WEDNESDAY AGGREGATE: Resolution SPD-37 Disputes; Zonal Electrification Lessons; Responses to PG&E/Stanpac Filing

Today's roundup includes the following items.

• A summary of parties' responses to a recent joint application for rehearing challenging Resolution SPD-37, which revised the CPUC’s Senate Bill 884 undergrounding framework.
• PG&E's "Lessons Learned" report summarizing its experience with the proposed zonal electrification project at California State University Monterey Bay, which was ultimately withdrawn after extensive litigation and delay.
• An amended scoping memo in PG&E’s 2027 General Rate Case that incorporates implementation questions arising from Senate Bill 254, which changed how wildfire mitigation memorandum accounts may be used and reviewed.
• A summary of parties' responses to PG&E and Standard Pacific Gas Line Incorporated's recent joint application, which seeks approval for a multi-part transaction that would transfer substantially all of Stanpac’s remaining gas transmission pipeline assets to PG&E.
• Responses of PG&E and SCE to parallel applications for rehearing submitted by CalCCA that challenge the CPUC’s December approval of 2026 ERRA Forecast decisions for PG&E and SCE (D.25-12-027 and D.25-12-028, respectively).

A common theme is that intervenors are forcing the Commission to define the evidentiary and procedural standards required before utilities book significant costs, whether for wildfire, undergrounding, decarbonization, or legacy asset restructuring.

More detail is provided below.

UNDERGROUNDING/RESOLUTION SPD-37

As reported by CRI here, Cal Advocates, TURN, and the Mussey Grade Road Alliance recently filed a joint application for rehearing challenging Resolution SPD-37, which revised the CPUC’s Senate Bill 884 undergrounding framework.

These parties argue that the Commission committed legal error by creating an expedited “Phase 1 Application” process without defining party status, shortening response timelines to 15 days, and eliminating meaningful discovery and hearings. They contend these procedural defects violate the CPUC’s own rules and deny due process in decisions that will shape future undergrounding cost recovery.

On January 26, the Commission received two responses to the application for rehearing.

In a joint response, PG&E, SCE, and SDG&E urge the Commission to deny rehearing, arguing that the challenged aspects of SPD-37 fall squarely within the CPUC’s procedural discretion. They contend that the Resolution’s requirement for a joint Phase 1 application (addressing benefit-cost ratio methodology, audit design, and other cost-recovery conditions on an expedited schedule) does not constitute legal error or a denial of due process.

The utilities emphasize that:

• SB 884 expressly contemplates expedited action to address wildfire and reliability risk; and
• Stakeholders have already participated extensively over several years in workshops and guideline development at both the CPUC and Energy Safety.

By contrast, the Energy Producers and Users Coalition (EPUC) supports the rehearing application and argues that SPD-37's process risks producing an incomplete evidentiary record on decisions that will govern billions of dollars in future undergrounding costs.

• EPUC frames the Phase 1 determinations as foundational decisions, and contends that resolving them through a compressed 15-day response period, without clearly defined party status, discovery rights, or hearings, compromises the Commission's ability to ensure future costs are just and reasonable.
• According to EPUC, these procedural constraints conflict with the Commission’s own rules and constitutional due-process principles, increasing the risk that future cost recovery will be approved without adequate scrutiny or protection for ratepayers. Consequently, EPUC urges the Commission to grant rehearing and modify SPD-37 to require a more conventional application process, including longer response timelines, formal discovery, and a hearing framework.

INSTANT ANALYSIS: The rehearing dispute over SPD-37 is premised on a procedural disagreement rather than the merits of undergrounding itself. The utilities argue the CPUC acted within its discretion by forcing unresolved SB 884 methodology issues into a fast, front-loaded Phase 1 application, pointing to years of prior stakeholder process and the public-safety mandate to move quickly. EPUC and other intervenors counter that the Phase 1 determinations will govern billions in downstream cost recovery and therefore require a fuller record, longer response windows, and clearer participation rights before the Commission locks in benefit-cost and audit frameworks.

What matters for observers is that the Commission is being asked to decide how much procedural rigor is required before utilities begin booking large undergrounding costs into balancing accounts. Denial of rehearing would reinforce the CPUC’s latitude to compress process when wildfire risk is invoked and push contested design questions into later, plan-specific reviews. Granting rehearing would slow near-term implementation but raise the bar on upfront guardrails, tightening scrutiny over how SB 884 compliance is measured and audited. Either outcome shapes not just undergrounding, but how aggressively the Commission can streamline future safety-driven infrastructure programs.

PG&E – MONTEREY ZONAL ELECTRIFICATION

PG&E filed a “Lessons Learned” report in R.19-01-011 (Building Decarbonization) and R.24-09-012 (Long-Term Gas Planning) summarizing its experience with the proposed zonal electrification project at California State University Monterey Bay, which was ultimately withdrawn after extensive litigation and delay.

PG&E concludes that the project revealed three core challenges:

• Planning and execution for large-scale behind-the-meter electrification took far longer than anticipated due to tenant resistance, individualized construction logistics, and misalignment with the safety-driven schedule for required gas pipeline replacement;
• The expedited procedural schedule PG&E initially sought proved unrealistic given prolonged negotiations over scope, cost sharing, cost recovery, and cost-effectiveness, resulting in years of litigation that conflicted with pipeline safety obligations; and
• PG&E was overly optimistic about reaching settlement on contested issues and should instead assume litigation when designing future schedule-dependent decarbonization projects.

The Indicated Shippers’ incorporated comments emphasize deeper lessons, arguing that:

• PG&E’s economic analyses were flawed and non-transparent;
• Relied on cash-flow metrics rather than full lifecycle revenue requirements;
• Failed to account for lost gas revenues, overhead costs, and long-term ratepayer impacts; and
• After correcting for these flaws, the electrification alternative yielded a benefit-cost ratio below 1.0, meaning it was not cost-effective for remaining gas customers.

The Indicated Shippers further objected to regulatory asset treatment for behind-the-meter appliances and to allocating electrification costs to gas ratepayers who did not benefit from the project, urging future proposals to rely first on non-ratepayer funding and strict cost caps.

The Shippers also highlighted a procedural lesson: confidential data responses supporting PG&E's economic analyses were excluded from the evidentiary record due to inadequate confidentiality declarations, leaving the record without detailed cost data directly relevant to evaluating PG&E's claims.

• TURN largely agreed with the need for more realistic timelines but criticized PG&E’s draft for underemphasizing policy, cost, and ratepayer impacts. TURN recommended that future lessons-learned reports more clearly document disputed assumptions, cost inputs, and methodological choices, and that the Commission adopt uniform cost-recovery policies to avoid re-litigating the same issues project by project.
• TURN also stressed that safety-driven pipeline risk information should be disclosed early in future proceedings to avoid late-stage project collapse and unnecessary delay. For future Senate Bill 1221 projects specifically, TURN suggested that local entities beyond the utility should be involved in conversations with property owners and tenants to promote acceptance by all affected parties.

INSTANT ANALYSIS: PG&E’s “Lessons Learned” filing reads as a retreat from project-by-project electrification as a substitute for safety-driven gas infrastructure work. The record shows that zonal electrification, when layered onto an active pipeline replacement schedule, creates timing conflicts, prolonged litigation risk, and unresolved cost allocation disputes that can overwhelm any near-term policy upside.

Intervenor contributions expose a deeper problem: electrification alternatives were evaluated using incomplete economic frameworks that understated long-term gas ratepayer exposure, omitted lost fixed-cost recovery, and relied on optimistic assumptions about behind-the-meter assets the utility would not own.

In sum, the main takeaway is that, without upfront resolution of cost recovery rules, ownership treatment, and full lifecycle revenue impacts, electrification proposals will continue to stall or collapse when tested against safety obligations and affordability constraints. For the CPUC, this filing strengthens the case for setting uniform cost-recovery and evaluation standards before advancing additional non-pipeline alternatives, rather than litigating those questions one project at a time.

PG&E – GENERAL RATE CASE

Commissioner John Reynolds issued an amended scoping ruling in PG&E’s 2027 General Rate Case to incorporate implementation questions arising from Senate Bill 254, which changed how wildfire mitigation memorandum accounts may be used and reviewed. (SB 254 took effect September 19, 2025 as an urgency statute.)

SB 254 shifts prior statutory requirements by giving the CPUC discretion (rather than a mandate) to allow memorandum accounts, and limits eligible costs to those that are both unforeseen and incremental to amounts already authorized in a utility’s revenue requirement.

In response, the ruling expands the scope of the proceeding to consider whether:

• PG&E may continue recording wildfire mitigation costs to its existing Wildfire Mitigation Plan Memorandum Account (WMPMA) and Fire Risk Mitigation Memorandum Account (FRMMA);
• Additional guidance is needed on what qualifies as “unforeseen” and “incremental"; and
• New or revised administrative processes should govern future cost tracking and recovery.

PG&E and other parties are directed to address select questions on these issues by February 6 while all other elements of the July 31, 2025 scoping memo remain unchanged.

INSTANT ANALYSIS: This ruling formally pulls SB 254 implementation into PG&E’s 2027 GRC and puts wildfire memorandum accounts on notice. By reframing WMPMA and FRMMA eligibility around costs that are both unforeseen and incremental, the Commission is testing whether legacy wildfire tracking mechanisms remain appropriate inside a forward-looking revenue requirement. The key issue is discretion: memorandum accounts are no longer assumed, and continued use may require explicit approval and stricter process guardrails.

Practically, this affects wildfire cost recovery pathways. If the Commission directs PG&E to close or freeze existing memorandum accounts, utilities may be pushed to front-load wildfire mitigation costs into base rates or seek pre-authorization through advice letters or applications. The outcome will shape how wildfire risk is priced, monitored, and litigated in future GRCs and suggests a broader shift away from open-ended, after-the-fact wildfire cost booking toward more disciplined up-front ratemaking.

PG&E – NATURAL GAS TRANSMISSION

As summarized here at CRI last month, PG&E and Standard Pacific Gas Line Incorporated (Stanpac) recently filed a joint application seeking approval for a multi-part transaction that would:

• Transfer substantially all of Stanpac’s remaining gas transmission pipeline assets to PG&E;
• Restructure how Chevron receives gas transportation service; and
• Ultimately wind down the nearly century-old Stanpac joint venture.

Chevron, which owns a 1/7 non-controlling interest in Stanpac, supports the transaction, arguing it is a practical solution to avoid more than $100 million in system upgrades otherwise required to meet Chevron’s historic 30.7 MMcf/d entitlement, and asserting that the transaction would yield net savings to PG&E ratepayers while maintaining Chevron’s gas delivery through a 20-year transportation agreement largely implemented via PG&E facilities

On the other hand, Cal Advocates protested the application, raising concerns about:

• The valuation of StanPac and Chevron’s interest;
• The fairness of PG&E paying the full asset value despite already owning 6/7 of the utility;
• The proposed ratemaking treatment and affiliate-transaction compliance; and
• The reasonableness of allowing StanPac to persist for 20 years after its assets and operations are effectively absorbed by PG&E, with Chevron’s remaining stock transferred only at the end of that term for a nominal price.

INSTANT ANALYSIS: This filing presents a clear policy divide. Chevron characterizes the transaction as a cost-avoidance measure that replaces an open-ended legacy structure with a defined, contract-based arrangement anchored in PG&E’s newer infrastructure, with claimed net savings to ratepayers. Cal Advocates does not dispute the operational rationale, but is positioning the case around valuation, ratemaking, and governance, questioning:

• Why PG&E should pay full asset value for an entity it already largely owns;
• Why StanPac should persist for two decades after its assets and operations are absorbed by PG&E; and
• Whether the affiliate mechanics comply with all pertinent rules.

This proceeding is shaping up as a fairness and precedent case, not a reliability case.

PG&E and SCE – ENERGY RESOURCE RECOVERY ACCOUNT FORECAST DECISIONS

As reported at CRI here, CalCCA recently filed parallel applications for rehearing that challenge the CPUC’s December approval of 2026 ERRA Forecast decisions for PG&E and SCE (D.25-12-027 and D.25-12-028, respectively). PG&E and SCE have since responded to the applications. SCE's response is pointed, calling CalCCA's challenge "frivolous" and suggesting the Commission should "consider the troubling lack of restraint" in CalCCA's argumentation.

In response, both utilities stress that a June 2025 decision (D.25-06-049) revised the Resource Adequacy Market Price Benchmark and directed its immediate use for the 2025 true-up and 2026 forecasts. That decision is final and operative absent a judicial stay, the utilities hold, and the Commission was required to implement it in the ERRA forecast decisions.

• The utilities also reject claims of retroactive ratemaking, explaining that ERRA and Power Charge Indifference Adjustment rates are pass-through, balancing-account mechanisms. They do not set general rates or utility profit and therefore do not implicate the retroactive ratemaking doctrine.
• Additionally, PG&E and SCE argue that CalCCA’s challenges amount to an impermissible collateral attack barred by Public Utilities Code §1709.
  Disagreement with D.25-06-049, they contend, must be resolved on appeal, not re-argued in annual ERRA proceedings.

On the matter of pre-2019 banked Renewable Energy Credits, both utilities defend the Commission's adoption of a zero valuation for 2026 rates. They argue those attributes were fully paid for in prior years' rates and that customer indifference does not require new compensation to departing load.

PG&E cites a 2018 joint working group report co-led by CalCCA itself, in which CalCCA agreed that a D.19-10-001 REC methodology would apply only to RECs "generated commencing January 1, 2019 and going forward" because earlier RECs had already been bought and paid for.

Both responses note that broader REC policy questions are being examined in a separate rulemaking. On this basis, they urge denial of rehearing and rejection of CalCCA’s request for oral argument.

INSTANT ANALYSIS: This rehearing dispute focuses on whether the Commission made new policy in the 2026 ERRA decisions. PG&E and SCE argue it did not, and that the decisions simply applied rules set in the 2025 PCIA proceeding. On RA pricing, the utilities say D.25-06-049 required the revised benchmark to be used for the 2025 true-up and 2026 forecast. They argue the Commission was bound to apply that directive because no court has stayed it. CalCCA's position is that this treatment is unlawful retroactive ratemaking.
The IOUs counter that the issue was already litigated and is not properly revisited through ERRA rehearing.

On pre-2019 RECs, the Commission accepted a zero valuation for 2026 rates. The utilities argue those credits were fully recovered in prior rates and do not create new departing-load value. The 2018 working group citation is particularly damaging to CalCCA's position, as it suggests the organization previously endorsed the very interpretation it now challenges.