February 5, 2026 CPUC Voting Meeting Preview: Flexible Service Connections; PG&E Wildfire Recovery Costs; SoCalGas Distribution Integrity

The CPUC will convene on February 5 for its second voting meeting of the year. Items currently scheduled for consideration include:

• A proposed decision in the Commission's Timely Energization rulemaking 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.
• A PD authorizing PG&E to recover a $1.416 billion revenue requirement, which 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.
• A PD granting SoCalGas partial interim rate recovery for costs recorded in its Distribution Integrity Management Program Balancing Account between 2019 and 2023. The PD authorizes SoCalGas to recover $35.5 million on an interim basis, representing 60% of the $59.1 million requested, for a 12-month period, subject to refund with interest pending a final reasonableness determination.
• A draft resolution approving SCE's request to enter into 10 clean energy resource contracts resulting from its 2024 Clean Energy Request for Offers. This portfolio totals 2,093 MW of nameplate capacity across four projects, including large single-axis solar PV facilities and paired, co-located four-hour lithium-ion battery storage systems in California and Nevada.
• A PD which has been bounced repeatedly from consideration at recent CPUC voting meetings, denying a request of California Resources Production Corporation for a Certificate of Public Convenience and Necessity to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation.
• A draft resolution approving emergency interim rate relief for Crimson Pipeline's SPB-KLM system. The draft resolution approves an interim rate increase effective August 1, 2025, with authority to allow retroactive collection subject to refund.
• A draft resolution approving Phillips 66 Pipeline LLC's request to withdraw utility service on crude oil pipeline Lines 100, 200, 300, and 400 and to cancel its tariff, marking Phillips 66's complete exit from California crude pipeline utility operations and concluding an uncontested Tier 3 advice letter process.

Additional details are available below.

ENERGIZATION

A proposed decision in the CPUC's 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.

Additional implementation requirements include:

• A separate Tier 2 advice letter within 30-45 days formalizing preliminary capacity assessment processes;
• SCE must file a Load Control Management Study pilot learnings report by March 1, 2026; and
• Both utilities must submit a comprehensive cost-efficiency and revenue requirement impact report by January 15, 2029.

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 Standard Offer establishes minimum profile granularity (three seasons, two daily capacity values per season) and creates a "safe harbor" for loads controlled by UL 3141-certified Power Control Systems, exempting such controlled loads from connected load calculations.

The PD keeps the proceeding open to address additional Phase II energization issues, including dynamic Flexible Service Connections and broader process reforms.

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.

WILDFIRE MITIGATION

A proposed decision in A.23-12-001 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). (Because approximately $943.9 million was already collected through interim rates, only $2.2 million in new collections will begin in March 2026.)
• 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.
• The largest disallowance ($353.4 million for Enhanced Vegetation Management) rests on the PD's finding that PG&E knew by February 2022 that the program delivered minimal risk reduction (2.5 risk-spend efficiency versus 3,501.4 for routine vegetation management) yet spent $715 million more from March through December without reconsidering the program or its costs.
• 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.

The PD also rejects PG&E's claim that threshold-triggered balancing accounts are exempt from incrementality analysis, clarifying that utilities must prove costs exceeding GRC authorizations were not already funded elsewhere. For future applications, the Commission orders PG&E to provide enhanced comparative data linking GRC-authorized unit costs to actual recorded costs, with specific breakdowns by activity type.

INSTANT ANALYSIS: The main takeaway for market participants is twofold:

• Catastrophic-event and policy-driven memorandum accounts continue to receive favorable treatment when linked to declared emergencies and explicit CPUC mandates; but
• Vegetation management remains a high-risk category for recovery, even where spending aligns with approved Wildfire Mitigation Plans, with no presumption that plan compliance alone establishes reasonableness. The PD explicitly applies the prudent manager standard based on what PG&E knew or should have known at the time (not in hindsight) finding that contemporaneous evidence of program ineffectiveness triggered an obligation to reevaluate spending that PG&E failed to satisfy.

In short, the Commission appears more willing to approve costs incurred after system stress or failure than costs incurred to prevent it, where preventive spending is subjected to intensive, retrospective review. For utilities, the message is straightforward: future wildfire-related recovery will be evaluated based on execution quality, documentation, and cost discipline, not program scale or urgency.

SOCALGAS DISTRIBUTION INTEGRITY MANAGEMENT

A proposed decision in A.25-08-008 grants SoCalGas partial interim rate recovery for costs recorded in its Distribution Integrity Management Program Balancing Account between 2019 and 2023.

The PD authorizes SoCalGas to recover $35.5 million on an interim basis, representing 60% of the $59.1 million requested, for a 12-month period, subject to refund with interest pending a final reasonableness determination. The PD finds that interim recovery is warranted because it:

• Produces direct interest savings for ratepayers (approximately $918,000);
• Promotes intergenerational equity by aligning cost recovery more closely with when costs were incurred; and
• Helps preserve SoCalGas’ financial integrity following a recent credit-rating downgrade, which can indirectly reduce future capital costs.

At the same time, the PD rejects SoCalGas’ request for 85% interim recovery, concluding that a lower percentage better balances ratepayer affordability concerns (particularly in light of recent gas rate increases) while still achieving the public-interest benefits of interim relief. Recovery would be implemented through a Tier 1 advice letter using the Equal Percent of Authorized Margin cost-allocation methodology.

For illustrative rates related to SoCalGas's work, see our summary here.

Interim Rate Relief; Physical Risk

Interim ratemaking, operational outages, and long-dated infrastructure commitments are reshaping cost exposure across California

CALIFORNIA REGULATORY INTELLIGENCEMC

INSTANT ANALYSIS: This PD reflects a Commission approach that permits limited interim recovery when doing so lowers financing costs and supports utility credit metrics, while declining to grant the full amount requested. By authorizing 60% of SoCalGas’ request, the PD emphasizes rate moderation and affordability in light of recent General Rate Case increases, particularly for disadvantaged customers, even as it accepts that deferring recovery would raise interest costs ultimately borne by ratepayers.

The PD also clarifies that the Sempra Utilities' 2024 GRC decision (D.24-12-074) does not foreclose interim recovery for earlier DIMP costs, maintaining a path for utilities to seek near-term relief outside a GRC when costs were not ripe at filing. For large gas customers, the practical takeaway is procedural: interim recovery remains available but will be sized conservatively, tied to refund protections, and constrained by explicit affordability considerations.

CLEAN ENERGY/SOUTHERN CALIFORNIA EDISON

Draft Resolution E-5445 approves SCE's request to enter into ten clean energy resource contracts resulting from its 2024 Clean Energy Request for Offers. The draft resolution authorizes a portfolio totaling 2,093 MW of nameplate capacity across four projects, including large single-axis solar PV facilities and paired, co-located four-hour lithium-ion battery storage systems in California and Nevada.

The contracts are intended to help SCE meet its Integrated Resource Planning obligations under a 2024 decision (D.24-02-047) and its Renewables Portfolio Standard requirements, with solar deliveries beginning between 2027 and 2029 and contract terms ranging from 15 to 20 years.

Energy Division found that SCE’s solicitation and least-cost, best-fit evaluation process was fair and reasonable, relied on independent evaluator oversight, and produced contracts that are consistent with SCE’s 2024 RPS Procurement Plan and long-term greenhouse gas reduction targets.

The draft resolution authorizes full cost recovery of contract and administrative costs through SCE’s Portfolio Allocation Balancing Account. It allows limited flexibility to count the resources toward mid-term reliability requirements if needed, but rejects SCE’s request to pre-authorize cost recovery related to separate interconnection process enhancement solicitations.

INSTANT ANALYSIS: This draft resolution continues the Commission’s steady pattern of approving large, utility-led solar and paired storage portfolios to backfill long-term IRP needs identified in D.24-02-047, with little controversy and no protests. The scale is significant: over 2,000 MW of nameplate capacity approved in a single advice letter, reinforcing SCE’s reliance on utility-scale solar plus four-hour storage as the default compliance pathway for both IRP and RPS obligations.

For ratepayers, the near-term cost exposure is opaque because contract prices remain confidential, but the Commission’s approval of full PABA cost recovery and vintage allocation confirms these resources will flow through bundled and departing-load customer charges beginning in the late-2020s.

The draft resolution also draws a clear boundary around cost recovery authority, approving recovery for the clean energy contracts themselves while rejecting SCE’s attempt to roll unrelated interconnection-process costs into the same resolution. This conveys that procurement approvals will not automatically open the door to adjacent administrative cost mechanisms.

UNION ISLAND PIPELINE

A proposed decision, which has been bounced repeatedly from consideration at recent CPUC voting meetings, denies a request of California Resources Production Corporation (CRPC) for a Certificate of Public Convenience and Necessity (CPCN) to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. The PD concludes that the company no longer holds valid franchise rights in Antioch and Brentwood and ceased transporting gas in 2023.

• The PD concludes further that ongoing litigation over alleged pipeline abandonment means CRPC cannot demonstrate clear ownership or operational control of the full line, preventing it from dedicating the system to public use.
• The PD rejects CRPC’s attempt to substitute a subsidiary and denies the cities’ request for a procedural pause, though it grants CRPC’s motion to keep financial records sealed for three years.

INSTANT ANALYSIS: This PD resolves the application on threshold jurisdictional grounds and avoids reaching broader policy questions about the role of statewide regulation where local franchise authority has lapsed or been denied. By grounding the denial in present-tense statutory requirements under the Public Utilities Code, the PD treats the absence of current operating rights as dispositive and declines to evaluate system value or public-interest considerations.

The PD also clarifies that CPCN authority does not operate as a mechanism to cure unresolved local franchise disputes. In practice, this approach places primary weight on settled legal control of facilities before public-utility status can attach, reinforcing a sequence in which municipal authorization precedes Commission oversight. The result is a narrower, process-oriented interpretation of the Commission’s role that limits its involvement in infrastructure assets facing active local and judicial uncertainty.

CRUDE OIL TRANSPORTATION

Draft Resolution O-0098 approves emergency interim rate relief for Crimson Pipeline's SPB-KLM system. The resolution approves an interim rate increase effective August 1, 2025, with authority to allow retroactive collection subject to refund.

The draft resolution:

• Finds that sustained volume declines (from approximately 100 kbpd in 2021 to under 30 kbpd by late 2025, including zero nominations for December 2025) justify interim action to prevent suspension of pipeline operations. Crimson stated it "lacks sufficient cash on hand, does not have access to debt financing, and cannot secure additional capital from its owner to sustain operations."
• Rejects an argument advanced by Chevron and Valero that the Public Utilities Code limits CPUC authority to approve increases above 10%. The draft resolution clarifies that the statutory cap constrains only what utilities may implement unilaterally, not what the CPUC may authorize.

As a condition of approval, Crimson must secure a letter of credit to protect shipper refunds. Final rate determinations remain with the pending General Rate Case (A.25-01-009).

INSTANT ANALYSIS: Draft Resolution O-0098 reflects the Commission's willingness to use interim ratemaking to preserve critical infrastructure when volume collapse threatens operational continuity. The SPB-KLM system is the primary pipeline connecting crude oil from the Central Valley to Northern California refineries, giving the system strategic importance beyond its current throughput, and one of only a limited number of pipelines capable of moving Central Valley crude out of basin. The draft resolution prioritizes near-term system availability over rate stability, while deferring cost scrutiny and final rate reasonableness to the pending GRC (treating emergency relief as a temporary bridge rather than a final judgment).

Separately, Draft Resolution O-0099 approves Phillips 66 Pipeline LLC's request to withdraw utility service on crude oil pipeline Lines 100, 200, 300, and 400 and to cancel its tariff, marking Phillips 66's complete exit from California crude pipeline utility operations and concluding an uncontested Tier 3 advice letter process.

The draft resolution finds that, following the closure of the Santa Maria Refinery and the conversion of the Rodeo Refinery to a renewable fuels facility, the pipeline system no longer serves a useful purpose, and all former producers have secured alternative transportation.

Safety oversight remains exclusively with the Office of the State Fire Marshal, which has granted Phillips 66 a deferment of certain maintenance, inspection, and testing requirements. Phillips 66 must still comply with all applicable state and federal regulations for idled lines. The draft resolution does not authorize or address cost recovery, noting there are no ratepayers using the lines and that any remaining maintenance costs will be borne entirely by Phillips 66.

INSTANT ANALYSIS: Draft Resolution O-0099 formalizes the end of Phillips 66's crude pipeline utility operations in California – not a partial system withdrawal, but a complete exit from the business. The draft resolution reflects demand loss rather than a safety or cost dispute, tying directly to the Santa Maria refinery closure and the Rodeo conversion to renewable fuels. There is no rate exposure, no cost allocation, and no downstream precedent risk for other pipeline utilities, as the draft resolution explicitly avoids approving any costs and leaves all residual obligations with Phillips 66. From a market perspective, the draft resolution closes the book on a legacy crude transport corridor and reinforces the direction of travel for refinery-linked infrastructure in California: once refining demand disappears, utility status follows.