California utilities outline integrated grid-planning pilots; stakeholders press for standard cost‑benefit tests

Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric presented competing approaches to “integrated planning” at a California Public Utilities Commission workshop, saying combining multiple types of distribution work — wildfire mitigation, equipment replacement and capacity upgrades — can reduce repeated construction and lower costs for customers.

Commissioner Maryam Hough opened the workshop by saying, “The purpose of today's workshop is for the utilities to consider how to better align the distribution needs under undergrounding, capacity upgrades for distribution infrastructure, wildfire mitigation, and the risk based decision making framework.” The workshop, organized under the High DER proceeding, is intended to inform advice letters the utilities must file later this year.

Why it matters

Utilities argued that planning projects to address multiple needs together can cut unit costs and reduce customer outages, but stakeholders pressed for a standard, transparent methodology to determine when upsizing or bundling is justified — especially where future load growth is uncertain. The commission directed two workshops and an advice-letter filing under the High DER Track 1 decision; participants said the record should make clear how integrated planning will interact with existing risk frameworks and general‑rate-case processes.

What the utilities said

PG&E described an “Integrated Grid Planning” (IGP) process that aggregates circuit-level needs — wildfire risk, asset health, capacity and reliability — and monetizes those risks to compare alternatives across the system. PG&E said it uses an internal platform (IGP SNAP) to convert model outputs into dollar-values and a portfolio tool (Copperleaf) to create an unconstrained “wish list” of projects that is later optimized and constrained by regional and operational limits. A PG&E manager said the company’s pilot “mega bundling” exercise reduced unit costs by about 18% on average and cut planned customer outage time nearly 50%.

Southern California Edison (SCE) said it has piloted integrated planning and has released more than 400 circuit segments for execution so far, with about 40 additional segments under review. SCE presented a four-dimension integration concept — drivers, voltage level, time horizon and asset type — and showed examples where reconductoring or undergrounding done for reliability or wildfire mitigation can be upsized to meet nearer-term capacity needs.

San Diego Gas & Electric (SDG&E) said integrated coordination is embedded in its existing processes: distribution planning results already flow into wildfire, reliability, new-business and other work streams. SDG&E described a case-by-case, local approach and said its smaller portfolio means fewer opportunities for large-scale bundling; it emphasized that customer energization timelines and certainty of loads often drive scheduling.

Stakeholders’ main concerns

Public Advocates Office supervisor Richard Ko said, “We think that cost benefit analysis is really important and we wanna ensure that the utility's cost benefit analysis methodology is robust and that the inputs are clear and transparent.” Parties asked for a single methodology rather than three different utility-specific approaches, recommended limiting benefits to ratepayer impacts (not broad social benefits) and urged mechanisms for off‑ramps if costs increase or forecasts change.

Several intervenors and non‑profit groups pressed the utilities to quantify how distributed energy resources, demand flexibility and storage (DERs) could reduce or defer distribution investments. Climate and consumer advocates said past efforts — e.g., the Distributed Investments Deferral Framework (DIDF) experience — did not fully capture DER value and urged the commission to ensure the EIS Phase 2 electrification and load‑flexibility work is folded into distribution planning decisions.

Questions left open

Participants debated how to treat uncertain/pending loads. Utilities said distribution forecasts look out more than a decade, but that integrated planning will typically use a shorter, more certain horizon (PG&E said it maintains forecast data up to 16 years and expects IGP inputs to focus on roughly a 10‑year window). Several parties asked whether integrated planning requires a project‑by‑project comparison of a bundled upgrade today against a not‑bundled upgrade in the future; utilities said that detailed phantom‑project costing for every possible later scenario would be costly and disruptive. They proposed instead to (a) show the incremental cost of bundling when it occurs and (b) supply examples/pilot results demonstrating likely net savings.

Process, schedule and next steps

The CPUC staff is collecting written questions and comments for workshop 2; participants were asked to submit topics by Oct. 24 (questions will be considered for workshop 2). Staff indicated workshop 2 is tentatively scheduled the week of Nov. 17, 2025, and utilities’ Tier 3 advice letters are due Dec. 15, 2025. CPUC staff and utility presenters said they will seek to clarify how integrated planning outputs map back to distribution‑upgrade project lists (DUPR/DUPR-like outputs), the General Rate Case (GRC) investment process and the Risk‑Based Decision Making Framework (RDF) used for wildfire mitigation.

What to watch for

Stakeholders will look for: (1) whether utilities submit a clear, auditable method for comparing incremental upsizing costs to avoided future investment costs; (2) explicit linkage between RDF and the integrated planning valuation so wildfire projects and capacity projects can be compared or coordinated without double‑counting; (3) how pending loads and scenario‑based planning are incorporated; and (4) how DERs and load flexibility are valued and integrated into proposed solutions.

Ending

The second workshop will focus on methodological detail and stakeholder feedback; utilities and parties said they will use the advice‑letter process to formalize approaches for the commission to review in December.