CPUC workshop lays out path for ‘flexible connections’; utilities push pilots, parties debate standards and compensation

SAN FRANCISCO — The California Public Utilities Commission convened utilities, vendors and advocates on June 12 to examine so‑called “flexible connections” — a set of control and market tools that allow customers to connect to the grid sooner by operating under time‑ or condition‑limited service envelopes.

Gabe Petlin, supervisor in the CPUC energy division, opened the all‑party workshop by previewing the eight topics the commission asked parties to address, from ADMS/DERMS readiness to communications protocols and the roles of aggregators. ‘‘We want this to be an open dialogue,’’ Petlin said as staff laid out the difference between bridging solutions (temporary limits tied to planned wire upgrades) and non‑bridging approaches that would provide ongoing non‑firm service.

Why it matters: California’s grid faces rapid electrification and large new loads such as fast chargers and batteries. Flexible connections, proponents say, can reduce the time and cost to connect customers, unlock existing capacity and potentially delay expensive grid upgrades — but they also raise questions about data sharing, standards and when (or whether) customers should be paid to accept limits.

What the utilities proposed: Pacific Gas & Electric described its FlexConnect program and DERMS deployment, saying the company’s DER management system (Schneider Electric’s EcoStruxure) has been used in production at six sites since October 2024 and now dispatches variable operating envelopes via IEEE 2030.5. ‘‘As of February 2026, we have…6 sites go through the program. There are 5 currently live in the program right now,’’ Alex Collins, who manages PG&E’s DERMS group, said during the presentation. PG&E said the program currently focuses on large distribution customers (batteries and 1–10 MW EV fleets) but that the utility models thousands of feeders and can add capability where value is shown.

PG&E emphasized operational protections. The company requires local fail‑safes — for example, ‘‘if the site loses connection with our DERMS system for more than 15 minutes, we require that site to also go down to its lowest safe operating limit,’’ Collins said.

On the secondary‑network front, PG&E presented AMI‑edge pilots it is funding through EPIC to limit EV charger load at the meter and avoid panel or service upgrades. ‘‘This is something that we can do to connect a customer in probably under a week without any of those upgrades,’’ a PG&E presenter said of the meter‑based EV‑charger approach.

SCE and SDG&E roadmaps: Southern California Edison outlined a phased ADMS/DERMS approach — integrating forecasting, optimization and state estimation — and said it plans day‑ahead VOEs plus real‑time dynamic envelopes once pilots are successful. San Diego Gas & Electric described ongoing proof‑of‑concept work and said it is not yet positioned to deploy territory‑wide VOEs until additional telemetry, modeling and verification capabilities are in place.

Standards and communications: A major thread was how to translate distribution‑level VOE dispatches into device actions. Utilities argued for a unified utility‑grade dispatch interface and noted that IEEE 2030.5 (CSIP) is being used for many dispatch and telemetry functions. Community choice aggregators and other third parties urged using OpenADR as a complementary standard for event signaling and argued it can be lower‑cost to scale for demand flexibility use cases; technical experts on the call noted OpenADR‑3 and IEEE 2030.5 have converged architecturally but implementers still face transition costs.

On compensation: Parties pressed whether the commission expects direct customer payments for non‑bridging service. Staff read the Assigned Commissioner’s framing as a near‑term boundary condition that the workshop would focus on tools and pilots without broad new monetary compensation structures, but left the door open to in‑kind value exchanges and future consideration. ‘‘When we say ‘not payments,’ we mean value — equipment or other measures that materially reduce customer cost — could still be part of a value proposition,’’ a staff speaker said.

Stakeholder views: Community Choice Aggregators argued CCAs already operate VPPs and DERMS and could be partners for secondary‑level VOEs; they recommended pilots that give CCAs low‑latency data and the ability to participate. The Interstate Renewable Energy Council highlighted international model‑free hosting‑capacity approaches used in Australia as potentially lower‑cost ways to produce VOEs. Vehicle and charger industry groups urged elective, customer‑facing non‑bridging options and said meaningful incentives or equipment support will be needed to reach wide participation.

Quotes that capture the day: ‘‘We will send them daily schedules until the last day where that schedule becomes effectively locked,’’ PG&E explained of its day‑ahead VOE practice, stressing predictability for customers. SCE summarized the near‑term path: ‘‘We’re planning to provide a 24‑hour look‑ahead operating envelope based upon the forward‑looking forecast.’’

What’s next: Staff said utilities will prepare a workshop report for the record and that the proceeding aims for a proposed decision later this year. Many parties urged the commission to require or fund pilots that collect rigorous cost‑benefit data, to convene technical forums on protocol interoperability, and to define data‑access needs for third‑party DERMs and CCAs.

Bottom line: The workshop advanced technical detail and pilot experience — notably PG&E’s FlexConnect and AMI‑edge pilots — but left open higher‑level questions about standards coordination, how to measure and pay for avoided upgrade value, and how to scale low‑cost secondary solutions for millions of customers.