PG&E may answer the billion dollar grid modernization question

California regulators have taken the biggest step forward yet to clarify what grid modernization is, how to prioritize technology deployments and what costs are appropriate.

A new framework, prompted by the controversial Southern California Edison (SCE) $1.9 billion grid modernization spending request, gave Pacific Gas and Electric (PG&E) clear direction on its proposed grid modernization expenditures and on what is eligible for cost recovery through rates.

The proceeding could lead to new clarity for utilities and regulators across the country on the ill-defined grid modernization concept and allow higher penetration of distributed energy resources (DER), stakeholders told Utility Dive.

“Grid modernization proceedings in almost every state have identified objectives and recommendations, but there is still no agreement on what investments are or are not appropriate,” Autumn Proudlove, senior research director for the Clean Energy Technology Center (CETC) grid modernization policy quarterly, told Utility Dive. “California is getting to a more granular level on how to prioritize technologies and spending.”

There is a lot of money at stake. Utilities proposed $14.2 billion across 17 grid modernization proceedings pending in Q2 alone. California’s next steps could influence that spending, as well as the many investments likely to follow.

“There is wide agreement on the need for investment, but the high price tag makes it necessary to carefully prioritize investments,” Proudlove said. “California is one of the first movers, but commission staff tell us they are beginning to think about those spending priorities.”

Two factors made California the national leader, according to stakeholders: a framework established by the state’s regulators and extensive system planning by SCE and PG&E.

California’s grid modernization framework

California’s 2013 Assembly Bill 327 established a public utility code section that required distribution system planning. A subsequent ruling by the California Public Utilities Commission (CPUC) required utilities and stakeholders to develop a framework for IOU grid modernization proposals in their General Rate Cases (GRCs).

The framework had two objectives: identify investments needed “to integrate the growing number of DERs” and determine how customer-owned DER should be valued.

A CPUC Distribution Resource Planning Order followed, establishing guidance on IOU grid modernization expenditures. It was not put in place in time to guide SCE’s proposals, but will be used to evaluate PG&E’s December 2018 GRC application.

Unlike other GRC expenditures, grid modernization spending must, in addition to being “just and reasonable,” also make possible “net benefits” for ratepayers, the commission ruled.

The guidance applies to all investments made to integrate DER that serve customers or provide grid services, but not “investments made solely for safety and reliability purposes,” the ruling added. It does, however, apply to “next generation” technologies that cost-effectively protect safety and reliability.

Stakeholders urged the CPUC to be more definitive about these investments, but the commission declined, maintaining narrower guidance “would pre-judge the GRC process” where final approvals should be made. Whether expenditures to integrate DER are justified “remains squarely in the GRC process.”

The framework now requires each IOU to separately identify a Grid Modernization Plan (GMP) in its GRC filing. The plan must be developed in a pre-filing public workshop and include a 10-year grid modernization “vision.”

SCE’s GRC, filed in mid-2017, controversially demonstrated what a utility faced with rising DER penetrations could propose as grid modernization without commission guidance.

Lessons from SCE

The purpose of SCE’s plan was to prepare its distribution system for 1.5 million new DERs by 2025 without compromising safety or reliability, according to its “Emerging Clean Energy Economy” white paper.

Investments included structural upgrades, automation and telecommunications capabilities, and system management, SCE GRC director Shinjini Menon told Utility Dive when the application was filed in 2016. The plan would have also added distribution system technology platforms to integrate DER and use it for grid services.

But the utility did not demonstrate “net benefits for ratepayers,” managing director of Vote Solar’s regulatory team Ed Smeloff said after the CPUC cut the investment to $613 million. The plan also “failed to account for opportunities to use DERs and other third-party services to minimize costs.”

Most objections on the proposed spending were about timing, not technology, Smeloff told Utility Dive. The utility “tried to do too much too soon.”

SCE is now workshopping a new plan for its next rate case, SCE Director of Grid Technology and Modernization Vibhu Kaushik told Utility Dive. The commission approved some of its proposed investments on reliability and automation, and other investments, such as a system management platform and central communication capabilities, were not explicitly ruled out.

SCE will more clearly prioritize its spending requests in its 2021 GRC, Kausik said. The utility’s first priority is replacing its now-obsolescent 10-year-old distribution management system with an advanced distribution system management (ADMS) platform to improve communications and cybersecurity capabilities.

The new software platform will “incorporate” and “refresh” the existing operations management system (OMS) and data acquisition system, he added. It will allow SCE to meet distribution resource planning standards for DER integration “by improving our ability to manage DER semi-autonomously and in real time.”

As DERs grow, SCE’s priority will shift toward a distribution energy resource management system (DERMS), Kaushik said. The ADMS “will help with resiliency, and more automated technology will improve reliability. Then we can optimize DER and allow customers to be part of the solution, but that is several years out and includes DERMS capabilities that are now only conceptual.”

SCE’s last proposal lacked commission guidance, but “PG&E’s vision, based on the commission framework, could become a national grid modernization template,” Solar Energy Industries Association (SEIA) Regulatory Counsel and California Affairs Director Rick Umoff told Utility Dive.

“Obscene” spending or a national grid mod template?

A joint Vote Solar-SEIA filing endorsed PG&E’s vision.

Only two pieces are missing from the proposal, say the solar groups: A method for assessing cost rationale and more clarity on “the full costs for each program during and beyond this GRC cycle,” former PG&E executive and President of New Energy Advisors Curt Volkmann wrote on behalf of the solar advocates.

“PG&E is proposing a reasonable investment sequence and this GRC will be a full evidentiary process on it, bounded by the commission’s established priorities,” SEIA’s Umoff said. “It will allow a real stakeholder-led examination of prudence, and could standardize the utility rate case process on grid modernization.”

The CPUC framework “did not fundamentally change our grid modernization proposal, but it helped clarify the meaning of grid modernization” and that “DER integration is a sub-component of it,” PG&E Director of Integrated Grid Planning and Innovation Quinn Nakayama told Utility Dive.

PG&E is requesting spending for an ADMS that will incorporate existing OMS, data acquisition and other distribution system tools to create an Integrated Grid Platform, Nakayama said. It will improve operational efficiency, enhance cybersecurity and “lay the groundwork for future DER integration.”

The sequencing of PG&E’s grid modernization planning is defined by a four-level hierarchy. On the first two levels, the utility will work on modernization and on traditional infrastructure that “is part of grid modernization but goes above and beyond DER integration,” Nakayama said. “As you move up the pyramid, it becomes much more DER intensive.”

The current GRC gets into the second level’s system monitoring and management technologies, outage detection, automation and DER awareness technologies, Nakayama said. “That will allow us to integrate DER in a way that does not negatively impact other customers.”

The third level, scheduled for the next GRC, will focus on using DER to deliver grid services. It will require new visibility, analytics, management and control technologies to use DER as non-wires solutions or begin providing those services to markets.

At the top of PG&E’s hierarchy are technologies that will create “an optimization platform in which customers participate in markets by receiving and responding to price signals,” Nakayama said. “But before we invest in tools needed for that platform, we want to get experience with DER through pilots.”

With funding from California programs designed to encourage power sector innovation, PG&E is now planning and running small pilots involving DER integration, he added.

But there is disagreement about which should be deployed first: ADMS or DERMS.

“To optimize DER with expected near-term DER penetrations, we need the ADMS,” said SCE’s Kaushik. “To get to 100% true DER optimization requires DERMS, but moving to DERMS first is like going after the cherry on top and forgetting about the cake.”

California IOUs are far from needing a DERMS’ granular control of DER, SEIA’s Umoff agreed. “Start with ADMS, then consider DERMS, as PG&E recommended in its filing.”