MONDAY AGGREGATE: Energization PD; SoCalGas AFR of Electrification Pilot; Wildfire Mitigation PD

Today’s roundup examines how California’s regulatory framework is reallocating energy-infrastructure risk across utilities, customers, and departed load.

• Utilities get potential energization pathways via tariff but connecting customers face interim load restrictions until upgrades arrive.
• SoCalGas challenges electrification mandates as procedurally defective.
• PG&E absorbs $363 million in disallowed vegetation management costs despite regulatory approval of its mitigation plans.
• Bundled customers and departed load face renewed PCIA cost battles.
• Gas curtailments gain formal priority structure with year-long implementation buffer.

Across these actions, risk is redistributed through tariffs, settlements, and procedural sequencing rather than resolved through new infrastructure investment.

ENERGIZATION

The CPUC issued a proposed decision in its Timely Energization docket (R.24-01-018) that directs PG&E and SCE to establish a standardized, tariffed Standard Offer "Flexible Service Connection" to accelerate customer energization when distribution-level capacity constraints would otherwise delay service.

The PD formalizes a bridging mechanism (modeled largely on PG&E’s existing "Load Limiting Letter" practice) that allows customers to receive firm, near-term electrical service by adhering to a utility-defined Limited Load Profile until upstream upgrades are completed.

If the PD is ultimately adopted by the Commission, PG&E and SCE would be required to file a joint advice letter within 30 days. The filing would:

• Implement the standard offer;
• Update tariff rules;
• Add customer disclosure and opt-in mechanisms to service application materials; and
• Begin collecting detailed cost, performance, and curtailment data to support future refinement.

The PD applies only to PG&E and SCE and declines to impose requirements on SDG&E or small multi-jurisdictional utilities at this time. The PD emphasizes speed, safety, and scalability by relying on static load limits, existing engineering practices, and Advanced Metering Infrastructure-based compliance rather than real-time communications or DERMS integration.

The PD keeps the proceeding open to address additional Phase II energization issues, including dynamic Flexible Service Connections and broader process reforms. The earliest the CPUC will consider this item is February 5. Comments are due January 16.

INSTANT ANALYSIS: This PD formalizes a standardized/tariffed pathway for PG&E and SCE to serve customers facing distribution constraints by allowing interim service under predefined load limits. In essence, the Commission is turning an informal engineering workaround into a repeatable energization tool, and prioritizing speed and certainty over waiting for upstream upgrades. For large or fast-moving loads, this creates a clearer, earlier option to take service but it does not add physical capacity or resolve underlying distribution shortfalls.

ELECTRIFICATION PILOT

SoCalGas filed an application for rehearing of an October 2025 decision (D.25-11-009, see our summary here), arguing that the CPUC exceeded its legal authority and violated basic procedural requirements in establishing an electrification pilot for mobilehome parks.

SoCalGas contends that the rulemaking was scoped narrowly to improve safety by converting master-metered systems to direct utility service, not to eliminate gas service. Yet, SoCalGas argues, the decision:

• Imposed a new electrification initiative;
• Ordered decommissioning of existing gas infrastructure;
• Required long-term bans on future gas service through recorded land covenants; and
• Shifted evaluation costs to gas ratepayers without prior notice or evidentiary support.

SoCalGas argues these measures were never identified in scoping memos, staff proposals, or party briefs and therefore deny affected parties due process. SoCalGas further asserts that:

• The Commission lacks jurisdiction to impose land-use restrictions or override statutory rights to gas service;
• The gas ban is preempted by federal law; and
• Forced abandonment of utility assets constitutes an unconstitutional taking.

On this basis, SoCalGas asks the Commission to rehear and revise (or vacate) the decision to remove the gas ban, decommissioning mandate, and cross-subsidization requirements. Party responses are due January 12.

INSTANT ANALYSIS: This application for rehearing tees up a procedural vulnerability for the Commission: the electrification pilot, gas decommissioning mandate, and long-term gas ban all appear to have emerged at the proposed-decision stage without being properly scoped or litigated. If the Commission takes rehearing seriously, the cleanest off-ramp is to narrow or sever the gas ban and decommissioning provisions rather than defend a record that never clearly noticed those outcomes.

WILDFIRE MITIGATION

A new proposed decision in A.23-12-001 (which is tentatively scheduled for consideration on February 5) authorizes PG&E to recover a $1.416 billion revenue requirement. This amount includes costs incurred primarily in 2022 related to wildfire mitigation, vegetation management, catastrophic events, and a set of customer-protection and policy-driven memorandum accounts.

• The PD approves a broad, largely uncontested settlement resolving all cost categories except vegetation management, and directs PG&E to true-up recovery via the advice-letter process, with offsets for amounts already collected under interim rate relief granted in a 2024 decision (D.24-09-003).
• Most notably, the PD denies recovery of $363.4 million in vegetation management costs, finding that PG&E failed to meet the prudent manager standard for that portion of its 2022 spending recorded in the Vegetation Management Balancing Account.
• By contrast, the PD approves recovery (via settlement) of:
  • Wildfire mitigation costs in the Wildfire Mitigation Balancing Account;
  • Catastrophic event costs associated largely with the 2022 heat events and 2022–2023 winter storms; and
  • Costs recorded in multiple memorandum accounts covering COVID-era customer protections, disconnections, privacy compliance, climate vulnerability assessments, microgrids, and low-income affordability pilots.

The settlement reflects significant reductions from PG&E’s original request, incorporates Cal Advocates’ concerns about customer affordability, and preserves interim collections already underway, with remaining balances to be amortized beginning in March 2026. Comments are due January 15.

INSTANT ANALYSIS: While the PD authorizes recovery of $1.4 billion for 2022 wildfire mitigation, catastrophic events, and customer-protection programs through a settlement, it draws the line on vegetation management, disallowing $363.4 million for failure to meet the prudent manager standard.

The main takeaway for market participants is twofold:

• Catastrophic-event and policy-driven memorandum accounts continue to enjoy relatively high settlement tolerance when tied to declared emergencies and explicit CPUC mandates; but
• Vegetation management, despite its centrality to wildfire mitigation, remains subject to exacting, post hoc scrutiny, with Wildfire Mitigation Plan approval offering no safe harbor for cost recovery. (This begs the question: Is the Commission more comfortable approving costs after failure over costs that prevent failure?)

For utilities, the PD reinforces that execution quality and evidentiary granularity (not just scale or urgency) will determine recoverability in future wildfire-related filings.

PCIA & ERRA REFORM

A new ALJ ruling in the Commission's Power Charge Indifference/ERRA reform docket sets the next steps in the Commission’s effort to update and reform Energy Resource Recovery Account and PCIA policies.

• The ruling schedules a prehearing conference for January 23 and directs parties to meet and confer and file a joint prehearing conference statement by January 16. The rulemaking contains multiple tracks and has already resolved Track 1 issues related to the Market Price Benchmark via a decision last June (D.25-06-049).
• Track 2 will be narrowed to address an urgent issue that arose in the 2026 ERRA forecast proceedings: how to appropriately value Renewable Energy Credits generated prior to January 1, 2019, when those “pre-2019 banked RECs” are used for bundled service compliance and PCIA calculations in 2026 and later.

For the upcoming prehearing conference, the ALJ outlines preliminary issues focused on:

• Whether and how costs and benefits associated with pre-2019 banked RECs should be equitably allocated between bundled service customers and customers who later departed bundled service; and
• Whether the REC valuation methodology adopted in recent ERRA decisions can (or should) be applied on an industry-wide basis.

Parties are invited to propose alternative issue framing, discuss initial positions, comment on the proposed Track 2 schedule, and consider procedural steps that could facilitate settlement, while unrelated matters will be deferred to a potential Track 3 later in 2026. A proposed decision is envisioned for the September 3, 2026 voting meeting.

INSTANT ANALYSIS: This ruling formally narrows Track 2 to a single, high-stakes issue with immediate rate consequences: how pre-2019 banked Renewable Energy Credits are valued when used for bundled-service compliance after customer departures. By elevating this question out of the annual ERRA forecast context, the Commission is indicating discomfort with ad hoc, utility-specific Renewable Energy Credit valuation outcomes and is positioning itself to set an industry-wide precedent that could significantly shift PCIA cost responsibility between bundled customers and departed load. For market participants, the near-term takeaway is that PCIA mechanics tied to legacy RECs are now explicitly in play, with a fast procedural runway and an open invitation for settlement. This creates both downside risk and strategic opportunity for parties that engage early and shape the framing before valuation assumptions harden into CPUC doctrine.

PG&E Curtailment Procedures

PG&E filed Advice Letter 5161-G to implement a decision from October (D.25-10-042, summarized here), which approved revisions to PG&E’s gas curtailment framework.

The advice letter transmits the final tariff language for Gas Rule 1 ("Definitions") and Gas Rule 14 ("Capacity Allocation and Constraint of Gas Service"), along with PG&E’s proposed implementation timeline and a high-level implementation plan. The revised rules establish a new, standardized prioritization structure for gas curtailments intended to align PG&E’s practices with those of other California natural gas utilities.

PG&E proposes to implement the new curtailment procedures on November 1, 2026, coinciding with the start of the 2026–2027 winter gas season. PG&E explains that this delay is necessary to:

• Complete customer notifications;
• Coordinate with the CAISO and other grid operators;
• Update internal tools and procedures; and
• Conduct employee training, while avoiding disruption to the already-completed winter preparedness planning for the 2025–2026 season.

Until then, the existing versions of Gas Rules 1 and 14 will remain in effect.

PG&E notes that it has already engaged a broad set of stakeholders (including generators, gas storage operators, consumer advocates, and state agencies) and commits to continued updates through its Pipe Ranger website as implementation progresses.

Protests are due January 20.

INSTANT ANALYSIS: Advice Letter 5161-G operationalizes the Commission’s approval of a more stringent and standardized gas curtailment hierarchy, but PG&E’s proposed 2026 implementation date effectively defers the real-world impacts for nearly a full winter cycle. This gives large noncore customers (particularly electric generators and refineries) additional runway to adjust operations and negotiate minimum usage thresholds. The long lead time highlights both the operational sensitivity of gas curtailment reform and the Commission’s continued willingness to sequence gas reliability changes cautiously.