources Defense Council, and other participants suggested ways to expand the proceeding’s scope of work far beyond its original mandate. Florio’s newly released proposed decision embraces their ideas almost completely, and coins a new phrase, "integrated demand-side resources," or IDSR, to encompass the outcome.
“We’re excited that the commission listened to stakeholders and is proposing a big, bold change,” Stephanie Wang, senior policy and regulatory attorney for the Center for Sustainable Energy (CSE), said in a Friday interview. “They’ve completely redefined what integrated demand-side resources are -- well, there was no definition before.”
Now there is, however -- and according to Florio’s proposal, it’s specifically tied to resources that aren’t solely controlled by utilities. As the document states, “We confirm that the integration of demand-side management is what the utilities and others offer to customers, and the integration of demand-side resources is the collective action of customers, the Commission, the Utilities, the CAISO, etc. to optimize demand-side resources to the extent possible.”
Companies are installing, managing and aggregating distributed energy resources (DERs) in these ways today, albeit on a limited scale. Some are bidding them into grid markets, through demand-response pilot projects underway at Pacific Gas & Electric and planned for California’s other utilities. Others are getting paid via utility contracts, like the distributed energy procurements that Southern California Edison signed last year.
But under Florio’s proposed regime, DER providers can suggest new methods for how they’re to receive value for what they’re doing, and can seek to apply them to a far broader set of opportunities, Ryan Hanley, senior director of grid engineering solutions at SolarCity, said in a Friday interview.
“At its heart, DER is not an individual technology; it’s a flexible, diverse portfolio that can change over time,” he said. As Florio’s proceeding expanded from looking at utility programs to a whole new range of resources, the scope of what IDSR meant “sort of changed from a limited set of use cases to 'Let’s deploy multiple assets and let them do different things in the future.'”
DERs can range from grid-aware battery-backed solar systems to price-responsive EV chargers or home automation platforms. But there’s no single way to consider these different technologies as a whole, the proposal notes -- and that needs to change, Hanley said. “We don’t know the half of what they can do eventually.”
While the proposal is awaiting feedback from future workshop sessions to better define what its next steps are, Wang noted that the underlying idea is to “create a regulatory framework to allow customers to choose from an array of DERs.” That includes “language about incentives, about valuation, and about sourcing mechanisms. I think a lot of the focus of this particular proceeding is financial signals that will get passed through to customers.”
Bringing money to the table for DERs as grid assets
One of the key steps Florio’s proposal would take to make this happen is to fill in the big “hole in the process” set up by the CPUC’s Distribution Resource Plan (DRP) proceeding, Hanley said.
Started by the CPUC last year, the DRP proceeding aims to push the state’s three big investor-owned utilities to incorporate DERs as an integral part of the operations and investment plans for their low-voltage distribution grids. Last month, Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric filed plans that include some first-of-their-kind maps and methods that could set values for DERs as part of their grid investments.
But these DRPs haven’t yet tackled how to turn this data into mechanisms for procuring DERs as alternatives to traditional grid projects, or creating new tariffs that could reward existing DERs for performing grid-supportive tasks.
Florio’s new proposal takes on that challenge head-on, pledging to “make a determination on how best to source the distributed energy resources needed by the utilities based on the determinations made in [DRP proceeding] R.14-08-013, i.e., value of distributed energy resources.”
This indicates that “procurement is directly tied to IDSR now,” Hanley said. “These programs were always a stepping stone toward a market anyway…to find out the most cost-effective ways to deploy the solutions where needed, use a complete portfolio of DR options, and then figure out new integrations that haven’t been seen before.”
While the DRPs provide the rules for how DERs are valued as grid assets, Florio’s proposal could set the rules for “how can you actually capture that value,” Ted Ko, policy director at behind-the-meter battery startup Stem, noted at a Thursday CPUC meeting. Utilities could say, “'I need capacity, I need ramping, I need voltage support,' and then let the portfolio of technologies fill that need for you.”
Of course, the locations of DERs will determine what they’re worth to the distribution grid. To help figure that out, Florio’s proposal will “also consider the issue of localized incentives, which was not anticipated when we established the rulemaking but arose in workshop discussions.”
In some ways, Florio’s new proposed decision pushes California further along a path that looks like New York state’s Reforming the Energy Vision proceeding, which is seeking to create open markets for DER owners and managers to trade these values with utilities. “It does look like they’re taking the next step toward REV that the DRPs didn’t do," Ko said.
That view was echoed by CPUC President Michael Picker, who said at Thursday’s meeting that he is seeking to “create a collaboration” with New York’s Public Service Commission, the utility regulator in charge of implementing REV, to help get a sense of “the combinations of technology and policy and pricing that can do this in an effective way.”
Balancing the utility-customer benefits
It’s important to note that California’s big investor-owned utilities didn’t seek all the changes that Florio’s proposal encompasses. Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric all asked the CPUC to limit the IDSR proceeding to improving integration of traditional demand-side programs, since other proceedings, notably DRPs, are “currently considering how best to incorporate distributed energy resources into system planning.”
That utility stance wasn’t necessarily evident during workshops on this proceeding, Wang said. In those sessions, “it was almost like everyone was back in grad school and we were all really excited about what California could do,” she said. “It was as if folks just took off their individual hats for their organizations, and just tried to figure out what the major problems were and how we could solve them if we didn’t have the weight of historical methods in the way.”
“Once everyone went back to their organizations, and stepped back behind their workstations, the comments pulled back a little bit -- especially the utility responses,” he said. Even so, based on what emerged from the process, “I think the proposed decision really took that spirit and moved forward with it.”
At the same time, “What this proceeding will do and what the Distribution Resource Plan proceeding will do -- there’s some lack of clarity there.”
Florio’s proposal stakes out a series of decisions to be made in Phase 1 of the new proceeding, including “the development of an end-to-end framework for integrating demand-side resources, including relevant valuation methodologies and sourcing mechanisms. The final step in Phase 1 will entail developing objectives for the adopted framework.”
The next phase “will consider how pilots may be launched to explore promising distributed energy resource sourcing mechanisms,” the document states. What’s still unclear, however, is what will happen in Phase 2 besides pilots, Wang said.
Specifically, there are some challenges ahead for any regulatory regime that moves distributed energy from relatively simple mass-market compensation schemes, like net metering, and toward more complex, grid integration-based business models, she said. From the point of view of DER providers, “We may be coming up with more value streams, but not any more certainty that they will all stack up to amount to payment amounts that will, in the aggregate, support the market.”
From the point of view of utilities and California grid operator CAISO, on the other hand, “Who takes the risk if these resources don’t show up? And can we frame it in a way that as long as the risks are calibrated properly, grid planners can say, 'OK, we can rely on that?'”
These are some thorny issues, and Florio’s proposal doesn't seek to directly resolve them. It does note, however, that current regulations “require that distribution system planning be informed by distributed energy resources, including choices made by customers. Here we acknowledge that the inverse is also true: customer choice should be informed by the impact of those choices on the electrical system.”
In other words, any future rules for a grand unifying theory of utility-DER partnership will have to keep both parties’ needs in mind. Get ready for a vigorous debate from utilities, third-party DER providers and other involved parties on how to make this vision a reality.