February 5, 2026 CPUC Voting Meeting Results: Commission Clears Path for Immediate Energization Under New Flexible Service Connection Rules

The CPUC's February 5 voting meeting authorized several notable decisions.

First and foremost, the Commission adopted a decision in the Energization rulemaking (R.24-01-018) that directs PG&E and SCE to establish a standardized, tariffed “Standard Offer” Flexible Service Connection to accelerate energization for customers facing distribution capacity constraints.

"A flexible service connection allows customers waiting for an upgrade to use power in the interim when it is safe to do so," said Commissioner Darcie Houck from the dais. "This tool allows investor-owned utilities to connect customers to the grid while limiting energy use during constrained periods and while grid upgrades proceed in a more cost-effective manner."

The Commission also adopted the following items.

• Wildfire Cost Recovery: A decision granting partial approval of PG&E’s request to recover recorded costs related to wildfire mitigation, vegetation management, catastrophic events, and several customer- and policy-driven programs, primarily incurred in 2022. The decision authorizes recovery of $1.607 billion in revenue requirement, largely reflecting wildfire mitigation activities, emergency storm response, and compliance with Commission-mandated programs, while denying $172.5 million in vegetation management costs after a reasonableness review.
• SoCalGas Distribution Integrity Management Costs: A decision partially granting SoCalGas interim recovery of costs recorded in its Distribution Integrity Management Program Balancing Account for the 2019–2023 period. The decision authorizes $35.5 million, equal to 60% of a $59.1 million request, to be recovered over a 12-month period through interim rates.
• Clean Energy Contracts: Resolution E-5445, which approves SCE’s request to enter into 10 clean energy contracts resulting from its 2024 Clean Energy Request for Offers. The approved portfolio totals 2,093 MW of nameplate capacity across 10 contracts and four projects.
• Union Island Pipeline: A decision dismissing without prejudice California Resources Production Corporation's application seeking a Certificate of Public Convenience and Necessity to operate the Union Island natural gas pipeline as a public utility.
• Crude Oil Transportation: Resolution O-0098, which approves San Pablo Bay Pipeline Company and Crimson California Pipeline’s request for emergency, interim rate relief on the SPB-KLM intrastate crude oil pipeline system. And separately, Resolution O-0099 which 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.

More detail is available below.

ENERGIZATION

A decision in R.24-01-018 directs PG&E and SCE to establish a standardized, tariffed “Standard Offer” Flexible Service Connection to accelerate energization for customers facing distribution capacity constraints. SDG&E and small multi-jurisdictional utilities are not required to participate at this time.

The decision formalizes existing utility practices (particularly PG&E’s Load Limiting Letter model) into a uniform option that allows customers to receive firm, limited capacity under predefined load profiles while awaiting upstream upgrades.

PG&E and SCE must file:

• A joint Tier 2 advice letter within 60 days implementing the standard offer;
• A Tier 1 advice letter within 15 days updating tariff rules; and
• A Tier 2 advice letter within 75 days formalizing preliminary capacity assessments.

SCE must file a report on its Load Control Management Study pilot learnings by March 1, 2026. Both utilities must collect detailed data to evaluate cost efficiency and file a report by January 15, 2029.

The Flexible Service Connection is positioned strictly as a temporary bridging solution for individual customers, does not alter energization queue positions, and prioritizes speed, safety, and scalability through a "trust-and-verify" approach rather than prescriptive control systems. Load profiles must include a minimum of six values (three seasons with two daily capacity values each), and load behind UL 3141-certified power control systems receives safe harbor treatment that excludes it from connected load calculations.

"It’s considered a bridging solution," President Alice Reynolds said from the dais, "because the limits are temporary and may be removed after grid infrastructure is in place. In the case of flexible service connections, utilities can serve new customers with little or no near-term investment, and this approach can help manage and even lower costs for ratepayers."

Below are some additional comments from the dais.

• Commissioner Darcie Houck: "In the High DER proceeding, we are assessing longer-term feasibility of flexible service connections for non-firm capacity, including utility and customer-side equipment, technical standards, scalability, performance, and reliability. The flexible service connections established here will be foundational to that longer-term work."
• Commissioner John Reynolds: "One of our high-level goals should be timely energization and electrification. To do this, we need to adjust our regulatory framework to encourage energization and load growth. This goal is fundamental and urgent. We cannot afford to wait for every distribution upgrade, especially when the distribution revenue requirement of IOUs has more than doubled since 2016. We must maximize the value of existing assets—and do so safely. This decision should have a positive effect on affordability by facilitating energy sales sooner than would occur if we waited for upgrades. The revisions made to the decision have also been very helpful."
• Commissioner Karen Douglas: "We have heard repeatedly from customers who are unhappy with rising bills. One way we manage affordability is by promoting efficient utility management. Another is promoting efficient use of the grid — which this decision does. In California, when a utility sells more energy, it does not make more money. More sales can lead to lower rates. Flexible service connections increase sales by allowing customers to purchase more energy on existing infrastructure. These connections are short- to medium-term solutions. Typically, they remain in place for about three years before infrastructure upgrades are built. During that window, sales increase before the flexible connection sunsets and upgrades proceed."

INSTANT ANALYSIS: This decision moves Flexible Service Connections from pilots and one-off arrangements into a standard, tariffed option at PG&E and SCE for customers blocked by local grid limits. Instead of waiting years for upgrades, customers can take partial power sooner by agreeing to stay within defined load limits while the utility completes the required upgrade work. The Commission is favoring this practical stopgap over delay, particularly as electrification drives load growth that exceeds existing distribution capacity.

For utilities and ratepayers, the goal is providing capacity faster through operational flexibility rather than waiting on infrastructure construction timelines. For customers, the tradeoff is responsibility: they must actively manage their load and stay within approved limits, or face curtailment and potential liability. The required tracking and reporting will inform future refinements to what is already a proven approach, with adjustments likely once broader deployment generates real-world data beyond PG&E's existing 100+ Load Limiting Letter customers.

PG&E WILDFIRE COST RECOVERY

A decision grants partial approval of PG&E’s request to recover recorded costs related to wildfire mitigation, vegetation management, catastrophic events, and several customer- and policy-driven programs, primarily incurred in 2022.

The decision authorizes recovery of $1.607 billion in revenue requirement, largely reflecting wildfire mitigation activities, emergency storm response, and compliance with Commission-mandated programs, while denying $172.5 million in vegetation management costs after a reasonableness review.

Most disputed costs (covering wildfire mitigation, catastrophic event response, climate adaptation, microgrids, customer protections, and related memorandum accounts) are resolved through an uncontested settlement among PG&E, Cal Advocates, TURN, and the Small Business Utility Advocates, which the Commission finds reasonable and in the public interest.

Under the decision, PG&E must file an advice letter to implement recovery, net of amounts already collected under prior interim rate relief, with remaining balances amortized beginning in 2026.

INSTANT ANALYSIS: The decision approves PG&E’s 2022 wildfire and catastrophic-event cost recovery, with most disputed amounts resolved through an uncontested settlement. The decision authorizes recovery of about $1.6 billion, reflecting continued deference to wildfire mitigation, storm response, and customer-protection spending when costs are tied to authorized programs and supported by the record.

The denial of $172.5 million in vegetation management costs shows that Vegetation Management Balancing Account spending is not automatically recoverable. The disallowance has two components:

• $10 million for above-compliance work performed at customer request; and
• $162.45 million for Enhanced Vegetation Management costs incurred from October through December 2022 (after PG&E knew the program was not cost-effective and would be replaced).

Even work aligned with an approved Wildfire Mitigation Plan remains subject to detailed reasonableness review and potential disallowance. For ratepayers, the settlement reduces PG&E’s original request and brings procedural closure. For utilities, the takeaway is straightforward: settlements support recovery, while vegetation management continues to face the most scrutiny.

SOCALGAS – DISTRIBUTION INTEGRITY MANAGEMENT

A decision partially grants SoCalGas interim recovery of costs recorded in its Distribution Integrity Management Program Balancing Account for the 2019–2023 period.

The decision authorizes $35.5 million, equal to 60% of a $59.1 million request, to be recovered over a 12-month period through interim rates. All interim collections are subject to refund with interest, pending a final determination on the reasonableness of the costs.

The decision finds interim recovery appropriate to reduce accumulated interest expense, support intergenerational equity, and preserve the utility’s financial condition following a recent credit downgrade. It concludes that delaying recovery would increase financing costs borne by ratepayers and prolong pressure on SoCalGas’ credit metrics. These factors support immediate but limited relief, the decision finds.

The decision rejects SoCalGas’ request to recover 85% on an interim basis. It determines that a 60% authorization better balances ratepayer protection with utility needs, given recent rate increases and ongoing affordability concerns.

INSTANT ANALYSIS: The decision shows that interim recovery remains available outside a General Rate Case when utilities show concrete ratepayer benefits. Interest savings, intergenerational alignment, and credit pressure carried weight here, especially after a downgrade. For stakeholders, the key takeaway is calibration, not capitulation. The Commission was willing to act quickly, but only at a level that smooths rates and constrains exposure. A final outcome will require a detailed reasonableness review of the underlying Distribution Integrity Management Program Balancing Account costs.

SCE – CLEAN ENERGY CONTRACTS

Resolution E-5445 approves SCE’s request to enter into 10 clean energy contracts resulting from its 2024 Clean Energy Request for Offers.

The approved portfolio totals 2,093 MW of nameplate capacity across 10 contracts and four projects:

• Two co-located solar-plus-storage projects (Aratina II and Darden); and
• Two solar-only projects (Bonanza Peak and Lockhart IV)...

...with deliveries beginning between 2027 and 2029 and contract terms of 15 to 20 years. The solar contracts are expected to generate approximately 4,008 GWh annually and are intended to support SCE's Integrated Resource Plan and Renewables Portfolio Standard obligations.

Energy Division found the solicitation and least-cost, best-fit evaluation process to be fair and reasonable, with independent evaluator oversight and Procurement Review Group participation.

The resolution:

• Approves full cost recovery of contract and administrative costs through SCE’s Portfolio Allocation Balancing Account for applicable customers;
• Allows limited flexibility to count the resources toward mid-term reliability requirements if needed; but
• Rejects SCE's requests to pre-authorize cost treatment for future Integrated Resource Planning mandates and to recover costs related to a separate interconnection solicitation as out of scope and lacking sufficient information, though SCE may re-file separately.

INSTANT ANALYSIS: This resolution advances SCE’s near-term Integrated Resource Planning execution by committing to a large tranche of late-2020s solar and paired storage using already-vetted offers, rather than reopening a new solicitation cycle.

The Commission’s approval affirms the Clean Energy RFO as a workable bridge between mid-term reliability procurement and longer-horizon Integrated Resource Planning needs, while preserving flexibility to reclassify these resources if SCE later faces mid-term reliability shortfalls.

At the same time, the resolution establishes very specific parameters for cost recovery: SCE receives full recovery for the clean-energy contracts themselves, but the resolution declines to pre-approve cost treatment tied to future Integrated Resource Planning mandates or to fold in unrelated interconnection-solicitation mechanics.

For customers, this confirms that the cost exposure from these contracts is immediate, but with closer scrutiny of add-on procurement requests that attempt to travel alongside otherwise approvable clean-energy filings.

UNION ISLAND PIPELINE

A decision dismisses without prejudice California Resources Production Corporation's A.23-07-008 seeking a Certificate of Public Convenience and Necessity to operate the Union Island natural gas pipeline as a public utility.

The decision concludes the application is not ripe for consideration because:

• CRPC does not presently hold clear, undisputed rights to control, operate, or manage all segments of the pipeline (particularly within the Cities of Antioch and Brentwood); and
• Parallel judicial and local administrative proceedings remain unresolved. The decision emphasizes that Sections 216 and 222 of the Public Utilities Code use present-tense language ("owning, controlling, operating, or managing") that does not permit expired or speculative future status to satisfy the statutory criteria.

The outcome turns on two unresolved issues.

• First, ownership of the Antioch pipeline segment remains disputed in ongoing Phase II litigation, where Antioch seeks a determination that CRPC abandoned the pipeline upon franchise termination, potentially vesting ownership in the City.
• Second, CRPC lacks current franchise authority in both Antioch and Brentwood, with local franchise applications still pending or held in abeyance.

The decision denies the Cities' request to hold the case in abeyance, finding dismissal cleaner. It also denies CRPC's motion to substitute its subsidiary (to which CRPC transferred pipeline ownership in October 2024) as applicant, concluding the subsidiary faces identical deficiencies. The dismissal is without prejudice, allowing CRPC or its successor to re-file once ownership and franchise rights are resolved.

INSTANT ANALYSIS: This dismissal is procedural, but the message is substantive. CRPC filed its application hoping the Commission would grant public utility status conferring eminent domain authority (allowing the company to condemn municipal rights-of-way and bypass the Cities' franchise decisions entirely).

The Commission refused. By insisting on present-tense statutory language, the decision directs CRPC to resolve its property and franchise disputes through courts and local processes first. The main message from the Commission is this: it will not serve as an alternative forum when those negotiations fail. The Phase II litigation now becomes dispositive: if Antioch prevails on its abandonment theory, the pipeline may be permanently foreclosed from private operation.

CRUDE OIL TRANSPORTATION

Resolution O-0098 approves San Pablo Bay Pipeline Company and Crimson California Pipeline’s request for emergency, interim rate relief on the SPB-KLM intrastate crude oil pipeline system.

The resolution authorizes a 59.2% interim rate increase, raising the mainline tariff from $2.3571 to $3.7527 per barrel, effective August 1, 2025, subject to refund, and applies the same percentage increase to the Station 36–San Joaquin Refinery segment.

• The resolution finds that Crimson demonstrated sustained and severe throughput declines (including zero shipper nominations for December 2025) resulting in negative operating cash flow and an inability to continue operations absent immediate relief.
• Chevron Products Company and Valero Marketing and Supply Company protested, and PBF Holding Company, LLC filed reply comments in opposition, arguing that increases above 10% are impermissible without hearings and disputing the existence of an emergency. The resolution asserts statutory authority to grant interim relief above 10% and finds that resolving the matter through the advice-letter process is appropriate.
• The resolution emphasizes the public interest risks of a pipeline shutdown, including higher costs, increased trucking and marine transport, environmental and safety impacts, and reduced resilience in California's crude supply chain.
• An accompanying attachment notes that pipeline tariffs do not affect gasoline prices because California crude producers (not refiners) bear the transportation cost differential relative to competing southbound routes.

To protect ratepayers, the interim increase is subject to refund pending resolution of the ongoing general rate case, and Crimson must secure a $5.8 million letter of credit to ensure refund availability in the event of insolvency. The accompanying attachment reinforces the factual basis for emergency relief, documenting:

• Volume losses since early 2025;
• The pipeline’s high fixed-cost structure;
• The economic obsolescence risk posed by competing southbound pipelines; and
• Crimson’s unsuccessful efforts to settle its 2024 and 2025 rate cases at deeply discounted levels to stabilize operations.

INSTANT ANALYSIS: The Commission's approval of a 59.2% interim emergency rate increase for the San Pablo Bay Pipeline reflects how quickly collapsing crude volumes can destabilize fixed-cost energy infrastructure, even before a final rate determination.

By authorizing relief above the customary 10% threshold through an advice letter resolution (a procedural vehicle not previously used for oil pipeline emergency relief of this magnitude), Resolution O-0098 shows a readiness to intervene when continued operation of a single-asset system is at risk and broader supply-chain impacts are plausible.

At the same time, the resolution avoids prejudging Crimson's pending General Rate Cases: the increase is interim, subject to refund, and paired with a $5.8 million letter of credit to protect shippers if rates are later disallowed. For shippers and producers, the resolution increases near-term transportation costs but preserves optionality in a constrained crude logistics network.

For other pipeline operators and regulated infrastructure owners, the resolution establishes that system continuity can outweigh procedural ceilings when volume collapse threatens withdrawal of service.

Separately, 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 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 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: 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 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 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.