Over the past few years, we’ve been tracking the slow progress of California’s Distribution Investment Deferral Framework, or DIDF. That’s the program that orders the state’s three big investor-owned utilities to look over their multibillion-dollar annual budgets for reinforcing their distribution grids with new wires, poles and transformers, and find a handful of projects that could be solved instead with distributed energy resources (DERs).
In other words, the DDIF is California’s version of a non-wires alternative (NWA) program for the distribution grid. But much like similar efforts underway in other states, it hasn’t yielded much in the way of real-world projects so far. In fact, only Southern California Edison has successfully delivered a NWA as part of the underlying regulatory proceeding that created the DIDF, and none of the state’s utilities has yet awarded a contract through the DIDF process.
That could change in the coming months. Late last year, both SCE and Pacific Gas & Electric put out for competitive bidding a combined 10 projects that could be deferred with DERs. Results of those bids could come as early as next month, Ed Smeloff, director of grid integration at Vote Solar, said in an interview this week.
In the meantime, the California Public Utilities Commission is looking for ways to improve the DIDF process, and it’s asking utilities, distributed energy industry groups, and environmental and consumer advocates for ideas.
Not surprisingly, stakeholders have responded with a broad range of complaints and suggestions. Many of them cover the same longstanding conflicts between utilities and DER advocates over how the program should work, with utilities generally seeking to limit the types of projects that should be considered for NWAs, and DER advocates calling for policies that open up more potential projects to review and bidding.
At the same time, the wildfires caused by Pacific Gas & Electric that drove it into bankruptcy have refocused the conversation around providing energy resilience to its most vulnerable populations. DER advocates are calling for the DIDF process to help solve this pressing problem.
The utility point of view
There are reasons for the utilities to balk at changes. San Diego Gas & Electric, which has put no projects out to bid through the DIDF process, argued in its filing that the program’s success “should not be measured by the number of DER contracts that emerge from the annual DIDF cycle but rather in the results delivered to ratepayers.” In other words, if DERs can’t replace grid investments in a cost-effective way, choosing the traditional upgrade is the right choice, it argues.
It’s also important to remember that utilities have no clear incentive to replace traditional projects with NWAs. Traditional “wires” investments are designed to maximize system reliability and come in the form of capital investments that bear guaranteed rates of return. NWAs, by contrast, ask utilities to rely on third-party DER providers or aggregators to deliver the same level of reliability, and they offer no clear path to recovering the costs involved, even if they’re lower than a traditional upgrade.
Southern California Edison warned in its filing against making any “significant changes" to the DIDF. In SCE’s view, big changes would only slow down the process, stealing time and resources better spent on more pressing DER-integration challenges. Those include speeding interconnection process to support faster deployment of DERs and ensuring they can be called on to meet grid needs in real time.
SCE’s filing points out just how challenging interconnection can be for bringing NWAs online. A major DER project, such as the large-scale battery systems deployed in California for distribution grid support, can take from one and a half years to up to five years to complete, it states in the filing. These types of delays are a key reason why SCE and other utilities have argued for only considering DERs for projects that are at least three years out and thus have a chance of being completed by the time they’re needed.
Even when they are deployed, SCE noted, actively controlling third-party DERs for grid needs is a significant challenge. Current operational rules require utilities to devise a day-ahead schedule to DER operators before they commit to providing services to state grid operator CAISO, which “severely limits the ability for DERs to be used to meet real-time needs.” At the same time, utilities still need to make “significant advances” in their short-term forecasting and ability to communicate with DERs, SCE said.
The CPUC is working on these interconnection and communications issues in other proceedings, and SCE suggested that it focus its efforts there instead of the DIDF. SDG&E went further, arguing that the rest of the policy issues being discussed as part of the DIDF process be transferred to these other proceedings, essentially freezing the program as it now exists.
Distributed energy advocates’ point of view
DER supporters, unsurprisingly, have a different view of the problems at hand.
In a joint filing, Vote Solar and the Solar Energy Industries Association argued that California must stay on the “cutting edge” of using its distribution resources plan proceeding, the genesis of the DIDF process, and laid out a number of ways the program could change to accomplish that.
First of all, DER providers are eager to open the utilities’ project identification and screening processes, to better match what DERs can provide to what utilities need, Vote Solar’s Smeloff said. “One of the big issues is expanding the window of opportunity” in the timing screens used by utilities. While utilities say they can’t rely on DERs to solve problems that need to be solved in less than three years' time, “we think there are near-term opportunities that are being overlooked.”
One way to open more near-term opportunities could be looking beyond the project-by-project request for offers and bidding process now in place, he said. In its DIDF filing, the California Energy Storage Association (CESA) suggests an alternative method — turning to tariffs that pay customers for the energy, capacity or other grid services that DERs can provide as a solution.
CESA asks the CPUC to include in its 2020 DIDF process one of the many tariff pilot project proposals provided by industry groups and utilities last year. While each differs in terms of technical details, they’re all meant as a method of “incrementally procuring resources over time, thus reducing the lead time required to address certain, though possibly not all, distribution needs," according to the organization's filing.
The key idea, Smeloff said, is to capture the value of “incrementality.” Tariffs don’t work in the same way as a utility's request for offers, which specifies just what distribution needs it’s targeting and what technical solutions are required. But they could tap enough battery-backed solar potential to reduce the peak loads that the utility expects to have to manage in a few years, for example, and thus lower the costs of whatever grid upgrades might be under consideration.
The challenge for utilities is that it would further complicate their distribution grid planning processes, asking them to actively choose to forgo capital investments in favor of relying on customer-owned DERs to meet their critical reliability needs. “That’s been a big fight with utilities,” Smeloff said. “There’s no clear way to provide that value for incrementality."
A new focus on grid resiliency
The second big change DER advocates are calling for is a clear role for DERs to play in providing grid resiliency — specifically, resiliency against wildfires and fire-prevention power outages. “California needs to continue to be on the cutting edge of promoting [the distribution resources plans] together with local land use and transportation planning to build community resiliency,” Vote Solar and SEIA wrote.
There’s an important difference between this concept of community resiliency and the traditional utility concept of reliability, Smeloff noted. The term "reliability" is the standard way to express a need for what may be the simplest use of DERs — to provide generation or load reduction at the proper place and time in order to reduce load on specific parts of the distribution network that would otherwise have to be upgraded.
That’s “distribution deferral” at its most simple, and it’s the key function of almost all of the big NWA projects in the country, including New York utility Con Edison’s Brooklyn Queens Demand Management project.
Resiliency, on the other hand, is “the ability to respond to and recover from low-frequency, high-consequence, ‘dark sky’ events that may last longer in time and affect a larger area,” Vote Solar and SEIA state in a filing.
This can include all manner of utility investments into grid sectionalization, outage restoration and even the weather-forecasting capabilities that SDG&E has developed to manage its fire-prevention power outage program. But it can also include onsite backup power generators, solar-plus-storage systems or microgrids that combine resources to power critical facilities or entire communities during long outages.
Resiliency is one of the four key categories defined in the DIDF framework, but so far, no utilities have identified resiliency projects in their annual Grid Needs Assessments or Distribution Deferral Opportunity Reports, Smeloff said.
A broad group of stakeholders, ranging from solar advocates to PG&E, has suggested that the CPUC order utilities to separate resiliency from reliability for analysis in 2020, to aid in identifying projects linked to wildfire and power outage relief.
Vote Solar and SEIA also suggested that the CPUC order utilities to identify a "resiliency value" that accounts for load loss and other community costs that result from lengthy power interruptions. That would go beyond the traditional utility approach of measuring the cost of outages in minutes or hours of unserved load, he said.
Right now, however, most of the state’s work on wildfire and blackout resiliency is going on in the CPUC’s newly launched microgrid proceeding, Smeloff said. That proceeding is mandated by a 2018 state law that calls for the CPUC to develop guidelines for commercializing microgrids by the end of this year.
The CPUC has identified Track One of this proceeding as the venue to create and approve programs meant to help the state in the upcoming 2020 fire season, including PG&E’s proposal to build up to 20 substation-based microgrids to keep communities powered during fire-prevention outages.
In the view of groups including Vote Solar, it’s not clear why utilities shouldn’t open up the DIDF process to soliciting DERs for solutions to the same problems being addressed in the microgrid proceeding. As Smeloff pointed out, PG&E’s Grid Needs Assessment from early 2019 didn’t include the 20 microgrids it declared it would be soliciting in November.
It’s also unlikely that the utility’s plan to rely on fossil-fueled generators for the microgrids would pass muster as part of a distribution investment plan, he added.