by Jeff St. John
August 27, 2019

California is seeing very slow progress from utilities seeking to integrate distributed energy resources like solar and storage as non-wires alternatives for bits and pieces of their multibillion-dollar annual distribution grid investments. In fact, from the casual observer’s perspective, they might not appear to be moving at all.

Earlier this month, Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric submitted their second-annual Grid Needs Assessments and Distribution Deferral Opportunity Reports (DDORs). In simple terms, the Grid Needs Assessments lay out every single distribution grid need facing each utility in the coming year. The DDORs, meanwhile, break out the fraction of those projects that could be replaced by distributed energy resources serving as non-wires alternatives, then pick a further subset to open to third-party requests for proposals. 

According to the DDORs filed with the California Public Utilities Commission, PG&E has identified three “Tier 1” projects, adding up to 18.5 megawatts, that it’s targeting for competitive solicitations. SCE has identified 15 “candidate deferral” projects, of an unspecified capacity total, while SDG&E stated that it has found “no potential candidate projects for deferral by cost-effective” distributed energy resources.  

Coming up short

This month’s filings set the stage for PG&E and SCE to launch requests for offers later this year, opening up a small set of projects that could be deferred through a combination of energy, capacity and reliability that can be provided by the right mix of DERs. As with the utility-scale procurements happening in the state, it’s likely that bids will consist of a combination of solar PV and energy storage, although energy efficiency, demand response and controllable EV charging are other possible options. 

But getting from these short lists of non-wires alternative (NWA) candidates to third-party contracts to deploy DERs to meet them will remain a challenge, if last year’s process serves as a guide. That’s because last year’s inaugural DDORs also yielded a short list of projects that PG&E and SCE put to bid in early 2019 — and so far, that process hasn’t yielded a single contract.  

To be more precise, SCE’s March solicitation ended up seeking DERs for two planned distribution upgrades, at its Mira Loma and Sun City substations. But in a July advice letter to regulators, the utility reported that none of the DER provider offers could pass the projects’ multifaceted screening tests. 

The reasons were fairly straightforward. For the Mira Loma project, which required a solution that could deliver increased amounts of energy for up to 17 hours per day, SCE found that none of the DER offers could solve the need. In fact, all of the DER submissions added together weren’t enough, it reported. 

Meanwhile, DER offers for the Sun City project, while technically capable of meeting the substation’s needs, “compared very unfavorably against the traditional distribution upgrades for the Sun City Project and significantly exceeded the cost-effectiveness cap,” SCE wrote. 

SCE’s decision not to pursue any DERs has left the state without any distribution deferral projects on the books. SDG&E declined to pursue any bids this year and last year. And while PG&E hasn’t officially filed an advice letter to report the results of its February request for offers for three deferral opportunities with a minimum 10.6 megawatts of capacity, it’s unlikely the bankrupt utility will be aggressively pursuing DER opportunities amid its other challenges. 

A hard road for distribution-level NWAs 

These are certainly disappointing results for backers of the idea of integrating DERs into California’s distribution grid planning, particularly given how long it’s taken to get to this point.

At the same time, the results aren’t out of line for NWA efforts in other parts of the country. New York, the other state that’s pushing in a big way for NWAs at the distribution grid level, has seen limited success beyond its showcase Brooklyn-Queens Demand Management project. And Hawaiian utility regulators are struggling with Hawaiian Electric over its approach to DERs as grid replacements as part of that state’s Integrated Grid Planning effort. 

There are reasons for the slow pace of these efforts, as we’ve noted in previous coverage of NWAs. One is the complexity of trying to match wires, poles and transformer upgrades to the mix of capabilities and reliability that DERs could provide. Another is the problem of asking utilities to defer a capital investment, with its commensurate guaranteed rate of return, in exchange for an arrangement with third parties that doesn’t offer a clear path toward making up that lost revenue. 

Shinjini Menon, SCE’s regulatory affairs director, pointed to several key factors in the utility’s decision not to pick any DERs from its first request for offers.

First is “the dynamic nature of planning,” which allows SCE to mix, match and switch out different distribution grid solutions for its near-term needs, she said. This process doesn’t lend itself well to being fitted with an RFP-type process, which requires that projects be defined and “locked in” early on, and can take months to years to complete. 

The second problem was “the location of DERs themselves” in relation to the circuit needs, she said. Simply put, DER providers have only so many customers per affected circuit to tap with their various offerings, leaving them with few options if there aren’t enough of them to meet the grid's need. 

Finally, Menon highlighted the ongoing utility concern with relying on DER technologies to provide the same reliability as grid investments. “There is a particular need for the right thing at the right place at the right time,” she said. “But it’s not just how well DERs can be deployed in the area we need — it’s also how effectively they can be dispatched.”

On this front, California’s utilities, regulators and DER providers are still in the early stages, as we’ve noted in our ongoing coverage of grid-DER integration pilots in the state.  

All in all, SCE’s experience with the DDOR process “has not been as successful as we had hoped it would be,” Menon said in an interview.

“At the same time, we feel that this has been a great learning opportunity to learn more about what might work and what won’t. And at the end of the day, we do believe that DERs have and will continue to have a pretty strong role in how we manage our grid.”

California's broader context for DERs

In fact, SCE has several projects that are actively integrating DERs into grid operations in a way that meets the technical definition of an NWA, even if they aren’t linked to the DDOR process, Menon noted.

One such example is its Preferred Resources Pilot, which is contracting for more than 125 megawatts of DERs to help meet the needs of an Orange County grid infrastructure affected by the loss of the San Onofre nuclear power plant in 2013 and the scheduled closure of coastal natural-gas-fired power plants in the coming years. 

SCE is also the only California utility to successfully deliver on an NWA pilot project launched in 2016 under the CPUC’s Integration of Distributed Energy Resources proceeding. In October, SCE awarded esVolta contracts for 38.5 megawatt-hours of batteries to defer distribution upgrades in Palm Springs and Thousand Oaks.

California’s other two utilities didn’t complete their Integration of Distributed Energy Resources pilots, SDG&E because it reported that it received no compliant proposals, and PG&E because its target substation in Santa Rosa was damaged in the 2017 Tubbs Fire. 

Ed Smeloff, director of grid integration at Vote Solar, highlighted SCE’s project with esVolta as a success story to set against the lack of progress on the DDOR front. “My overall view is that this has been a very slow, plodding process that hasn’t delivered what people initially expected,” he said. 

Smeloff agreed that there are “real disincentives for utilities to do non-wires alternatives since they don’t earn any equity,” which could lead to foot-dragging on the utility's part. At the same time, “part of this is still a very new process, and I think there is value in the transparency being created here.” 

In May, for example, the CPUC issued an order requiring utilities to include more detailed data on the projects identified in their Grid Needs Assessments and DDORs, including cumulative demand and customer composition per project, as well as how much solar PV and energy storage the customers have installed.  

Next month, the CPUC will be holding meetings of the Distribution Planning and Advisory Group, which will offer stakeholders the chance to look into whether utilities could include more “Tier 2" projects on their shortlist of DER candidates, he said.  

But there’s also the possibility that the NWA opportunities that California’s utilities happen to have from year to year just don’t match the economic imperatives of DER developers in the state.

“DER developers are struggling to come up with solutions to very specific needs, and when they do find a feasible portfolio of NWA solutions, it’s too expensive,” said Daniel Munoz-Alvarez, grid edge analyst for Wood Mackenzie Power & Renewables. 

The question of RFPs vs. tariffs 

Many argue that the RFP process, with its tight timelines, specificity and lack of alignment with DER providers’ economic incentives, might not be the best way to merge grid/DER values. Earlier this year, as part of its Integration of Distributed Energy Resources proceeding, the CPUC opened up requests for proposals for DER tariffs — rates that encourage and reward DERs that can provide a certain mix of energy, capacity and reliability service — as an alternative to RFPs. 

The ideas emerging from that process range from utility proposals for limited, project-targeted tariffs, to a plan backed by industry groups Vote Solar and the Solar Energy Industries Association to offer payments and incentives to DERs being deployed in broad swaths of PG&E territory with the highest marginal distribution grid costs. 

When it comes to solving binary distribution grid constraints or reliability threats, “you still need a final amount of capacity at the end of the project,” Vote Solar's Smeloff said. "You don’t know if you’re going to get that by knocking on doors and signing up customers.”

This fundamental uncertainty about the cause-and-effect of tariffs on real-world DER deployments remains the primary problem with relying on them, rather than tightly defined and bound contracts, to solve the NWA conundrum. 

Even so, utilities as well as DER providers are interested in exploring tariffs as a solution. “If we could figure out a way to create targeted incentives that could give a nudge to customers or assist aggregators in deploying DERs to a certain location…we’re very interested in exploring those kinds of opportunities,” SCE’s Menon said.