As California moves to accommodate high flows of bi-directional distributed energy resources (DER), distribution system reform is needed, according to a white paper introducing a new series of regulatory workshops on the distribution system.
Identifying reform is essential to meeting the commission’s 2021 High DER Future Proceeding order, California Public Utility Commission Energy Division Staff Rob Peterson said during the first in a series of stakeholder engagement workshops on May 3. The objective of the order (R.21-06-017) and workshops is to “guide public and private sector investment for a high DER future” while “integrating equity and access to DER considerations,” Peterson added.
DER are renewable generation resources that connect to lower voltage power lines, and include electric vehicles, energy storage, energy efficiency, and demand response technologies, according to the California Public Utilities Code.
Though currently threatened by reconsideration of rooftop solar supports, California DER growth will accelerate, workshop participants agreed. Customer demand, the 2045 zero-emissions goal, technology evolution, and falling prices will be drivers, the white paper added.
California’s 2021 Integrated Energy Policy Report (IEPR) forecasts statewide installed distributed solar capacity to increase from 2022’s 14,048 MW to 24,721 megawatts in 2030, according to California Energy Commission spokesperson Michael Ward. Distributed energy storage capacity is projected to increase from 2022’s 740 MW to 2,587 MW in 2030, he added.
CEC data forecasts the state’s estimated 839,000 zero-emission vehicles in 2021 will reach 5.7 million light-duty passenger and medium- and heavy-duty vehicles by 2030, Ward said. And an estimated 1.5 million households had smart thermostats, according to the commission’s 2019 Residential Appliance Saturation Study.
Gov. Gavin Newsom’s Executive Order, which requires new car and passenger truck sales be 100% zero emissions by 2035, is expected to drive exponential transportation electrification growth. Assembly Bill 327, programs supporting battery storage and heat pumps, other policy initiatives, and utility and private sector DER incentive programs will also accelerate growth, the white paper added.
The paper offered guidance to the CPUC stakeholder-led workshop on potential distribution system operator (DSO) models for reliably managing expected DER penetrations.
A DSO could be a distribution level version of the California Independent System Operator to manage and be responsible for distribution system planning and operations. Or it could only operate “networks” at the commercial-residential level, the white paper said.
A DSO could also be “a neutral facilitator” of an open DER market that accepts offers from DER aggregators or individual owners rather than them being integrated through today’s IOU-controlled market, it added. Or it might be “the existing utility,” Lorenzo Kristov, who helped with California’s bulk power system design and was workshop consultant to The Climate Center, wrote in 2015.
Four “conceptual” new DSO models are outlined in the white paper. They range from complete control by California’s current system operator to a new independent DSO that coordinates lower voltage distribution lines with the high voltage bulk system. Workshop participants will be asked to identify “legal, regulatory, procedural, technical, and financial barriers” and regulatory or policy solutions for overcoming them.
A DSO or other new model for the roles and responsibilities of the distribution utility will be needed when “every electricity user can have DER and participate in an open access distribution network,” Kristov told the workshop. Incumbent utilities, regulatory agencies, and system operators have roles in an interactive open access network, “but the approach requires reshaping” to create a DER marketplace, he said.
The questions about who meets the roles and responsibilities of managing DER are “probably the most fundamental, contentious, and difficult issues in energy policy,” said Gridworks Executive Director Matthew Tisdale. He is leading the workshop process for the CPUC.
Regulatory reform first?
An obstacle to distribution reform are “the needs of incumbent utilities” to protect their business model under current regulation, California Alliance for Community Energy Operations Director Erika Morgan told the workshop on behalf of multiple community and environmental groups.
“The utilities, the distribution system, and its rules should serve the needs of the community, not the other way around,” California Alliance for Community Energy Coordinator Al Weinrub told Current. “A community-led process would identify DSO objectives before deciding on a DSO model,” he said.
California can learn from the United Kingdom and New York.
The UK’s five-year “step-by-important step” process to successfully incorporate a new DSO had the advantage of utilities familiar with performance-based regulation, British consultant Jason Brogden told the workshop. “Invest in stakeholder engagement” or risk an “academic” result that does not earn “buy in,” he cautioned.
The Distributed System Platform (DSP) proposed in the New York Reforming the Energy Vision (REV) proceeding is now part of New York’s Distributed System Implementation Plans (DSIPs), New York Department of Public Service spokesperson James Denn told Utility Dive.
But the DSIP effort is still incomplete, and there may be a lesson in the fact that California has reached a higher DER penetration without a reformed distribution system, the white paper said.
“We are moving to a future that will require investment in new distribution services,” but New York found only the utilities were willing take on those costs, said former CPUC President and DER advocate Michael Picker.
New York’s utilities took over REV’s DSP concept, but DSO benefits for California will be “analogous to those from a regional wholesale market,” former FERC Chair Jon Wellinghoff, a longtime DSO advocate, said. With the right utility incentives, “distribution level competition can drive multiple layers of efficiencies from new market products and resources.”
A workshop report from distribution circuit technology provider Utilidata found those costs are necessary and will be significant, added Utilidata VP of State Policy and Regulatory Lauren Randall.
California utilities are rapidly investing in grid modernization to support reliability, customer needs, state policy, and DER growth, Southern California Edison Senior Manager, Grid Modernization Policy, David Castle told the workshop. But any new DSO facing the “inherent complexity of reconfiguring the distribution system” should meet “upfront criteria and metrics” and a “detailed benefit-cost analysis,” he said.
“The current distribution utility model is not adequate, and the revenue model requires rethinking,” said Kristov. The “heart of the issue” is that DER are not a problem. They are the future and an alternative to costly utility infrastructure overbuilding if regulation compensates utilities for integrating them, he said.
But first, workshop participants must define the objectives for the 2030 power system in their own way, instead of accepting one of the models offered in the white paper that supports the existing regulatory framework, Kristov added. Then the regulatory changes and DSO model to deliver them can be designed, and a new regulatory framework can make that DSO the centerpiece of a new power system network.”
Quarterly reports on the workshops will go to the commission “as record evidence” in July and October 2022 and January and April 2023, with a final proposed commission decision scheduled for the final quarter of 2023.