What a General Rate Case decides
A CPUC General Rate Case (GRC) proceeds in two phases. Phase 1 sets the utility's revenue requirement — how much it may collect overall. Phase 2 decides cost allocation and rate design — how that revenue requirement is split across customer classes. For industrial customers whose electricity bill is a top-three cost of production, Phase 2 is where cost causation either holds or breaks.
CLECA's CPUC general rate case intervention record covers every recent PG&E and SCE Phase 2: A.19-11-019, A.20-10-012, A.23-05-010, A.24-03-019, and A.24-09-014. Across these proceedings the positions cohere into a single methodological argument.
The long-run marginal cost framework
CLECA's position is that marginal cost should be measured on a long-run basis using methods the Commission has used for decades, against counterparties — the utilities, Cal Advocates, TURN, SEIA, CFBF — who advance variously short-run, embedded-cost, or outcome-driven alternatives that would understate industrial cost responsibility.
The specifics recur across proceedings. The Marginal Generation Capacity Cost should be derived from a long-run marginal cost framework, levelized over the rate-case cycle — a three- or four-year window rather than six — using a battery proxy of at least six hours, with corrections to the IRP annualization formula that systematically understates cost when battery prices are declining. In the PG&E 2023 GRC Phase 2, A.24-09-014, CLECA supported an eight-hour battery proxy, citing D.26-02-057 in R.25-06-019, which required load-serving entities to procure 6,000 MW of new long-duration capacity.
Energy, customer, and distribution costs
The same discipline applies to the other marginal cost components. The Marginal Energy Cost should be computed from the most current SERVM hourly prices, not from a stale prior-cycle PLEXOS run. The Marginal Customer Cost should use the Real Economic Carrying Charge methodology, not the Net Customer Outage method that Cal Advocates and TURN periodically advance. The Marginal Distribution Capacity Cost should be calculated using NERA regression — a method the Commission has used since D.91729 in 1981 — not PG&E's proprietary Distribution Test Investment Model.
The unifying principle is methodological continuity: methods the Commission has applied for decades should not be displaced absent a developed record showing they are no longer fit for purpose.
Phase 1 and the revenue requirement
CLECA also engages the revenue requirement side. In PG&E's TY2027 GRC, A.25-05-009, CLECA's testimony benchmarked the request against the prior record $9.6 billion single-GRC electric increase adopted in D.23-11-069, identified approximately $1.9 billion of authorized-but-unexecuted capital from the 2023-2026 period, and challenged approximately $3.1 billion of capital routed through a proposed New Business Balancing Account — citing D.24-12-074's finding that liberal two-way balancing account use disincentivizes cost control.
Why cost allocation is a competitiveness question
CLECA does not always win the technical points, but it consistently presses the framing point: cost allocation is not just an engineering exercise. Any method that pushes more cost responsibility onto industrial classes without a cost-causation basis worsens California's industrial rate gap — with California industrial electricity rates already roughly 300 percent of those in neighboring states — and accelerates the emissions leakage that undermines the state's own climate goals. CLECA typically partners with EPUC on cost allocation, part of a broader Joint Ratepayers coalition that appears throughout the GRC record.