WEDNESDAY AGGREGATE: Cost Questions Intensify Across Storage, SB 1221, and Shared Renewables
Today's aggregate includes:
- More activity involving Senate Bill 1221 decarbonization pilots;
- Utility safety metric reports and energization reports;
- A PD establishing the statewide Shared Renewables Portfolio;
- SDG&E's cost-benefit report on the Advanced Energy Storage project; and
- A looming investigation into PG&E's Elkhorn Energy Storage System.
We will include a summary on the latter item in our full April 9 voting meeting report tomorrow afternoon (please see our meeting preview here).
MC
SENATE BILL 1221/DECARBONIZATION PILOTS
California's four major gas utilities filed compliance reports in the CPUC's Long-Term Gas Planning docket, documenting their virtual SB 1221 information sessions and stakeholder outreach pursuant to a decision last December (D.25-12-042). In sum, the reports reflect a mix of public resistance, information gaps, and in Southwest Gas's case, near-total indifference.
- SoCalGas and SDG&E held the most attended sessions and recorded the clearest opposition majorities: 29 of 38 commenters opposed SoCalGas; 25 of 34 opposed SDG&E.
- PG&E's session landed differently: its own sentiment analysis found the dominant tone was neutral and information-seeking rather than oppositional, with negative comments clustered around implementation concerns rather than outright rejection.
- Southwest Gas is the only utility that reported no tribal contacts, no load-serving entity contacts, and no expressed interest from any community organization.
Where opposition did register, it boiled down to:
- The electric grid cannot absorb the load;
- Public Safety Power Shutoff and wildfire outages make full electrification dangerous; and
- Gas provides resilience that electricity doesn't.
Several commenters characterized the SB 1221 program as a forced conversion softened by "pilot" language. Cost concerns were everywhere: appliance replacement, panel upgrades, rewiring, ongoing rate exposure.
Written comments in SDG&E’s appendix illustrate the cost pain: a fast-food franchisee estimating six-figure conversion costs per location, a solar homeowner facing higher electric bills without the ability to expand generation, and a resident unable to secure an electrical service upgrade.
On equity, feedback across all four sessions converged on the same issue. Low-income households, renters, seniors on fixed incomes, and medically vulnerable customers are the least equipped to absorb upfront conversion costs. The program’s stated equity rationale (targeting disadvantaged communities) runs directly into its operational constraint. The populations most targeted are the least able to comply.
The next phase of this proceeding will focus on program design: pilot structure, cost recovery, Priority Neighborhood Decarbonization Zone updates by December 31, and program requirements adoption by July 1.
INSTANT ANALYSIS: The July 1 program design deadline is what actually matters. Cost recovery (who pays, how stranded gas assets get treated, whether utilities earn on electrification capital) determines whether large users engage or ignore this proceeding. Right now they are waiting for cost-recovery design to tell them whether these developments are worth their attention.
SB 1221 requires 67% property owner consent before any pilot can be approved (a real constraint on deployment, but one whose mechanics haven't been designed yet). Priority Neighborhood Decarbonization Zone update criteria remain undefined. No utility recommended new census tracts with analytical confidence because the program details that would make such recommendations meaningful don't exist yet.
The equity problem is baked in. If pilots front-load costs onto residents in disadvantaged communities without robust bill protection and appliance replacement funding, the CPUC will have built something politically and legally vulnerable from Day 1. The public comment record says that in plain language. Whether the CPUC reads it that way is the question.
RISK-BASED DECISION-MAKING
California's major investor-owned utilities filed Safety Performance Metrics Reports under the CPUC's risk-based safety framework. The filings contain:
- 10 years of historical metric data where available;
- Narrative context linking metrics to operations;
- Explicit executive compensation ties;
- Bias control disclosures; and
- Documentation of how metrics feed RAMP and General Rate Case commitments.
The Sempra utilities cover different slices of the 32-metric framework. SDG&E reports on 29 metrics: the full set minus Metric No. 12 ("Natural Gas Storage Baseline Assessments"), which doesn't apply because SDG&E operates no storage facilities. SoCalGas reports on the 20 metrics applicable to a gas-only utility. Both filings emphasize multi-year trend narratives, safety management plan integration, workforce training, and public safety coordination, using metric outputs to document measurable safety improvements and satisfy RAMP and GRC process requirements.
SCE's filing ties specific metrics to corrective actions, contractor training and oversight, and continued deployment of its Safety Management System, building a metric-by-metric record of what changed and why. Executive compensation linkages are detailed at the individual metric level, consistent with the CPUC's expectation that utilities not just track safety performance but actively drive organizational behavior through it.
PG&E filed two documents.
- Its annual Safety Performance Metrics Report follows the same Commission-directed framework as the other utilities (metric tracking, compensation linkages, bias controls, and risk-spend context cross-referenced to its 2023 General Rate Case).
- Separately, PG&E filed its ninth semi-annual Safety and Operational Metrics Report covering January 1 through December 31, 2025, a broader operational dataset that includes reliability indices (SAIDI, SAIFI), outage performance, distribution and transmission ignition metrics, and gas system safety indicators. That report is anchored to PG&E's 2024 RAMP and pending 2027 General Rate Case.
The two PG&E filings position the company's metrics as live management tools: tracking trends, triggering corrective actions, and maintaining system-wide risk visibility across both electric and gas operations.
INSTANT ANALYSIS: Utilities are no longer arguing that their programs reduce risk. They are required to prove it through standardized, longitudinal data tied directly to spending, operations, and executive pay.
And they are building their records differently. The Sempra IOUs lean on trend narratives and program alignment. SCE builds metric-by-metric through operational feedback and contractor accountability. PG&E runs two parallel tracks (one Commission-standardized, one operationally expansive) and uses both to project institutional control over system risk.
The CPUC has created a common measurement language but it has not created a common truth. The next phase of litigation will center on whether these metrics reflect real risk reduction, or whether they can be gamed, redefined, or selectively framed to support rate requests.
TIMELY ENERGIZATION
California’s major electric IOUs filed their biannual energization reports in the CPUC's Timely Energization docket. The filings indicate that the Commission’s energization timeline is operational and largely being met, but the process remains constrained by factors utilities do not control.
All three utilities report against the framework established by a 2024 CPUC decision (D.24-09-020). They have implemented the required tracking systems and are producing more granular data, but energization is not linear. It spans engineering, permitting, construction, customer readiness, and upstream capacity, with many steps occurring in parallel and outside utility control.
- Compliance rates are high. PG&E reports 95% to 97% of its projects meeting maximum timeline targets in 2025, with similar directional performance across the other utilities.
- The constraint is execution. SDG&E and SCE state that their legacy systems do not align cleanly with the CPUC’s eight-step framework, which limits precise tracking where responsibilities overlap. All three utilities point to ongoing system upgrades, but full alignment requires significant investment.
- Operational limits drive outcomes. SCE cites permitting delays, material shortages, complex design, and outage constraints. SDG&E highlights overlapping workflows. PG&E quantifies the upper bound, with upstream upgrades taking 950 to 1,285 days.
- Timelines are stable, not falling. PG&E reports flat performance from 2023–2025 with a slight late-period improvement.
- PG&E states that Senate Bill 410 support is sustaining its current performance and warns that gains will not continue without it.
INSTANT ANALYSIS: The CPUC has a working system with high compliance but utilities control only part of the process. External factors set the pace. That gap will drive the next phase: disputes over who owns delays. Without continued funding, timelines will hold, at best.
SHARED RENEWABLES
The CPUC issued a proposed decision that implements the California Shared Renewables Portfolio by establishing a Community Renewable Energy tariff on a ReMAT/PURPA-compliant foundation and rejecting proposals for compensation above avoided-cost levels.
Following the EPA’s termination of Solar for All funding and the reversion of the $33 million state appropriation, the PD proceeds without the external funding layer contemplated in a 2024 CPUC decision (D.24-05-065). For Green Tariff programs, the PD shifts stranded cost recovery to each utility’s ERRA proceeding and reduces oversight by eliminating annual forums and advisory structures in favor of Procurement Review Group and ERRA oversight.
Comments are due April 27.
INSTANT ANALYSIS: The PD places the shared renewables portfolio within a strict avoided-cost framework. With Solar for All funding terminated and the $33 million appropriation reverted, the program loses the subsidy layer that was expected to support participation. The CPUC is advancing implementation, but prioritizing statutory compliance and ratepayer protection over project economics.
By anchoring the tariff to ReMAT and rejecting adders above avoided cost, the Commission is signaling that nonparticipants will not subsidize the program. That preserves legal defensibility, but narrows the revenue stack for developers and makes financing more difficult. For Community Choice Aggregators and developers, the result is a viable tariff structure with limited pricing flexibility and weaker market-building incentives.
ENERGY STORAGE/MICROGRIDS
SDG&E filed its compulsory cost-benefit report for a 7.3 MW/14.6 MWh battery system at the Borrego Springs microgrid, which is intended to absorb excess solar and support local reliability.
This particular project – Advanced Energy Storage, or AES – reached CAISO commercial operation on August 12, 2025, operated as a dual-asset microgrid on November 5, 2025, and was treated as complete after February 2026 data validation.
Total project cost to date is about $33.1 million, including a $4.913 million reduction tied to a denied hydrogen storage component. SDG&E says the battery is already creating value through CAISO market participation, energy arbitrage, and avoided Resource Adequacy procurement, while also providing resiliency, zero-emissions operation in some modes, and improved solar utilization.
INSTANT ANALYSIS: SDG&E is positioning the AES project as proof of a new utility storage model: a single asset that can monetize wholesale market participation, defer or avoid RA procurement, and still serve as a local reliability tool when needed. The battery can switch roles cleanly between market asset and microgrid support asset without operational friction.
The most important takeaway is that the CPUC appears willing to support battery-first deployments when they are tied to an authorized project scope and can show concrete operating value. But the Commission is not extending that tolerance to adjacent concepts like hydrogen storage that were not expressly authorized. This creates a strong regulatory signal: utilities can recover and operationalize batteries more easily when they fit within an approved framework, but they will face a much higher burden for speculative (or peripherally connected) technologies.
ENERGY STORAGE INVESTIGATION
At its April 9 voting meeting, the CPUC is expected to launch an investigation to determine whether:
- PG&E’s Elkhorn Energy Storage System has been out of service for nine or more consecutive months; and
- The CPUC should eliminate consideration of the plant’s value or disallow associated expenses from rates under Public Utilities Code §455.5 or other statutory authority.
The 182.5 MW/730 MWh battery system at Moss Landing has been offline since June 2, 2025 following a coolant leak during restart. PG&E reports it has no definitive return date and is planning for the facility to remain offline through the remainder of 2026.
While PG&E maintains that energy storage may not qualify as a “generation or production facility” under §455.5, it provided notice voluntarily, triggering the CPUC’s obligation to open this proceeding.
The order launching this rulemaking also directs PG&E to establish a memorandum account to track its authorized revenue requirement and related revenues, with amounts accruing interest and subject to refund from the date the investigation is issued. The matter may ultimately be addressed in coordination with PG&E’s Test Year 2027 General Rate Case.
INSTANT ANALYSIS: If the Commission finds that §455.5 applies to storage, the statute provides a direct path to disallow value and expenses tied to a prolonged outage. If it does not, the CPUC retains authority under “just and reasonable” standards to examine the same cost-recovery question.
- The memorandum account does not determine outcomes, it preserves the ability to reconcile revenues and apply refunds with interest if the CPUC later finds that costs should not have been collected during the outage period.
- The record points to extended uncertainty. PG&E has no restart timeline and is working with Tesla as the maintenance and warranty provider to address the coolant leak. That combination keeps the focus on outage duration, asset classification, and cost recovery rather than safety findings, which are being handled in separate investigations.
At the end of the day, this is a cost-recovery proceeding anchored in outage duration and statutory interpretation, with potential downstream implications for how long-duration outages at utility-owned storage assets are treated in rates.