FRIDAY AGGREGATE: New Climate Credit Timing; SCE Dynamic Pricing Delayed

Today's report includes:

• A new PD in the CPUC's Climate Credit rulemaking directing immediate interim changes to the state's Climate Credit program;
• A new ALJ ruling indicating that the Commission is not ready to approve SCE's Large Power Dynamic Pricing framework;
• A two-month, emergency SoCalGas curtailment on its North Valley System;
• SoCalGas's renewal of interstate pipeline capacity contracts with Transwestern Pipeline Company; and
• A PD approving Crimson California Pipeline L.P.’s request for a 10% rate increase on crude-oil transportation across its Southern California pipeline system.

CLIMATE CREDIT

CPUC President John Reynolds issued a proposed decision in R.25-07-013 directing immediate, interim changes to California's residential Climate Credit program to improve bill affordability, primarily by shifting when credits are delivered rather than altering their size or eligibility.

Historically, these credits (funded by Cap-and-Invest allowance revenues) were issued in low-usage months (spring and fall), but the CPUC now finds that approach misaligned with affordability needs.

• For 2026, large electric utilities (PG&E, SCE, SDG&E) are ordered to move electric bill credits to August and September, when usage and bills are highest. Small and multi-jurisdictional utilities (Bear Valley, Liberty, PacifiCorp) will shift their remaining 2026 credit to November to match winter peaks, then distribute in October and November beginning in 2027.
• Natural gas credits will move to February beginning in 2027; the April 2026 gas credit already went out and could not be redirected, given timing constraints.
• The PD emphasizes speed and feasibility, adopting only timing changes that utilities can implement immediately, while deferring more complex reforms (e.g., eligibility changes, credit recalculation, baseline territory-level distribution) to Phase 1B.
• In parallel, the PD implements statutory requirements under Assembly Bill 1207 by directing electric utilities to remit 5% of Cap-and-Invest allowance auction revenues to the State Treasury for deposit in the California Transmission Accelerator Revolving Fund. Remittances are due within 15 days of final receipt of revenues from each auction, covering auctions held between July 1, 2026 and July 1, 2031.
• The PD updates Template D-1 within the utilities' Greenhouse Gas Revenue and Reconciliation Application Form, requiring standardized reporting on remittances through existing ERRA compliance, the Energy Cost Adjustment Clause, or advice-letter filings.
• The PD also requires limited updates to customer outreach (primarily clarifying bill savings and attributing them to the Cap-and-Invest program) while avoiding expanded messaging that could reduce available credit funds.

All changes are explicitly designated as interim, preserving flexibility for broader program redesign in subsequent phases of the rulemaking. The earliest the CPUC will consider this item is April 30. Comments are due April 15.

INSTANT ANALYSIS: If adopted, this PD would shift Climate Credits into peak months, lowering summer and winter bills without increasing total value. It's a timing change, not new relief. The bigger move is upstream: AB 1207 requires 5% of allowance auction revenues to flow to the Transmission Accelerator Fund, reducing the pool available for bill credits. The CPUC is implementing a legislative mandate, not making a discretionary policy choice, but the effect is the same. Climate funds are starting to split between direct ratepayer relief and grid infrastructure buildout. Utilities get a simple, workable change on credit timing. Affordability reforms are deferred.

DYNAMIC PRICING

A new ALJ ruling modifies the procedural schedule for SCE's Large Power Dynamic Pricing proceeding and its related standard dynamic rate application. The ruling adds a supplemental testimony phase to address unresolved design and implementation questions. SCE must submit supplemental testimony by April 24, with rebuttal testimony due May 26.

• The ruling focuses heavily on clarifying how SCE's proposed dynamic pricing structure will function across customer classes, particularly the role of subscription-based pricing versus alternatives like bill limiters for small and medium customers.
• A recurring threshold in the ruling is 500 kW of monthly demand, which surfaces as a potential dividing line for whether subscriptions should be mandatory or optional. Customers below that level may face a different protection framework than large power customers above it.
• The ruling directs SCE to analyze customer protection mechanisms, revenue neutrality, billing complexity, and implementation cost impacts under different design choices, including whether subscriptions should be required at all for residential and small/medium commercial classes.
• Additional questions probe how subscriptions should be updated over time, including the long-term bill impacts of annually recalculated versus static subscriptions for battery storage customers on TOU-8-SEC.
• The ruling also asks how SCE will maintain revenue recovery under its proposed rate design, and whether a per-customer monthly charge could replace the flat volumetric charge SCE proposed to recover Equal Percentage of Marginal Cost-scaled customer revenues.
• Other questions address system-wide versus locational distribution pricing, the appropriate venue for reasonableness review of implementation costs, and whether SCE's current dynamic rate pilots (set to expire December 31, 2027) need to be extended.

INSTANT ANALYSIS: The CPUC is not ready to approve SCE's dynamic pricing framework and is forcing a deeper vetting of its mechanics before moving forward. The focus on subscriptions versus bill limiters, revenue recovery, and implementation cost indicates concern that the current design may be too complex for smaller customers and may not produce stable or predictable outcomes across classes.

The CPUC is also testing whether SCE has over-engineered the rate. By asking for quantified cost and timeline reductions under simpler alternatives (including dropping subscriptions entirely for non-Large Power Dynamic Rate customers and adopting system-wide rather than locational distribution pricing), it's creating a pathway to scale back the proposal if needed. That puts pressure on SCE to justify not just the economics, but the operational burden of its design.

What SCE shows on bill impacts, revenue neutrality, and customer protection will likely determine whether its framework proceeds as a broad tariff, a narrowed product limited to large customers above the 500 kW threshold, or a more incremental pilot extension past 2027.

NATURAL GAS CURTAILMENT

SoCalGas submitted Advice Letter 6614-G (available here) to notify the CPUC of an emergency localized curtailment on its North Valley system that lasted from January 9 to March 18. The curtailment was initiated to facilitate repairs on a natural gas pipeline and resulted in a full interruption of service to affected noncore customers during that period.

SoCalGas says the curtailment was conducted in accordance with its tariff rules governing emergency service interruptions and that customers were notified through account managers and postings on its ENVOY system. Pipeline repairs remain ongoing.

INSTANT ANALYSIS: A localized curtailment lasting over two months points to real constraints in the North Valley system, not routine operations. Noncore customers absorbed the impact, which means large-load exposure to infrastructure bottlenecks remains active. Service has resumed, but the underlying condition has not fully cleared. Repairs are still ongoing, and this event shows how long disruptions can persist once triggered. For operators, this is a reminder that localized pipeline issues can translate into extended service disruptions, even without a systemwide emergency. Reliability risk in constrained zones is real, and it can last longer than expected.

INTERSTATE NG PIPELINE CAPACITY

SoCalGas submitted Advice Letter 6615-G (available here) requesting expedited CPUC approval of two renewed interstate pipeline capacity contracts with Transwestern Pipeline Company.

The filing relies on the expedited advice letter process established in a 2004 decision (D.04-09-022), which permits streamlined approval when supported by Cal Advocates and TURN. Cal Advocates participated in the Capacity Consulting Group meeting and has indicated support. TURN did not participate in the review process. The contract terms are confidential due to market-sensitive content.

INSTANT ANALYSIS: SoCalGas is maintaining interstate transport optionality into the L.A. Basin through Transwestern, with no visible change to procurement posture or tariff structure. What's worth noting here is that – even amid ongoing volatility around pipeline outages, storage constraints, and peak-day reliability concerns – SoCalGas is renewing upstream capacity rather than pulling back or reallocating exposure. Interstate capacity remains a solid reliability hedge, and there is no near-term shift toward reduced dependence on out-of-state supply corridors.

CRUDE OIL TRANSPORTATION

The CPUC issued a proposed decision approving Crimson California Pipeline L.P.’s request for a 10% rate increase on crude-oil transportation across its Southern California pipeline system, effective August 1, 2025. Crimson operates 300 miles of common-carrier crude oil pipeline connecting production fields to L.A. Basin refineries.

The PD also authorizes retroactive collection of the difference between rates billed and the approved rates from that date forward, with interest at the 90-day commercial paper rate.

The rate burden falls on commercial oil company shippers rather than end-use ratepayers. Crimson's Test-Year return on equity lands at 10.82% with the increase applied. The PD denies Crimson's separate attempt to tack on an additional 3.16% increase on procedural grounds.

The earliest the CPUC will consider this item is May 14. Comments are due April 15.

INSTANT ANALYSIS: This is a straightforward validation of the self-executing 10% increase mechanism under the Public Utilities Code. The rejection of the 3.16% add-on is the only other action worth highlighting – the CPUC won't let applicants bootstrap additional rate relief through filings that amount to substantive amendments submitted after the scoping memo.