The SoCal Edison rate case: A canary in the coal mine for DER policy debates
SCE wants $2.1B to upgrade its grid for distributed resources — a request that's raised ire from consumer advocates and DER providers alike
The $2.1 billion spend that Southern California Edison (SCE) wants regulators to approve for readying its system for distributed resources has raised a lot of stakeholder questions.
Some of the questioning is standard rate case skepticism about whether the $14.7 billion revenue request will serve customers or shareholders. But there are also new concerns related to the utility’s plan to spend $2.1 billion on grid modernization (docket A.16-09-001).
In particular, the distributed energy industry is concerned SCE is not taking advantage of all DERs have to offer by not valuing them properly in its planning. Consumer advocates, meanwhile, dismiss both sets of arguments as attempting to “gold plate the grid.”
“Our goal is a cleaner grid with much more distributed generation,” Shinjini Menon, SCE general rate case director, told Utility Dive. “We expect a rate case to be thoroughly reviewed but many of these programs and projects are what we have undertaken in the past.”
DER advocates want the utility spending in the 2018-2020 general rate case (GRC) to “optimize the value” of distributed resources before imposing costs on consumers for grid upgrades, according to a recent blog post from leaders of the Solar Energy Industries Association, a trade group, and advocacy group Vote Solar.
“We are asking whether these grid modernization upgrades for things like communications and automation can be done by third-party providers,” said Ed Smeloff, managing director of the regulatory team at Vote Solar and co-author of the blog post.
“Should the utility be making infrastructure investments or issuing solicitations for services from DER providers?” he said. “And is part of the utility’s calculation the return it will earn by making the investment, even though it might get better value from a third-party provider?”
Attorney Marcel Hawiger, of ratepayer advocacy group The Utility Reform Network (TURN), told Utility Dive neither the arguments of the DER advocates nor the utility are “justified by facts.”
Some DER advocates “allege that distributed resources provide benefits that will dramatically reduce utility capital investments in the distribution system,” Hawiger said, while according to SCE, “distributed resources, and especially distributed solar, impose huge cost burdens on the system.”
In upcoming rate case hearings, TURN’s objective will be to show that the utility is seeking to gold-plate its system by using the DER that it plans to build as an excuse for the modernization expenditures. But while that critique focuses on the utility side, he also said TURN has not “seen evidence DER from third parties will significantly reduce the need for utility capital expenditures.”
California is at the leading edge of the DER transformation, with more customer-sited resources than any other state. That could mean the issues raised in the SCE proposal could soon spread to other jurisdictions as DER adoption increases, making the GRC a kind of canary in the coal mine for DER policy debates.
To get a better sense of what’s at stake, Utility Dive posed four stakeholder questions raised in Vote Solar blog post to SCE’s Menon, Vote Solar’s Smeloff, and TURN’s Hawiger. Their answers show that regulators have their work cut out for them in evaluating the GRC in hearings this summer.
But, first, an overview of the SCE proposals.
What SCE wants and why
If the California Public Utilities Commission (CPUC) authorizes the required revenue, SCE’s modernized grid will be prepared for the addition of 1.5 million DER by 2025, according to “The Emerging Clean Energy Economy,” the utility’s recent white paper.
The modernized grid will then allow the utility to be its territory’s Distribution System Operator (DSO), the white paper reports.
As DSO, it will deliver new technologies coming from private sector DER providers in support of California’s ambitious climate goals, according to SCE’s GRC filing.
The filing asks the CPUC to authorize $14.6 billion in 2016 through 2020 revenues, including the $2.1 billion grid modernization capital expenditure. That will require average rate increases to SCE residential customers of 2.7% in 2018, 4.2% in 2019, and 5.2% in 2020.
SCE’s dual goals are system maintenance and preparation “for the new reality of DER,” Menon stressed in an interview when the GRC was filed.
Even without the DER factor, the utility would still require funding to maintain and upgrade aging infrastructure built as long ago as the 1950s, Menon said. But the spending will also allow SCE to handle the forecasted DER penetration without compromising safety and reliability.
The $2.1 billion grid modernization would build in four new capabilities, Menon said. They are structural upgrading, automation for real-time monitoring and control, new telecommunications capabilities with fiber-optic cable and wi-fi, and new software for system management.
The new grid would also enhance reliability by addressing technology obsolescence, such as the inadequate 4 kilovolt (kV) circuits that make up 22% of SCE’s 4,600-circuit distribution system, the filing reports.
Most substations on today’s system can only channel one-way power flow from the utility to the customers. But the CPUC’s landmark Distribution Resource Planning (DRP) order requires the state’s investor-owned utilities “to modernize the distribution system to accommodate two-way flows of power,” the GRC reports.
“The grid was built for central generation with a specific design and it was built to respond to a late afternoon load peak,” Menon said. “Now, in addition to centralized generation, generation can come from anywhere along a circuit and has an earlier, midday peak.”
To accommodate the two-way flows and keep the system reliable for non-DER-owning customers, it must be modernized, she added.
Finally, the utility wants to add technology platforms for distribution system forecasting, planning, and management, Menon said. These capabilities will ready the system to integrate DER where customer demand is high and where DER can provide grid services that could avoid or defer bigger capital expenditures.
Question 1: Does the spending benefit ratepayers?
The first question raised by the Vote Solar-SEIA blogpost is being asked in regulatory reform efforts across the country. It is about the utility business model.
“We want to avoid using pejorative terminology like gold-plating,” Smeloff said. “But what if there was a performance-based incentive or another way for the utility to earn its return?”
New York is working on Earnings Adjustment Mechanisms (EAMs) aimed at protecting the utility shareholders’ interests.
“If SCE was indifferent to whether it or a third-party provider made the investment, would the capital expenditure still be necessary to maintain quality of service?” Smeloff asked.
These questions are intended to benefit ratepayers by minimizing overall costs while protecting system reliability, he added. “Services traditionally provided through utility expenditures may be a better deal for ratepayers if they are obtained from DER providers.”
Ratepayer benefit “is the main issue TURN will litigate,” Hawiger said. Though it is still early in the watchdog’s study of the SCE filing, “we will for sure recommend cutting or reducing some of the proposed programs and projects.”
Cost-benefit analysis will not be adequate to evaluate all the proposed spending, he said. “Some benefits, like those from expenditures to improve reliability, can be quantified. Others, like spending to improve safety by replacing aging infrastructure, are harder to quantify.”
SCE’s Menon said stakeholders should be able to answer the four questions with what the utility has shared in work papers, testimony, and answers to data requests. “It is essentially public information,” she said.
“We are proposing grid modernization work so that, as more DERs are added, reliability is not degraded,” she said.
The proposed expenditures for distribution automation will produce one of the most quantifiable benefits, she said. State-of-the-art distribution automation, telecommunications, fiber-optics and wireless networks, and software will give SCE system operators the ability to see, analyze, and act on threats to reliability and quickly maintain or restore the system.
“Our average outage duration is now approximately 98 minutes,” Menon said. “That puts us in the low-to-mid third quartile of utilities nationally. With upgrades to approximately 600 of our poorest performing circuits and another 200 circuits where we expect high DER penetration, we forecast our average outage duration will go down to approximately 77 minutes.”
Other benefits cannot be as well quantified, she acknowledged. The first is “a significantly higher level of cybersecurity which, given the times we live in, is a big driver for spending.”
The other is the higher level of performance that will come from upgrading the 4 kV circuits to create a more standardized 12 kV and 16 KV system. There are many reliability and voltage issues presented by the lower voltage circuits, she said. But a more serious threat may be in the inability to maintain them at all. “We are now finding replacement parts are no longer available.”
The GRC calls for an acceleration of the utility’s program to upgrade the 4 kV circuits, Menon said. “We would have done part of this regardless of grid modernization and a part is driven by the expected increase in DER penetration.”
Question 2: Can these investments be deferred or eliminated by DER?
Vote Solar wants to understand, through its study of SCE’s system, whether the utility is appropriately accounting for the values provided by existing DER, Smeloff said. It also wants to understand if SCE “is making the right assumptions about the DER market opportunities across the whole suite of technologies.”
TURN’s Hawiger said relatively little of the spend proposed in the GRC is for “distribution capacity projects designed to address local load growth.” But it is not clear whether such infrastructure investments “could cost-effectively be offset by DERs,” he said. “There is not yet an adopted process to evaluate whether rooftop solar, battery energy storage, or other DER will reliably offset such peaks.”
TURN estimates no more than about $600 million in infrastructure spending can be deferred or eliminated by DER.
“DER does the deferral only if it is in exactly the right place,” Hawiger said. Because the utility knows exactly where the deferral is needed, SCE’s pilot for California’s Integrated Distributed Energy Resources (IDER) proceeding will reveal “how effectively a package of DER located by the utility to address its need can reliably defer investment and how much capital expenditure it can defer.”
Results from the IDER pilot will not, however, be available to inform this GRC, Hawiger said. “The issue in this rate case is whether SCE should value solar’s ability to reduce peak demand.”
TURN questions the methodology used by SCE to evaluate solar value, he added. It will nevertheless likely recommend significant cuts in spending to integrate distributed solar and other DER because “the alleged ‘problems’ can be addressed much more simply and for less money.”
SCE absolutely believes smart deployment of DER can defer capital expenditures, Menon said. This rate case only has “about $40 million in deferrals that are load growth related,” she said. Infrastructure builds have lead times of two years to three years so 2017 and 2018 projects are too far along to be deferred. The utility is now looking at projects “a little further out.”
DER used for deferring traditional investment must meet the utility’s reliability conditions, Menon said. “We need to make sure the project will be available when we need it because, at the end of the day, we are responsible to make sure our customers have power.”
The utility expects to propose more deferral projects in future rates cases but that “depends on what happens in this rate case in two ways,” Menon said. “If we slow the pace of grid modernization, we will not have the distributed resources to support future deferrals. And if we delay pilot projects, we will slow the learning about what is needed to accelerate the use of deferrals.”
Question 3: Is this spending due to normal utility operations or DER?
Vote Solar raised this question because it is concerned SCE may apply a cost-causation principle in its rate design “and try to collect its costs from customers as the cause,” Smeloff said. That could result in a fixed charge specific to DER owners.
DER advocates want to demonstrate the investments are due the utility’s need to modernize its system and are not be necessary to accommodate current DER levels, he added.
They are asking specific questions about the field area network, the wide area network, types of new switching equipment, and how the utility operates its system, Smeloff said. “We are trying to understand details about the GRC in order to demonstrate the upgrades it is planning are “part of normal maintenance and repair and upgrades and should be applied broadly to all customers.”
Vote Solar also wants to know how SCE prioritized its circuit upgrades, Smeloff said. “They want to put up this new equipment on 126 circuits. Are those really the circuits that need to be done by 2020? Is that the right schedule?”
TURN’s Hawiger cited passages in the SCE filings that identify “masked load” as the source of its need for investment in modernization. The utility’s system operators manage reliability issues by shifting load between circuits, but the lack of load visibility caused by DER output limits operational flexibility.
“Much of our work is studying how serious a concern masked load is.”
As DER penetration grows, “power is beginning to flow in both directions along distribution circuits and load is increasingly masked by DERs,” the Volume 10 of the GRC filing reports. Operators’ ability “to observe masked load and reverse power flows granularly on circuit subsections and quickly respond to system issues will be critical.”
But the few actual masked load problems to date were caused not by DER but by utility-scale solar connected to the distribution system, Hawiger said.
“Those discrete local problems should be addressed by SCE and the renewable project developer through appropriate local upgrades and communications,” he said, “not by having utility ratepayers subsidize billions to gold-plate the entire distribution system.”
Menon acknowledged the GRC investments are in fact part of the utility’s normal maintenance and capital replacement planning and not because of deployed DER.
“There are portions of our grid modernization forecast which are specific to DER integration but the vast majority of it is really trying to improve our safety and reliability,” she said. “Even if a single DER does not come online, we would have to improve the way we automate the grid, the way we get information back, and the way we process that information.”
Question 4: Is DER spending needed now and properly targeted?
Vote Solar agrees grid modernization would allow SCE to do more things to accommodate DER, Smeloff said. The upgraded 4 kV circuits would allow more rooftop solar with and without battery energy storage, more electric vehicle charging, and more energy efficiency technologies, he admitted.
“The question is timing,” he said. “Is it justified now?”
DER advocates also approve of modernization that removes bottlenecks. “We want to see investment in places where it enables greater DER capacity,” Smeloff said. But they want to know if SCE’s investments are “based on an empirical understanding of what’s happening in the market.”
Experience has proven that uncontrolled back-feeding can damage transformer switching equipment, Smeloff acknowledged.
“It is important that people appropriately plan,” he said. “But we don’t want to see misappropriated spending and the buildout of infrastructure in places where it might not be needed for 10 years.”
Vote Solar is largely “in alignment with the vision Edison is articulating,” he added. “They want to become more of a technology agnostic distribution system operator and that’s the right endpoint.”
The SCE vision, appropriately tempered by its reasonable concern for maintaining reliability, is “a cutting-edge and important contribution to the national debate,” he said.
But there might be a better investment plan that only the hard slog of finding answers to these questions will reveal, Smeloff said. “We’d like to see Edison make commitments to procuring DER services through competitive processes and we hope a better understanding between third-party providers and the utility comes out of this dialog.”
TURN’s analysis has not yet concluded whether the timing and location of SCE’s grid modernization plan are on target, Hawiger said. The ratepayer advocate is assimilating data from CPUC proceedings, from SCE’s DER growth scenarios, and from the GRC’s DER sales growth scenarios.
But TURN has already identified unnecessary expenditures that SCE claims are necessary to deal with masked load, Hawiger said. Visibility is vital but system management software, along with existing DER interconnection information not now made available to system operators, is significantly less costly than distribution automation and can provide that necessary visibility.”
Menon said a GRC requires the utility to open its books to the commission and stakeholders. “The burden is on us to prove why we are proposing this work and this cost,” she said. “That’s just part of doing business.”
Data from California’s Distribution Resources Planning (DRP) proceeding may alter the utility’s targets and direction, she added. But this GRC is the utility’s present best forecast of “where we think DER penetration will be” and what the utility will need “to host that level of DER.”
Based on current system and technology assumptions, SCE has identified the circuits on which upgrades will allow a higher DER penetration without threatening operational flexibility, Menon said. But the transition to a modern grid is driven by policymakers and customers who want more reliable and renewable energy at a reasonable cost.
“The whole point of this GRC is to meet that demand by working with private sector DER providers and policymakers,” Menon said. “Some spending targets traditional utility concerns but, for the first time, some spending targets our move to a modern grid that can support higher levels of DER.”
Finally, Menon stressed, the GRC is a work in progress. “Every GRC plan is old the day you file it,” she said. “But this GRC is being refined with new information from other proceedings and other parties. And pilots and demonstration projects done in collaboration with policymakers and third party providers are leading to learning that will allow projects on a bigger scale.”
Public testimony in the SCE GRC will run through August. A final decision is due in January 2018.