WEDNESDAY AGGREGATE: PG&E Challenges CPUC Denial of $172M in Vegetation Management Costs
Today's update covers:
- PG&E's wildfire mitigation costs;
- Zonal decarbonization pilots; and
- SoCalGas's Distribution Integrity Management Program.
WILDFIRE MITIGATION
PG&E filed for rehearing of D.26-02-004, seeking to overturn the CPUC's denial of approximately $172 million in cost recovery for 2022 Enhanced Vegetation Management work.
PG&E's original application sought recovery of about $353 million in Enhanced Vegetation Management expenditures exceeding the 120% threshold authorized in the 2020 General Rate Case.
The initial proposed decision would have disallowed the full amount; a revised PD, adopted February 5, reduced the disallowance but still denied recovery for work performed after October 2022, when the CPUC determined PG&E should have recognized diminishing cost-effectiveness and scaled back.
(See CRI's coverage here.)
MC
PG&E advances three independent grounds for reversal.
- On jurisdiction, PG&E argues the Legislature transferred Wildfire Mitigation Plan oversight to the Office of Energy Infrastructure Safety (Energy Safety) in 2021, leaving the CPUC authority to review how utilities implement approved work, not whether that work should have been performed. The disallowance is based on disagreement with the Energy Safety judgment, which the statute assigns to Energy Safety alone.
- On abuse of discretion, PG&E notes the Commission ratified its 2022 Wildfire Mitigation Plan without raising Enhanced Vegetation Management concerns, then disallowed costs four years later. The record shows Energy Safety was presented with the identical cost-effectiveness arguments (TURN urged Energy Safety to cut PG&E's Enhanced Vegetation Management target by 99%) and Energy Safety rejected them. PG&E argues it would have been both procedurally impracticable and substantively futile to seek a mid-year change.
- On constitutional grounds, PG&E raises takings and due process claims, distinguishing Duquesne by arguing that PG&E was compelled by a regulator to perform specific work under threat of penalties, unlike the discretionary utility investments at issue in that case.
INSTANT ANALYSIS: This is a jurisdictional fight that will define CPUC authority over every wildfire mitigation dollar. If PG&E prevails, Energy Safety will control what gets done, the Commission will review how. If the decision holds, utilities face retroactive cost risk on all Wildfire Mitigation Plan spending, rationally incentivizing underinvestment in Energy Safety-approved safety work and defeating the purpose of the 2019 restructuring. The constitutional claims add a second vector: if takings or due process arguments gain traction on appeal, the CPUC's disallowance authority could be constrained well beyond Wildfire Mitigation Plans.
LONG-TERM GAS PLANNING
A new ruling in the Long-Term Gas Planning docket seeks additional input from stakeholders to support implementation of Senate Bill 1221, with a focus on how utilities should recover costs associated with zonal decarbonization pilot projects.
The ruling reflects that prior comments were insufficient for resolving key policy questions, particularly around how to treat behind-the-meter zero-emission alternative costs, which SB 1221 prohibits from being recovered as traditional capital investments afforded a full rate of return.
The threshold question is whether two provisions of the statute are in conflict.
- Section 663(b)(8) prohibits capital cost recovery with a rate of return for BTM expenditures.
- While Section 663(b)(9) directs the Commission to establish an appropriate rate of return and recovery period for implementing zero-emission alternatives.
The ALJ is asking parties to address whether these provisions can be harmonized, and if so, how. The Commission is pressing parties to weigh in on whether utilities should be allowed to recover BTM costs from ratepayers at all, and if so, what accounting treatment should apply (including expensing versus regulatory asset treatment with defined amortization periods and depreciation schedules).
The ruling lays out three potential frameworks for compensating utilities if BTM costs are recoverable:
- Option 1: Treating BTM expenditures as expenses amortized over time with a carrying cost equal to the utility's authorized cost of debt (currently 5.04% for PG&E, 5.02% for SoCalGas, and 4.59% for SDG&E per a 2025 decision, D.25-12-043).
- Option 2: Granting regulatory asset treatment with a hybrid rate of return set at the midpoint between the utility's cost of long-term debt and its authorized capital rate of return, resulting in 6.325% for PG&E, 6.27% for SoCalGas, and 6.00% for SDG&E, compared to their full capital returns of 7.61%, 7.52%, and 7.41% respectively. BTM assets under this option would be amortized over a shorter period and depreciate faster than traditional gas capital assets.
- Option 3: Combining cost-of-debt recovery with a performance-based shareholder incentive tied to measurable outcomes (infrastructure retirement, customer conversions, and budget adherence). Under this model, utilities could earn up to 25% of net system cost savings, adjusted by a tiered performance multiplier, while the remaining benefits flow to ratepayers. The ruling illustrates the concept with a scenario producing $30 million in net savings and a mid-tier performance score, yielding a $3.75 million shareholder reward.
Comments are due March 27, and replies are due April 3.
INSTANT ANALYSIS: This ruling shifts the proceeding into financial design territory. The question is no longer whether pilots happen, but how utilities get paid, and the statutory tension between 663(b)(8) and 663(b)(9) is the fulcrum. Capital-style returns for BTM expenditures are almost certainly off the table given the explicit statutory prohibition. The real debate is between straight cost-of-debt recovery and performance-based incentives. Option 3 stands out; the ALJ devoted the most detailed treatment to it, building out a full formula and worked example, which suggests where the Commission's analytical thinking may be heading.
For utilities, the spread between cost-of-debt (approximately 5%) and the Option 2 hybrid (approximately 6% to 6.3%) represents the financial stakes of this design choice. For ratepayer advocates, the question is whether any return above cost of debt is justified for assets the utility will not own or maintain.
NATURAL GAS DISTRIBUTION INTEGRITY
A new ruling in SoCalGas's Distribution Integrity Management Program Balancing Account (DIMPBA) proceeding finds that Cal Advocates' testimony is internally inconsistent and requires clarification before the proceeding can move forward.
The ruling identifies major discrepancies in Cal Advocates' testimony, including conflicting recommendations on how much of SoCalGas' requested costs should be disallowed and unclear calculations underlying those figures. The ruling also notes SoCalGas's allegation that Cal Advocates recommended disallowing capital revenue requirements already approved by Resolution G-3610.
In response, the ruling directs Cal Advocates to submit supplemental testimony clearly explaining what portion of SoCalGas' requested DIMP costs should be deemed unreasonable and how prior CPUC approvals factor into that assessment. Cal Advocates must serve supplemental testimony by April 17, with supplemental rebuttal testimony to follow by May 18.
The ruling also modifies the proceeding schedule, establishing a meet-and-confer deadline of May 28, a joint case management statement due June 1, a potential evidentiary hearing window in July 2026, and briefing through September 2026. The joint case management statement must address whether parties will stipulate to the scoped issues and whether an evidentiary hearing is necessary.
INSTANT ANALYSIS: The ALJ is forcing Cal Advocates to fix inconsistent testimony, which weakens their current position but gives them a chance to reframe the case. SoCalGas gains near-term breathing room, as the Commission is not relying on the existing disallowance claims. The real issue is whether prior approvals of DIMP costs (particularly those under Resolution G-3610) hold. If they do, SoCalGas is in a strong position. If not, a meaningful reduction in recovery remains in play.