Back in 2014, the California Public Utilities Commission launched its Distribution Resources Plan proceeding — a sprawling effort to order the state’s three big investor-owned utilities to find out how distributed energy resources could fit into their multibillion-dollar annual grid investment needs, and provide those resources a path to be paid for that value.
It’s taken four years, but last month, California’s investor-owned utilities released a set of reports that represent the culmination of one facet of this effort — creating opportunities for distributed energy resources to serve as non-wires alternatives, or NWAs, in lieu of traditional grid investments, complete with plans to open bidding on a handful of projects by early next year.
These distribution deferral opportunity reports, or DDORs — a phrasing that highlights the fact that they’re solely dealing with NWAs for the distribution grid, not the transmission grid — have laid out a handful of projects that each utility thinks could be replaced by distributed energy resources.
Under CPUC’s schedule, by December, each utility is expected to issue an advice letter seeking permission to issue requests for offers for a handful of top-tier projects, and then to open up the process for submissions in early 2019.
These aren’t the first NWAs to be created in California, as we’ve noted in previous coverage. And they’ll be limited to only a handful of projects identified as optimal deferral candidates, out of lists of hundreds of potential grid projects needed over the next five years. The winnowing process reflects both the limits to what DERs can do to solve distribution grid problems, and limits to what utilities and regulators are currently prepared to do to integrate them as alternatives.
Still, they are the first step in an effort to change the NWA procurement process from its current project-by-project basis, to one that happens year after year, in a much more standardized way. “This is really the beginning of the payoff from the Distribution Resources Plan process,” said Sahm White, economics and policy analysis director for the Clean Coalition nonprofit group. “We’re actually seeing the work of the DRP to bring transparency into the grid planning process, to make sure we are seeing where the grid needs are, the nature of those needs, where they’re located, and creating opportunities of finding more cost-effective ways to meet those needs.”
These DDORs also provide an interesting contrast to the approach of New York, the other state that’s pushing for NWAs to be included in utility distribution planning in a big way as part of its Reforming the Energy Vision proceeding. “In New York, they said, 'Let’s get some pilots moving and we’ll get some information along the way,'” explained Daniel Munoz Alvarez, grid edge analyst for Wood Mackenzie Power & Renewables. That process has seen many more NWAs built, but has brought its share of problems over data sharing between utilities and DER providers, he noted.
"In California, the focus was on trying to require a lot of the information before they start to procure NWAs — the utility has to collect this information and has the burden of reporting, and then they'll build a market around that information,” Munoz-Alvarez said.
While that’s taken longer to develop, it may prove to be a more solid foundation for expanding NWAs in the future — depending on how the first round of bids called for in the newly released DDORs ends up going.
The top-line dollar and megawatt details: What’s public and what’s not
Of course, the casual reader of the DDORs filed last month by Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric might not get the impression that they’re sharing much data at all. That’s because the public versions of the DDORs have redacted much of the critical information about the individual projects they’ve put forward as NWA opportunities.
Clean Coalition's Sahm White, as a member of the Distribution Planning Advisory Group, the stakeholder advisory group working with the CPUC and investor-owned utilities on the process, has been able to review much the undisclosed data, and noted that it provides many of the critical technical and financial details for each project — at least for the relatively small number being put forward as opportunities for next year.
The public reports, while limited in the amount of data they share, do yield some valuable top-line figures, although much of it must be taken with a bit of explanation.
For example, all three utilities have identified about 20 projects that are candidates for DER deferral — a list winnowed down from a much larger number of grid investments from each utility’s Grid Needs Assessment plans — along with the dollar value of the traditional projects that won’t happen if they’re deferred. For PG&E, the total is $81.7 million and for SCE it’s $168.5 million, according to a Friday note from Ed Smeloff, director of grid integration for the solar advocacy group Vote Solar.
These figures are useful for DER providers, since any project they’re seeking to defer will obviously have to come in below the cost of the traditional project it’s meant to replace, White said. They also serve as a rough guide to valuing the “market,” so to speak, for DERs as distribution deferrals — although that’s complicated by the fact that DERs serving these needs could have multiple ways to earn money besides these utility contracts.
There’s another catch to this dollar figure. Each utility only plans to actually put out requests for offers (RFOs) on a handful of projects on these lists — four for PG&E and SCE, and one for SDG&E. PG&E and SDG&E haven’t listed dollar replacement values for these short-list, top-tier candidates, and while SCE has listed per-project costs, it hasn’t yet identified which of its 20 listed projects will be selected for its final tier. This all means “it is not possible to further break out the unit costs by the prioritized tiers from the unredacted versions of the submittals,” Vote Solar’s Smeloff wrote.
The detailed data available to Distribution Planning Advisory Group members includes more useful information, White noted, such as a unit cost guide that provides a much more accurate view of real-world costs, compared to the public report’s averages based on assumed equipment and labor costs. These are the kinds of extra details that will be critical for DER providers and developers responding to the RFOs that are set to emerge in December.
From hundreds of projects to a handful of RFOs: The DDOR screening process
Still, all of this talk about traditional project costs only sets a ceiling on the value of DERs to replace them. More complex calculations are required to find the most cost-effective options for different grid needs to be met by different combinations of DERs — and then, to pick only the most cost-effective and likely-to-succeed projects to go forward.
Vote Solar’s analysis laid out three key metrics used in SCE's prioritization process: cost-effectiveness, forecast certainty and market assessment. The first, cost-effectiveness, screens out projects that are cheaper to do the old-fashioned way, and prioritizes those for which traditional solutions are most expensive compared to the alternative. One simple example is the cost of upgrading a power line to increase its capacity, compared to contracting for DERs at the end of the line to meet that need, White said — the longer the line, the greater the cost, making DERs relatively more attractive.
Forecast certainty applies to the timing of the grid need. Each DDOR has already cut projects that need to be completed before 2021, given the uncertainty about finding enough DERs to fix a grid problem that could start causing reliability or safety issues as early as next year.
But it has also deprioritized projects that are further than five years out, since there’s less confidence in the reliability of the forecast, and prioritized areas with less volatility in load growth, to avoid a situation where changing conditions render the chosen DER solution ineffective.
Finally, the market assessment “looks at the hosting capacity of the impacted circuits and determines whether there is sufficient market potential for DERs that would defer the conventional project,” Vote Solar’s Smeloff wrote. This involves using the CPUC-mandated calculations known as an integrated capacity analysis to guide hosting limits, and a locational net benefits analysis to derive a value for services that DERs can provide — mostly from reducing load and adding generation during critical hours when the grid is facing capacity limits, but including the options of providing voltage support, reactive power, or “resiliency” and microgrid capabilities.
This year’s DDORs haven’t picked projects that are meant to satisfy all of these types of needs, Smeloff noted. Almost all of them are aimed at the relatively simple proposition of meeting capacity or reliability needs — adding generation to an area that would otherwise need to upgrade the grid to meet peak loads or reinforce itself against vulnerability to a failure somewhere else in the system.
This emphasis has allowed each utility to present each of its chosen projects in terms of megawatts of capacity and megawatt-hours of energy required. PG&E is seeking about 29.4 megawatts for its four Tier 1 projects, out of a total of about 112 megawatts for its 21 candidate projects. SCE hasn’t identified its Tier 1 projects yet, but its 20 candidate projects add up to 381.3 megawatts, including one 176.6-megawatt project that’s larger than the remaining 19 combined at 141.7 megawatts.
Finding the value of DERs: A work in progress
But the really important figures for would-be NWA developers are the value of the benefits those DERs can provide, White noted. In the DDORs, these come in the form of an “estimated [locational net benefits analysis] range” figure for each project — either less than $100, $100 to $500, or more than $500 — that represents a positive cost-benefit ratio of DERs instead of traditional upgrades, expressed in dollars per kilowatt-year.
This is a very site-specific calculation, White noted, which is why the DDOR list only includes ranges, not specific figures. But the Distribution Planning Advisory Group (DPAG) stakeholder group, which has access to the unredacted data, is working with more precise figures for individual projects, which will presumably become part of the RFOs to be proposed in December.
“It is really a case-by-case basis,” he said. “Each one has very specific needs and performance requirements. But they’re open to any DER technology that can do it — energy efficiency, demand response, energy storage, EVs, front of meter, behind the meter.”
Southern California Edison also had a handful of projects that included voltage support as a criteria, along with an explanation of how it calculated these needs in relation to each site’s capacity needs. But none of the utilities picked projects that required reactive power or resiliency as a need — a gap that could indicate missed opportunities, White said.
It’s to be expected that the utilities’ first foray into distribution-level NWAs might concentrate on more easily definable goals like capacity, while avoiding more technically challenging efforts like enlisting DERs for reactive power or microgrid services. But it also could be leaving some very valuable services on the table, as Vote Solar’s Smeloff noted.
For example, of SCE’s 557 identified grid investments, 342 were for capacitors to mitigate reactive power and voltage needs, he wrote. Smart solar or battery inverters can inject reactive power to achieve some of the same results as capacitors — a capability that California regulations anticipate making part of its distribution grid landscape. But “none of these projects were considered to be candidates for deferral through the use of smart inverters,” he wrote.
The Clean Coalition and other DPAG stakeholders are also asking the CPUC to give utilities more flexibility in how they procure DERs, White noted. Right now, the going model for how this happens is called the Integrated Distributed Energy Resources Competitive Solicitation Framework, and its implementation in practice is being tested in the Utility Regulatory Incentive Pilot projects each utility was ordered to undertake in late 2016, and which have begun rolling out this year.
This time lag between order and execution highlights some problems in the pilot projects’ execution, such as the time it takes to identify a project, and the time it takes to get CPUC approval to run an RFO, White said. “We’ve asked the commission to give utilities the ability to preapprove these projects and streamline the solicitation process.”
Speeding up this process could help DERs better fit into more rapid timelines for deploying as a grid alternative, he noted. But so could allowing DERs to tap demand response or load reduction in an area to deal with early capacity problems, while also lining up the actual on-site generating assets needed to solve the longer-range problems projected for that circuit — a concept that Clean Coalition has suggested to utilities as a way to include shorter-term grid needs on their list of potential deferral opportunities.
There's also the question of what’s in it for the DER providers. Given the limited public data, it’s hard to project whether DER providers active in California will see the DDORs as an economically attractive opportunity, compared to all the others in the state, whether it’s earning Self-Generation Incentive Program payments, being contracted to provide energy storage under the state’s AB 2514 mandate, providing capacity as part of Southern California Edison’s 2014 local resource procurement, or participating in state grid operator CAISO’s energy markets as a distributed energy resource provider, to name a few examples.
What’s not yet clear is how, or if, these DDOR projects will be able to serve in these additional revenue-generating opportunities, White said. Many of the capacity deferral projects identified in this first round are only asking for “a limited number of hours throughout the year,” he said. “For the rest of the time, that resources can be used for something else.” But this is a bit of a gray area at present, and “there are regulatory issues here, without question,” he said.
These and other issues will have time to be hashed out between now and the utilities’ December deadline for filing advice letters for their first RFOs. But they will also be refined as part of the annual process of which the new DDORs are just the inaugural edition, he added.“The whole point is to do a grid needs assessment every year, and identify distribution deferral opportunities every year,” one that improves as it brings in new data, such as the circuit-by-circuit data being delivered through ICA 2.0, and learns from its mistakes, he said.
