WEDNESDAY AGGREGATE: CPUC Moves to Enforce Energization Timelines; SDG&E Challenges EE Model; PG&E Exits Ruby Capacity

Today's regulatory roundup looks at:

• Enforcement tools the CPUC is developing for energization timelines;
• A holistic build sequence for DER orchestration;
• A Line 225 force majeure event on SoCalGas's system;
• PG&E's exit from contracted NG capacity with Ruby Pipeline;
• New IOU energy-efficiency business plan applications;
• SDG&E's request for borrowing authority before its next capital cycle; and
• A PG&E Corporation joint venture with Lockheed Martin, et al.

SDG&E's energy-efficiency submission is notable because it asks the CPUC to reject the filing and adopt a separate, pending request (A.25-04-014) that would significantly scale back its EE programs.

ENERGIZATION

CPUC President John Reynolds issued an amended Phase 2 scoping memo in the Commission's Timely Energization rulemaking (R.24-01-018), expanding the proceeding beyond the timeline-setting work completed in a 2024 decision (D.24-09-020) and into enforcement, auditing, and process improvement.

The new scoped issues fall into four categories.

• First, the CPUC is asking how it should enforce compliance with previously adopted energization targets under the Public Utilities Code:
  • What triggers remedial action;
  • What remedial actions are appropriate;
  • How compliance with those orders should be monitored; and
  • Whether the existing Enforcement Policy (Resolution M-4846) satisfies Senate Bill 254's requirement for an enforcement policy "that includes penalties" or whether additional measures are needed.
• Second, the ruling scopes auditor selection and implementation under SB 254, which requires utilities to retain third-party auditors to review energization planning and business processes. PG&E and SDG&E already have auditors in place under SB 410, so coordination between the two audit tracks is a live issue. The scoping memo asks whether large investor-owned utilities should jointly retain a single SB 254 auditor, how audit costs should be treated for ratemaking (notably, SB 410 prohibits ratepayer funding while SB 254 is silent) and what role nonbinding auditor recommendations should play.
• Third, the Commission asks whether it should take steps to implement the reporting requirements of the Public Utilities Code.
• Fourth, the ruling invites comment on whether energization processes should be further standardized across utilities and whether additional actions beyond SB 410 and Assembly Bill 50 are warranted to improve timelines.

INSTANT ANALYSIS: This phase marks the transition from setting energization timelines to building the machinery to enforce them. The most consequential fights will be over audit design (joint vs. separate auditors, shareholder vs. ratepayer cost allocation, and whether nonbinding recommendations acquire binding force through Commission action).

The enforcement policy question is equally significant: whether Resolution M-4846 is adequate or whether the CPUC constructs something new will shape penalty exposure for years. In the background, SB 254 requires the Commission to report to the legislature by January 1, 2027, on whether to tie executive compensation to energization performance. The latter is not yet a scoped issue, but a sign of where legislative pressure is heading.

DISTRIBUTED ENERGY RESOURCES

Commissioner Darcie Houck's March 23 ruling in the High DER Future docket (R.21-06-017) moves Track 2 from a workshop phase into a structured build sequence for DER orchestration.

Under this approach, PG&E, SCE, and SDG&E would each file formal applications to develop Distribution System Operator-led orchestration frameworks, preceded by two CPUC-led workshops (the first on the application process itself, the second on DER visibility to the CAISO and Transmission System Operator-Distribution System Operator coordination).

The ruling identifies five priority operational areas from the Gridworks Future Grid Study:

• DER visibility to the Distribution System Operator;
• DER visibility to the CAISO;
• Dispatchability/control;
• Open access to the distribution system; and
• Reliability coordination at the transmission-distribution interface.

Rather than treating these items separately, the ruling proposes a holistic framework in which utilities use real-time data, forecasting, and control signals to align DER output with grid needs (explicitly framed as targeted signaling, not full command-and-control).

The ruling contains seventeen stakeholder questions, which cover objectives, valuation, guiding principles, phased implementation, aggregator participation, ADMS/DERMS investment, interoperability, and real-time pricing compatibility. The ruling also asks whether Integration Capacity Analysis quarterly workshops should shift to biannual cadence and proposes a standardized template for biennial grid modernization reporting.

Comments are due April 13, with replies due April 20. Workshop presentations must be served by April 22 (the first workshop, addressing the application process, is April 29. The second workshop, addressing Transmission System Operator/Distribution System Operator/CAISO coordination, is TBD.)

INSTANT ANALYSIS: The sleeper provision is Question 6 (whether IOUs should propose a shared savings mechanism allowing them to share in net cost savings when DER solutions displace traditional infrastructure). If adopted, that fundamentally realigns utility incentives away from capital deployment. The other critical variable is what "open access" actually means once utilities control the orchestration layer.

The ruling lists this as a guiding principle, but operational definitions (eligibility, data flows, participation pathways) will be set in the application phase. Aggregators and third-party providers should watch Questions 15-17, which address aggregator coordination and performance standards, additional technology investments required for orchestration, and whether those capabilities should be customer-owned or utility-owned.

SOCALGAS SYSTEM RELIABILITY

SoCalGas reports on Envoy that it is continuing to respond to a force majeure event on Line 225 near the I-5 corridor in Castaic. A geotechnical assessment of the affected area is complete and engineers are designing a repair plan. Construction is expected to begin in May 2026 and will take multiple months, with timelines subject to adjustment.

Separately, SoCalGas will conduct safety checks and a required pressure test on a different section of Line 225 in Castaic between March and May 2026. The company states this work will not interfere with the repair schedule.

INSTANT ANALYSIS: Line 225 is a major transmission artery feeding the LA Basin, which means a force majeure with a multi-month construction window is not a short-duration outage, it is a sustained reliability challenge on a consequential segment.

SoCalGas has not announced blanket capacity reductions, but it is already directing customers to the Envoy Capacity Utilization page for cycle-by-cycle available capacity. That language suggests variability is present now, and is not hypothetical. The overlap of repair construction and pressure testing on different sections of the same pipeline in the same corridor compounds operational risk, even if SoCalGas says the two work scopes are independent.

This is early-stage, but the escalation path is legible: any constraints on scheduling flexibility move this into SoCal Citygate price exposure and curtailment risk for noncore loads.

PG&E NATURAL GAS CAPACITY

PG&E filed Advice Letter 5190-G, notifying the CPUC that it will not renew any portion of its contracted capacity on the Ruby Pipeline when the amended contract expires October 31.

The filing follows the procedure established in a 2021 decision (D.21-12-035), which requires PG&E to first consult with the Core Gas Supply Stakeholder Group (Cal Advocates, the CPUC's Energy and Legal Divisions, and TURN) before filing a Tier 1 advice letter with the Commission. PG&E completed the stakeholder consultation on March 11. Protests are due April 13.

INSTANT ANALYSIS: This is a full exit from a legacy interstate pipeline position. PG&E will not retain even a partial capacity commitment beyond October. No replacement procurement strategy is disclosed in the filing. The advice letter includes standard Tier 1 language representing no rate impact, no service withdrawal, and no tariff conflict, which tells you PG&E views the capacity as surplus to current needs.

The longer-term questions are significant: how does PG&E reconstitute its supply stack without Ruby capacity, what does that mean for winter reliability and basis risk, and does this accelerate reliance on storage and spot market procurement? The move is consistent with declining gas demand forecasts and growing political pressure on long-duration pipeline commitments in California, but it shifts risk from fixed-term contract obligations to market exposure.

ENERGY EFFICIENCY

PG&E, SCE, SDG&E, and SoCalGas all filed applications for eight-year energy-efficiency business plans (2028-2035) paired with four-year portfolio plans (2028–2031).

• PG&E and SoCalGas present relatively conventional, growth-oriented filings that lean into the CPUC’s Total System Benefit framework and long-term decarbonization trajectory, proposing large multi-billion-dollar portfolios ($1.78 billion for PG&E; about $1.25 billion for SoCalGas, excluding Regional Energy Networks) with an emphasis on building electrification, load flexibility, and market transformation.
• SCE takes a more constrained approach, explicitly aligning with state affordability directives by proposing a materially downsized portfolio (about $997 million for 2028–2031, a 40% reduction from the prior cycle). However, Edison still targets strong performance metrics (Total System Benefit above goals and improved Total Resource Cost), and pairs that with a set of policy reforms to reduce administrative burden, loosen third-party requirements, and improve cost discipline.
• SDG&E is the outlier. It submitted a compliant EE plan (about $565 million, or $1 billion including the San Diego Regional Energy Network). However, SDG&E is not actually asking the CPUC to approve it. Instead, SDG&E is urging the CPUC to reject its filing and adopt a separate, pending application (A.25-04-014) that would significantly scale back its EE programs or exit regional administration altogether, citing affordability concerns and past underperformance.

INSTANT ANALYSIS: These filings fall into two camps: PG&E and SoCalGas are pushing full-scale EE investment, SCE is trimming within the model, and SDG&E is challenging the model itself. SDG&E’s request to reject its own filing in favor of a lower-cost alternative introduces a real off-ramp. That raises precedent risk and gives the Commission a path to reset EE spending. The CPUC's response will determine whether EE continues as a large, systemwide investment or shifts toward a constrained, performance-driven model.

UTILITY FINANCES

In a new filing at the CPUC, SDG&E requests $2.583 billion in new long-term debt authority and $1.348 billion in rollover authority to fund capital investments through 2029. Existing authorization from a 2022 decision (D.22-12-011) is nearly used up: only about $167 million in unused new-debt authority will remain after planned 2026 issuances. On the other side, SDG&E forecasts $2.75 billion in new debt needs and $1.35 billion in maturing bonds to refinance.

The capital program is driven by wildfire safety and grid hardening, EV infrastructure, energy storage, grid modernization, and gas system integrity. These investments were largely approved in the Test-Year 2024 General Rate Case decision (D.24-12-074), or anticipated in future filings.

SDG&E requests the same financing toolkit and hedging authority approved in D.22-12-011. That includes the full range of secured and unsecured instruments, foreign market access, tax-exempt debt, variable-rate structures, and derivative-based hedging.

A concurrent motion seeks to seal six financial schedules containing forward-looking construction, cash flow, and capitalization data.

INSTANT ANALYSIS: SDG&E is securing the borrowing authority it needs ahead of a heavy 2027–2029 capital cycle. The $3.9 billion combined request is driven by wildfire mitigation, grid hardening, and electrification investment that has already been approved, or is expected to be approved. The financing toolkit gives SDG&E flexibility on timing and cost, but also leaves room for how debt costs ultimately flow into rates.

WILDFIRES

PG&E filed Advice Letter 5189-G/7864-E, notifying the CPUC of a new affiliate relationship with EmberPoint LLC. EmberPoint is a joint venture between Lockheed Martin Evolve LLC, PG&E Corporation, Salesforce, and Wells Fargo focused on developing next-generation wildfire mitigation solutions. PG&E Corporation acquired its interest on January 23, via a Simple Agreement for Future Equity funded by shareholders.

Although EmberPoint's business purpose does not directly relate to gas or electric service, PG&E is treating it as an affiliate under both Rule I.A and Rule II.B of the Affiliate Transaction Rules (the latter explicitly described as an abundance-of-caution measure) and will apply its existing 2025 compliance plan to all transactions with the entity.

INSTANT ANALYSIS: The Rule II.B designation is the key move here. PG&E didn't have to apply the full affiliate transaction restrictions to a holding-company-level investment in a venture with no direct utility nexus, but chose to anyway. That's a sign the company is already thinking about how wildfire mitigation spending, data access, and procurement could raise cross-subsidy or preferential treatment questions.