California’s landmark effort to value distributed energy resources by their location on the grid appears to be running into speed bumps.
If there’s one thing the parties in the state’s locational net benefit analysis (LNBA) working group can agree on, it’s that the valuation tool they have developed is “not yet ready” and “needs refinements.”
The phrases are from the working group’s final report to state regulators. The group was tasked with building a locational value tool to inform key proceedings in California’s effort to open its marketplace to distributed energy resources (DER).
“The tool should not be used as a sourcing mechanism or to determine payments to DERs for several reasons,” Dhaval Dagli, principal manager of regulatory affairs at Southern California Edison (SCE) told Utility Dive. One is that it includes avoided cost inputs that are a simplified representation of utilities’ cost-benefit analyses but “not an appropriate proxy to determine payments to DERs.”
Brad Heavner, policy director at California Solar Energy Industries Association (CalSEIA), was even more adamant that the working groups tool is not ready for prime time.
“We have the start of how to value distribution system expenditure deferrals,” he said. “But the bigger question, and the bigger value of DER is, what never gets built? If you model out the entire system right now, the answer is too complicated with too many places for errors.”
The report does not discourage Marc Monbouquette, senior regulatory analyst for the California Public Utilities Commission (CPUC).
“This start gives the commission plenty to work with because it shows what the tool can and cannot do and we know where it needs to go," he told Utility Dive.
“The longer-term goal is for an LNBA tool that can be used to more proactively identify locational value of DER without the input of new data,” he added. “The entire system would be mapped out and all its components and attributes would be available as the basis for a very granular value estimation.”
Now, stakeholders in the working group, including some who say the valuation goal cannot be achieved, await further commission guidance.
The LNBA backstory
California’s Assembly Bill 327 ordered its three dominant investor owned utilities (IOUs) — SCE, Pacific Gas and Electric (PG&E), and San Diego Gas and Electric (SDG&E) — to optimally locate distributed energy resources (DER) in their distribution systems.
An Assigned Commissioner’s Ruling from CPUC President Michael Picker set up an LNBA working group to develop a methodology for the three IOUs to use to value DER by location. That locational value, in turn, would be used to inform at least three other commission proceedings on DER integration at utilities.
Picker’s order also ordered the IOUs to apply the Locational Net Benefits Analysis (LNBA) methodology in “Demonstration B” projects required by the commission’s Distribution Resource Planning proceeding.
Demo B reports from the IOUs to the LNBA working group were filed at the end of 2016. Based on the cost-effectiveness Distributed Energy Resource Avoided Cost (DERAC) calculator approved by the CPUC, the reports included lessons learned and recommendations on the LNBA methodology.
Findings from those reports were incorporated into the working group’s efforts to complete a new LNBA methodology. Longer-term work will refine the methodology into a publicly available DER valuation tool with comprehensive location-specific system data.
The tool, Picker ordered, was to transform the system data into maps “consistent and readable to all California stakeholders across the utilities’ service territories.” It was also to serve as the basis for “further definition of grid service” from DER that would drive working group dialogue on other long-term methodology refinements.
Non-location-specific value components were defined by the CPUC staff as “system level conditions of the bulk electric system.” Location-specific values were defined as “local level conditions of the distribution system.”
Location-specific components added to DERAC for the tool are largely avoided costs provided by DER when they are deployed instead of traditional infrastructure infrastructure investments in transmission, substations and the like. They would avoid capital expenses for distribution voltage and power quality, distribution reliability and resiliency, transmission, flexible resource adequacy procurement, and renewables integration.
From the beginning, the IOUs were primarily focused on DER values for deferring transmission and distribution expenditures. That, President Picker wrote in his guidance, is likely not “sufficient to capture the value of the full range of potential benefits of DERs.”
According to the working group, its report recommendations are “to allow the Commission to a make an informed decision regarding next steps.” Those steps are expected to be a plan to further develop and implement a system-wide rollout of the LNBA tool.
But the working group noted that “the current LNBA methodology is not yet ready for a system-wide rollout.” It will work only “on a provisional basis” in CPUC-ordered pilots “for information purposes, and as a tool to support identification of project deferral.”
The tool “requires additional refinements” but the working group “has not yet reached consensus” on what they are. They may include replacing system values with local values, adding avoided transmission capital costs and distribution system benefits, improving the tool and map, adding more complex DER solutions, and better accounting for utility planning uncertainty.
Discussions on these and other topics have not been adequate to find consensus, the report adds. Additional discussion is needed to “determine whether the distribution deferral framework is the correct foundation for the broader issue of evaluating the overall locational benefits of DERs.”
Informing other proceedings
Working group discussions were based on the visionary More than Smart document that initiated the California DER proceedings. But commission guidance is now needed to prioritize next steps, though “some topics may require substantive analysis.”
Longer-term refinements of the tool and methodology are necessary, the CPUC’s Monbouquette said.
The “location-specific avoided cost values” developed in the LNBA proceeding will form the foundation for three other important DER proceedings, Monbouquette wrote in a key memo to the working group. Those include locating “high-value locations for DER deployment,” informing resource procurement decisions and developing “location-specific rates or tariffs for DER.”
The first initiative is the Integration of Distributed Energy Resources (IDER) proceeding (R.14-10-003). It requires the LNBA to complete the building of “a unified cost-effectiveness framework that can be used for technology-agnostic resource evaluation,” Monbouquette wrote.
The Distribution Resource Planning (DRP) proceeding (R.14-08-013), meanwhile, is tasked with moving the IOUs toward a fuller “integration of DERs into their distribution system planning, operations, and investment” through the use of LNBA and its companion integration capacity analysis (ICA) proceeding. The DRP awaits an LNBA-determined DER value for the design of programs, incentives, and tariffs, the memo reports.
Finally, the commission’s net energy metering (NEM) successor tariff decision (D.16-01-044) “clearly identifies LNBA-derived locational values as the basis of the next regime of NEM incentives,” Monbouquette wrote.
Additionally, he added, “future cycles of the Integrated Resource Planning (IRP) process post-2018 may utilize the locational values provided by the LNBA as an input to help estimate optimal levels of DERs.”
Despite all that awaits a location-specific DER value, however, “certain IOU parties believe that LNBA is a tool to provide indicative information to various stakeholders,” the working group reports. They argue it should not be used in DER sourcing or compensation decisions.
Uses for the LNBA tool today
At present, the primary information use for the LNBA tool allows DER developers to estimate the deferral value of a DER solution by inputting location-specific values to the system level values in the DERAC calculator, Monbouquette said.
What the tool does not yet do is “proactively identify those [DER] values across the entire distribution and transmission system,” Monbouquette said. “They have to be input.”
Color-coded maps provided by each IOU indicate an avoided cost range for DERs across their service areas. The IOUs keep the actual deferral values confidential, Monbouquette said. In their planning processes, they select deferral opportunities for a solicitation and publish them online.
“Developers can use the tool to get an idea of the estimated benefits for bidding,” he said. “The actual cost information is not published so that developers cannot game the solicitation with a bid just under the actual cost.”
The report’s conclusion that the LNBA tool is not ready for DER sourcing or compensation “is the main identified point of contention,” said the CPUC staffer. It is one shared by each of the three IOUs.
“The LNBA tool can help communicate potential optimal locations for DERs to interested parties and can also inform other DER regulatory processes that are underway,” said Mark Esguerra, integrated grid planning director at PG&E. “This includes sourcing mechanisms used to deploy DERs in those locations by helping the IOUs prioritize those locations for targeted DER sourcing.”
SCE sees the tool’s usefulness similarly, Dagli said. It is a “public-facing tool and heat map to help DER developers identify potential locations for DER deployment and to get an indicative idea of utility avoided costs,” he said. “It allows them to be better prepared to participate in utility solicitations for DER services.”
It also may “provide locational support to competitive procurement or future programs by identifying areas for increased focus,” he added. “SCE has successfully sourced many DERs in this manner.”
Not all DER will be procured competitively, Dagli acknowledged. SCE is “open” to location-specific tariffs and programs “tailored” by utilities “to drive desired growth.”
CalSEIA’s Heavner sees in the tool an opportunity for developers to “fish around” for locations ripe for deferral of distribution system expenditures. “It may not be worth the time, but you get an 8,760-hour profile and may be able to find areas where DER can reduce load enough to defer the building of new infrastructure.”
SDG&E sees “successful outcomes” but “room for improvements” in the tool. A more granular locational benefits analysis would “unlock new information that may help to better inform the energy planning process,” said Senior Communications Manager Amber Albrecht.
Vote Solar Grid Integration Program Director Jim Baak was even less enthusiastic. “The tool met the basic letter of the commission’s requirement, but a lot of the aspirations of many advocates and even some of the utilities were not met,” he said. “This is a to-do list.”
Shortcomings in the LNBA tool
But the tool misses the full range of DER value because of its lack of location-specific information, Baak said.
“Line losses in downtown San Francisco are much different than line losses in rural Modesto,” he said. “And operational efficiencies and improvements that reduce maintenance expenditures are not valued.”
SDG&E’s Albrecht took Baak’s critique further.
“This methodology is a framework that will need to be refined because there is no ‘one size fits all’ tool,” she said. It provides information not previously available but omits cost. Sourcing “should balance cost and benefits” and should “meet specific utility needs,” she argued.
PG&E’s Esguerra pointed specifically at the need to make “components in the tool, such as energy and generation capacity, more location specific.”
SCE’s Dagli expanded on this point. The tool should include location-specific transmission deferral benefits, ancillary services benefits, and a locational multiplier to the generation capacity benefit, he said.
He agreed with Albrecht’s argument that the tool should not be used for sourcing or payments because, he said, it does not consider costs for DER deployment, interconnection, and integration.
Also, Dagli added, the DERAC system-level avoided cost values are only narrowly applicable. “Rather than being based on a utility’s avoided costs, procurement should be based on an estimate of what it would take to get additional DERs deployed.”
And, he said, the distribution system “is very dynamic” while the tool is “tied to the utility’s annual planning process and, therefore, will not always reflect current system conditions."
The working group report makes the same argument.
“New projects may become necessary, adding to the value of DERs in that location,” it reads. But at the same time, “current projects may become unnecessary, reducing the value of DERs in that location.”
Energy Policy Analyst Eric Borden of ratepayer advocacy group The Utility Reform Network (TURN) emphasized this. Uncertainty “has not been reflected in the tool and needs to be accounted for so that we don’t create false economic signals and potentially wasteful subsidies,” he told Utility Dive.
Many deferral projects are funded in General Rate Cases (GRCs) that run every third year, Borden wrote recently. It is not unusual for them to be delayed or cancelled. In their recent GRCs, the majority of PG&E’s projects and 45% of SCE’s projects were deferred, he found.
“If DER’s are procured to ‘defer’ projects that were deferred anyway due to lack of expected load growth, they will not create any value,” Borden wrote.
Monboquette, Heavner, and Baak agreed this is a valid concern that should be addressed. Borden suggested DER procurement be limited to where load growth is not driven by only one customer, where less than expected load growth would still result in overloading and the need for upgrading, and where the utility need is more near-term.
Monbouquette essentially agreed.
“We should focus in the near term on more certain needs and, as we gain experience in how to identify deferral opportunities, go deeper and find more granular value to capture,” he said.
Can the LNBA tool work?
Monbouquette says he read the line in the working group’s report about not using the tool for DER sourcing and compensation as referring to “this version of the tool,” and not necessarily an indictment of the entire process.
“My memo clearly states how the commission wants the tool to evolve and what it is to be used for.”
The memo also indicates the tool’s location-specific DER values are to be used to structure California’s NEM successor tariff, he added.
The utilities, however, do not agree.
The LNBA tool might contribute to future distributed generation values, said SDG&E’s Albrect, but “the intent of the tool is not to develop a methodology to set values for private solar.”
PG&E supports changes to NEM, Esguerra said, but doubts “a highly dynamic and location-granular analysis like LNBA would work for purposes of directly setting compensation values.”
SCE’s Dagli said the tool “can indirectly help.” Understanding the value of optimally located distributed generation, along with input on integration costs and customer economics, “could lead to the determination of an appropriate export compensation incentive,” he said. Administrative complexities could, however, make such an approach unworkable.
Monbouquette acknowledged that the current version of the tool cannot do what the commission expects it to eventually do. But, he added, the CPUC’s DER Action Plan goals are for 2018 through 2020.
“It is a good place to start,” he said. The longer-term use cases that will be taken up by the working group this spring will require resolving “a huge data problem.”
The IOUs argue DER “have no inherent avoided cost value except to meet grid needs identified in the distribution planning process,” he said. “But we know the proliferation of DER, especially rooftop solar, has led to significant avoided investments and ratepayer savings.”
The LNBA working group will have to balance those two arguments so that the tool can eventually be “proactively used in planning,” Monbouquette said. First, however, the working group must find greater agreement on the tool's design and content.
Vote Solar’s Baak is less patient. “The next step is long term refinements — but how do you define long term? Some utilities may define it as five years but we would define it as, ‘let’s get it done.’”
Unlike New York, California is “inching along,” he said. The IOUs are looking only at distribution investment deferrals for DER because of regulatory framework disincentives that reduce the earnings that deliver shareholder value for other DER investments.
New York’s DER markets are behind California, Baak acknowledged. And the New York utilities don’t have the metering data, the monitoring and software, or the vast power flow analysis that has been done in California.
But the New York Reforming the Energy Vision process has envisioned a new regulatory framework. “It allows utilities to create value for shareholders and allows private sector DER providers to offer services into a distribution market.”
In contrast, California IOUs and regulators support a vision based on what will emerge from demonstration and pilot projects.
PG&E’s Esguerra said the CPUC focus is correct, and should remain on pilot projects in which DER can be “tested and vetted.” The insights that emerge will give regulators and utilities “a better sense for the sourcing and compensation mechanisms that will ensure cost-effective deployment,” he said.
The utilities, Baak said, “are in a tough place” because the current regulatory framework requires them to implement commission and state mandates and create shareholder value at the same time. “Instead of policies and regulations that require them to do something, they need incentives to do it and to go beyond it.”
CalSEIA’s Heavner questions the gradual approach of the IOUs and the commission. “How much do you need to prove, up and down, forward and backwards, that something will work?”
He understands the gradual approach and the need for caution to protect reliability. “But there needs to be a middle ground so that years aren’t lost doing pilots,” he said. “Ultimately, regulators need to trust the marketplace. Yes, markets are out of their control. But markets also work better. Regulators should understand that competition and innovation are good things.”
What is needed are tariffs set by marginal costs, Heavner said. “What is 1 kWh of reduced demand worth, in terms of less transmission, smaller substation transformers, and less bulk-power purchases? That’s the value of DER.”
The working group needs to continue its effort to identify locational values because the LNBA tool will support utility procurement but that can’t be the entire market, he said. “You need a tariff and the tariff of the future should fundamentally be based on marginal cost analysis, with locational variables added.”
Monbouquette sees the tools and processes being developed in the DRP ultimately aligning utility incentives and policy goals. But it will not be easily or soon achieved. "The utility business model question has explicitly been kept out of the DRP guidance documents so far," he said.
“California’s walk-jog-run approach avoids high-level long-term conceptual goals," Monbouquette added. "It favors a steady approach to learn how to implement and evolve distribution planning and operations around the new technologies before it makes decisions about the final concepts and incentives.”
