MONDAY AGGREGATE: Aliso Canyon Clash; PCIA/ERRA Reform (Track 3); Criticism of IRP Continues
Today's update examines party criticisms of Aliso Canyon natural gas storage levels, consequential portfolio recovery issues in the ERRA/PCIA Reform docket, and the scoping memo for SoCalGas and Lakeside Pipeline LLC’s application to recover cost overruns from a dairy biomethane pilot project. The latter item is an early stress test for Commission tolerance on RNG cost escalations.
Additionally, parties continue to characterize the current proposed decision in the IRP rulemaking as overly rigid, potentially oversized, and misaligned with affordability risks.
ALISO CANYON STORAGE
On February 20, multiple parties responded to SoCalGas’s compliance application in A.26-01-009, presenting divergent views on the future role of the Aliso Canyon storage facility. (See CRI's recent coverage of this matter here.)
At issue is SoCalGas's request for CPUC review of Energy Division’s 2025 Aliso Canyon Biennial Assessment, which recommends reducing the facility’s maximum inventory level by 10 Bcf from the current 68.6 Bcf authorized in a 2024 decision (D.24-12-076).
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In their remarks, stakeholders advance competing reliability, safety, and cost arguments.
- Sierra Club argues the application exaggerates gas demand and reliability risks. Pointing to declining gas use, rapid renewable and battery resource growth, and Energy Division's own modeling (which shows 44% or lower inventory levels sufficient across 19 scenarios), Sierra Club urges the CPUC to reduce storage capacity by as much as 38 Bcf, bringing the limit down to 30 Bcf. Sierra Club also calls for accelerated transition away from gas infrastructure and enhanced coordination with electric system planning.
- Cal Advocates similarly protests the requested increase, focusing on whether expanding inventory above the current authorized level would exceed the safe reservoir operating pressure of 3,600 psi, conflict with the scope of prior decisions, or impose unjustified risks and costs on ratepayers. Cal Advocates urges additional analysis of systemwide storage coordination and safety oversight.
- Porter Ranch resident Issam Najm likewise contends that SoCalGas dismissed Energy Division's analysis without justification. Using SoCalGas's own withdrawal data, Najm shows that even at 40 Bcf stored, withdrawal capacity (approximately 900 MMcfd) far exceeds the 550 MMcfd threshold Staff identified as the reliability requirement, leading him to recommend a specific 20 Bcf reduction to 48.6 Bcf rather than any increase.
On the other hand, the Indicated Shippers (representing major noncore industrial gas users including Chevron, Marathon Petroleum, California Resources Corp., BP, and PBF Holding) support the application. The Shippers assert that reducing storage would heighten outage risk, price volatility, and curtailment exposure during extreme weather. The Shippers criticize the Biennial Assessment for unrealistic assumptions that understate the need for storage and overstate available pipeline supplies.
Separately, the Southern California Generation Coalition (SCGC) seeks party status to protect gas-fired power generators' interests, emphasizing that changes to inventory limits could materially affect fuel reliability and energy costs for electric generation dependent on SoCalGas transmission.
SCGC's distinguishing contribution is a proposal to use backcasts (historical data analysis of whether the system could have operated without Aliso Canyon) rather than forecasts to evaluate storage need, a methodological position the Commission previously declined to mandate but did not prohibit.
INSTANT ANALYSIS: Environmental and ratepayer parties are pushing for deeper storage cuts on safety and demand-decline grounds, while industrial users and generators argue reductions would raise outage risk and price volatility. This may become a slow-moving proceeding with a compromise outcome (partial reduction or added safeguards), and not a decisive shift toward closure of the Aliso Canyon facility.
PCIA/ERRA REFORM
The CPUC issued a ruling in the Energy Resource Recovery Account and Power Charge Indifference Adjustment reform rulemaking (R.25-02-005), directing the investor-owned utilities and inviting other parties to file comments on the scope of Track 3.
Track 3 will address the proceeding’s remaining broad issues.
- Opening comments are due March 27; and
- Reply comments are due April 10.
Parties are asked to identify which issues Track 3 should cover, how they should be prioritized, potential data confidentiality constraints, and expected timing and interdependencies.
The ruling notes that earlier tracks addressed narrower topics and that Track 3 is intended to tackle the wider set of unresolved ERRA and PCIA policy questions outlined in the original Order Instituting Rulemaking. Party input will inform a forthcoming Track 3 scoping memo and possibly a future status conference.
INSTANT ANALYSIS: This ruling opens the agenda-setting phase for Track 3 of the ERRA/PCIA reform proceeding, where the Commission will finally address the most consequential unresolved cost-allocation and portfolio recovery issues left outside the narrower earlier tracks.
By asking parties to propose scope, priorities, confidentiality frameworks, and timing, the ALJ is effectively inviting stakeholders to shape the battlefield before formal policy positions harden. This dynamic favors well-resourced utilities and sophisticated intervenors.
For load-serving entities, Community Choice Aggregators, and large customers, the Track 3 scope will determine whether such contentious topics as legacy cost treatment, portfolio optimization rules, and future PCIA mechanics are handled incrementally or in a single high-stakes phase.
BIOMETHANE
Commissioner John Reynolds issued a scoping memo in A.25-08-009 establishing the procedural framework for the CPUC’s review of SoCalGas and Lakeside Pipeline LLC’s request to recover approximately $7.8 million in cost overruns from the Lakeside Maas Energy Works Dairy Biomethane pilot project. The latter is one of several projects authorized to demonstrate dairy biomethane interconnection to the gas pipeline system.
The ruling defines the key issues for review, including whether project management and cost increases above the original bid were reasonable, whether proposed rate recovery is justified, and how the project affects environmental and social justice goals.
The proceeding's timeline reflects an application the Commission found deficient at the outset. At the November 2025 prehearing conference, the ALJ highlighted missing engineering documentation in three areas:
- Foundation redesign for compressors;
- Power distribution center scope increases; and
- instrumentation additions.
SoCalGas addressed these issues through supplemental testimony. The ruling cites supplemental testimony as the reason intervenors received 75 days to prepare testimony rather than the 60 days Cal Advocates had requested. Intervenor testimony is due April 24, with rebuttal testimony served on June 19. Opening briefs are scheduled for August 12, with reply briefs due September 11.
INSTANT ANALYSIS: This scoping memo frames the proceeding around whether SoCalGas and Lakeside can justify $7.8 million in biomethane pilot cost overruns and recover those amounts in rates. But it also leaves the door open to a broader examination of project management practices that could influence future renewable gas initiatives.
The inclusion of environmental and social justice impacts as a formal issue reflects the CPUC’s continued effort to apply ESG criteria even in infrastructure cost-recovery cases, which may complicate approval for similar projects going forward. The timeline suggests a methodical review rather than an expedited pathway, which creates uncertainty for developers pursuing dairy biomethane interconnections under earlier pilot authorizations.
Generally speaking, the case is shaping up to be an early test of Commission tolerance toward cost escalation in state-backed renewable gas pilots. For utilities, agricultural methane developers, and ratepayer advocates evaluating the financial viability of California’s biomethane build-out, this process bears watching.
SELF-GENERATION INCENTIVE PROGRAM
Commissioner Karen Douglas issued a ruling in the SGIP docket directing program administrators to immediately strengthen verification of Total Eligible Project Costs for Residential Solar and Storage Equity projects before incentive payments are issued, after evidence showed reported project costs far exceeding both incentive levels and market averages.
The Residential Solar and Storage Equity program, funded at $252 million to support low-income households installing solar-plus-storage systems, was designed so incentives (paired with the federal tax credit) would cover most project costs.
However, reviews found average reported costs of roughly $46,000 across all developers and $58,000 among the largest developers, compared with an expected cost near $30,000 and market estimates closer to $25,000. These elevated costs reduce the number of households the program can serve and may require low-income participants to pay unexpected out-of-pocket expenses.
Finding wide and unexplained price variations for similar equipment and installations, the ruling now requires enhanced documentation for any project whose reported costs exceed 90% of the maximum allowable incentive, including receipts, labor contracts, and potentially more extensive verification for projects above 100%.
INSTANT ANALYSIS: By conditioning payments on cost verification above the 90% threshold, the ruling shifts enforcement risk onto developers and program administrators while preserving the headline incentive structure adopted in a 2024 CPUC decision (D.24-03-071).
The move also functions as a soft market correction: if inflated bids cannot be substantiated, either prices will compress or project volume will fall, slowing Residential Solar and Storage Equity deployment but extending budget reach.
Expect heightened scrutiny of third-party ownership models, contractor practices, and potential arbitrage of stacked subsidies, with possible downstream implications for SGIP participation economics and developer consolidation in the equity segment.
INTEGRATED RESOURCE PLANNING
The Alliance for Retail Energy Markets (AReM) submitted a written ex parte communication urging the CPUC to revise its proposed decision in the Integrated Resource Planning rulemaking.
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The PD, scheduled for consideration on February 26, require major electric resource procurement for 2029–2032. AReM argues the PD relies on effective load carrying capability (ELCC) metrics that could translate a nominal 6 GW procurement mandate into more than 40 GW of solar-plus-storage capacity on a nameplate basis, raising feasibility, market, and cost concerns.
- Based on recent CPUC modeling, AReM estimates annual procurement costs could rise from roughly $691 million under earlier assumptions to as much as $2–$5 billion, particularly as data center load growth drives demand while policy on allocating those costs remains unsettled.
- AReM further contends the proposal risks shifting costs unfairly onto existing customers (especially those served by electric service providers in the Direct Access program, which is capped and cannot enroll new data center loads) while also removing compliance flexibility that currently allows load-serving entities to manage procurement delays without penalties.
AReM asks the CPUC to reduce procurement volumes, preserve compliance flexibility, prevent cost shifting, and adopt a more programmatic, technically grounded procurement framework aligned with affordability and broader state policy objectives. (Additional CRI coverage of ex parte meetings in this proceeding are provided at the links below.)
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INSTANT ANALYSIS: The AReM ex parte filing adds to a rapidly consolidating stakeholder narrative that the proposed 2029–2032 procurement mandate in the IRP docket is overly rigid, potentially oversized, and misaligned with affordability risks.
- Like CalCCA, the Joint IOUs, and Cal Advocates, AReM warns that inflexible procurement volumes combined with constrained compliance pathways could force load-serving entities into inefficient resource choices and elevated costs, particularly if storage limits, procurement deadlines, and modeling assumptions remain unchanged. AReM’s focus on ELCC math translating a nominal 6 GW mandate into far larger nameplate procurement (and potentially billions in annual costs) intensifies the affordability argument already advanced by CCAs and consumer advocates.
- AReM's filing also introduces a distinct distributional concern: cost exposure tied to data-center-driven load growth may fall on existing customers, especially Direct Access participants who cannot serve new loads due to the statutory cap. This echoes Cal Advocates’ warnings about over-procurement and ratepayer harm, while aligning with utility requests to reassess need using updated forecasts and preserve flexibility for delayed projects.
With ex parte activity intensifying days before the February 26 vote, the probability of late edits is rising. Any revisions to procurement size, ELCC assumptions, storage treatment, or compliance mechanisms would cascade into Resource Adequacy positioning, contract timing, transmission planning, and long-term resource mix decisions. The proceeding remains in flux, and the final order could differ significantly from the current draft.