WEDNESDAY AGGREGATE: 957 MMcfd or 2,700 MMcfd — Whose Aliso Canyon Supply Numbers are Correct?

Today's briefing looks at:

• A continuing round of conflict in the Aliso Canyon Biennial Assessment proceeding;
• A new document from SoCalGas that champions underground gas storage as long-duration strategic infrastructure rather than a legacy fossil burden;
• Opening briefs on utilities' hydrogen blending demos;
• Utility reports suggesting that biomethane remains a compliance artifact with no value as a reliability or decarbonization resource; and
• The CAISO's summer outlook assessment.

ALISO CANYON

Parties filed reply comments in the Aliso Canyon Biennial Assessment proceeding (A.26-01-009), following a workshop on April 15. For context, see CRI's summary of parties' April 28 opening comments here. (Additionally, CRI's briefing on SoCalGas's external outages report is available here.)

Reply comments continue a battle over whether California's gas reliability risks are being overstated to preserve storage inventories or understated through optimistic modeling assumptions. The dispute organizes around three variables: peak demand assumptions, Receipt Point Utilization (RPU), and the economic consequences of reducing storage inventories.

• Sierra Club continues to push for reduction of Aliso Canyon inventories to approximately 30 Bcf, arguing Energy Division's workshop analysis showed that 19 of 27 modeled winter 2025-2026 reliability scenarios could maintain service at 44% of current capacity.
  • Sierra Club attacks SoCalGas's proposal to extend the biennial assessment cycle to five years, pointing to more than 16.8 GW of expected renewable and battery additions in 2026-2027 and the 2025 biennial assessment's finding that most scenarios no longer require Aliso Canyon inventory by winter 2030-2031.
  • On RPU, Sierra Club's key move is citing the CPUC's own FTI consultant, whose 2021 analysis concluded that the Winter Storm Uri RPU drop "is not related to availability of takeaway capacity" and reflected price-driven market behavior rather than physical supply constraint. FTI recommended 95% RPU for its own modeling. Sierra Club argues SoCalGas is improperly redefining RPU as a supply availability metric to manufacture a reliability case that the Commission's own consultant doesn't support.
• SoCalGas counters that Energy Division's modeling understates reliability risks through unrealistic RPU assumptions and insufficient outage accounting. SoCalGas cites RPU of 47% during the 2021 Arctic Blast, 36% during the 2024 Arctic Blast and 2025 Southwest Winter Storm combined, and 25% system-wide during 2026 Winter Storm Fern, with Northern Zone supplies hitting 9% of available capacity during Fern.
  • SoCalGas argues these figures reflect physical supply constraints, not market behavior, and that Energy Division's assumption of 2,700 MMcfd minimum pipeline supply was contradicted by actual deliveries that fell as low as 957 MMcfd during the relevant winter.
  • SoCalGas also defends its maintenance record as compliance-driven rather than evidence of systemic unreliability, and argues that CalGEM and the CPUC already determined Aliso Canyon is safe to operate in their 2017 Comprehensive Safety Review.
• The Indicated Shippers align with SoCalGas's reliability critique while emphasizing two points the summary record tends to underweight.
  • First, the 44% capacity finding applied to only 19 of 27 modeled scenarios; in the remaining eight scenarios (nearly 30%) more than 44% is required. Standard reliability engineering sizes to worst-case modeled need, not central tendency.
  • Second, the 2025 Assessment contains no analysis of Unbundled Storage Program consequences from an inventory reduction. The Shippers argue this omission alone makes the assessment methodology insufficient for decision-making on just and reasonable rates.

INSTANT ANALYSIS: This proceeding is developing around two incompatible frameworks. Sierra Club's position is legal and methodological: it argues that the Commission's own consultant confirmed RPU drops are price phenomena, not capacity constraints, so SoCalGas's attempt to redefine RPU as a supply availability metric is unsupported in the record. If that redefinition fails, the 85% RPU assumption (adopted through prior stakeholder process and embedded in D.24-12-076) holds, and Sierra Club's inventory reduction case becomes substantially stronger.

SoCalGas's actual field data (957 MMcfd actual deliveries against a 2,700 MMcfd modeling assumption, 9% Northern Zone utilization during Fern) is serious and not answered in Sierra Club's reply. The question the CPUC will have to resolve is whether those events represent physical supply constraints that invalidate the FTI framework, or extreme pricing events that the FTI framework already accounts for by design.

SoCalGas's secondary move (converting inventory reduction into quantified ratepayer harm through probabilistic price analysis) is also significant. Once the proceeding contains a CPUC-vetted dollar estimate for storage reductions, the debate may shift from conceptual reliability to measurable ratepayer exposure. Sierra Club's opposition to that framework is procedurally coherent but strategically risky: if the CPUC allows even a limited economic analysis, the ensuing numbers will take precedence in the next round of arguments.

The Unbundled Storage Program matter identified by the Shippers is the least-developed but potentially most impactful discussion. An assessment that cannot quantify Unbundled Storage Program impacts from inventory reductions is incomplete by the CPUC's own just-and-reasonable-rates standard.

AFFORDABILITY

SoCalGas recently published "The Affordable Way for California," a report that makes a coordinated affordability argument against accelerated natural gas displacement. Using Bureau of Labor Statistics data, the report establishes that average California households spend $47/month on natural gas, which is less than electricity ($143) or gasoline ($308), and that inflation-adjusted residential gas rates fell about 25% between 2000 and 2023. Meanwhile, electricity rates rose 60% over the same period.

The report's most substantive empirical claim concerns natural gas storage and grid balancing. California's underground gas storage system can deliver 1,597 GWh/day, which dwarfs current battery (63 GWh/day) and pumped hydro (46 GWh/day) capacity. During Winter Storm Fern in January 2026, natural gas storage supplied nearly 60% of peak system demand and avoided over $120 million in customer costs. On renewable integration, CAISO data shows that between 2018 and 2024, noon solar generation rose about 6,500 MW while natural gas generation fell only 1,500 MW. The non-one-for-one displacement ratio is the most consequential number in the document.

The equity argument frames accelerated electrification as a cost-shift risk: if higher-income customers exit the gas network, fixed infrastructure costs concentrate on lower- and middle-income ratepayers least able to electrify. SoCalGas residential bills currently represent 0.6% of household income, the lowest among its major U.S. gas peers.

INSTANT ANALYSIS: This is a strong PR document that might help SoCalGas's optics with the general public. The document also repositions underground storage as long-duration strategic infrastructure rather than a legacy fossil burden, which is a useful argument in an era of affordability and reliability crises. However, the report doesn't engage methane leakage accounting, stranded asset liabilities, or the trajectory of battery storage costs.

UTILITY HYDROGEN BLENDING DEMO PROJECTS

Parties filed opening briefs in the utilities' hydrogen blending pilot proceeding, highlighting a fundamental conflict over whether the utilities' proposed pilots represent legitimate scientific inquiry or an expensive effort to extend the gas system's relevance.

The utilities argue their projects generate real-world operational data that modeling cannot replicate. Intervenors argue that hydrogen blending is a dead-end strategy and the pilots are imprudent regardless of design quality.

• PG&E's closed transmission test loop in Lodi makes the strongest incremental-knowledge case.
• Southwest Gas's Truckee pilot offers credible geographic differentiation.
• SDG&E's polyethylene pipe testing is credibly characterized as duplicative.
• SoCalGas's Orange Cove project (an open distribution system serving thousands of residential customers) faces a threshold legal question on closed-system compliance under a 2022 CPUC decision (D.22-12-057) and community opposition so severe that 27 of 33 residents who testified opposed or raised safety concerns.

Cal Advocates recommends dismissing all five projects. Sierra Club, the Environmental Defense Fund, TURN, the Utility Consumers Action Network, and Orange Cove intervenors align behind the same conclusion.

INSTANT ANALYSIS: The intervenor coalition has made pilot design largely irrelevant by arguing that no version of hydrogen blending in residential and commercial distribution systems produces ratepayer benefits sufficient to justify the cost when electrification is available and cheaper. The CPUC cannot approve these applications without confronting that argument directly, and the utilities have not made a clean showing on prudency. The Commission's ultimate decision will reveal whether the CPUC is adjudicating on the prudency standard or managing the bigger political question of what role gas infrastructure plays in California's decarbonization future.

BIOMETHANE

PG&E and the Sempra Utilities (SoCalGas/SDG&E) recently filed their annual biomethane compliance reports.

• PG&E reports no biomethane procurement in 2025 under the terms of a 2022 CPUC decision (D.22-02-025), rendering most of the CPUC's expanded reporting categories inapplicable. The filing defaults to legacy Phase II requirements, which run through 2027. Within that scope: there is one interconnected project, a development timeline exceeding five years, and a $3 million incentive payment issued last year. There is no new procurement and no scaling.
• SoCalGas and SDG&E executed two biomethane contracts in 2025 but recorded no flows for the year, leaving the expanded D.22-02-025 reporting categories inapplicable. Phase II reporting covers three CalBioGas projects in the Central Valley (North Visalia, South Tulare, and Buttonwillow) with interconnection timelines ranging from 1,044 to 1,457 days and incentive payments between $2.96 million and $5 million, all disbursed in July 2025.

Contracts are being signed, incentives are being paid, but gas is not flowing. The program has produced no delivered volumes under the newer regulatory framework.

INSTANT ANALYSIS: Interconnection timelines in the four-to-five year range and zero post-contract flows suggest a development pipeline that functions more like custom infrastructure than a scalable fuel supply. Until project execution risk comes down and molecules start moving, biomethane remains a compliance artifact with no demonstrated value as a reliability or decarbonization resource.

CAISO SUMMER ASSESSMENT

The CAISO published its 2026 Summer Loads and Resources Assessment. The system is better positioned than in 2024 or 2025. The CAISO enters summer 2026 with a modeled surplus of 2,547 MW against its 1-in-10 loss-of-load target, the fourth consecutive year meeting that standard. Peak demand is forecast at 46,844 MW on September 2, hour ending 18.

The surplus relies on assumptions that deserve scrutiny. The portfolio includes all RA-eligible capacity regardless of contracting status, a methodology CAISO acknowledges may overstate available supply. Known Loads, approximately 1,569 MW of potential additional demand from distribution-level energization requests, are excluded from stochastic modeling.

Hydro is constrained to a low-water analog year; snowpack as of April 1 was the second-lowest on record at 18%. SunZia Wind counts toward the net import limit during peak hours only up to 1,009 MW, not the full 3,167 MW CAISO share.

September evenings are still a problem. Loss-of-load events in the probabilistic model concentrate in hours ending 19 and 20, when solar output has dropped and batteries are discharging. July carries similar load but benefits from about 3.6 GW more solar during the peak hour. The multi-hour stack analysis requires a 25% planning reserve margin to hit the 0.1 LOLE standard; the load-weighted average LSE obligation sits at 17.5%, a 3,250 MW gap that emergency resources are expected to bridge.

That emergency backstop totals approximately 3,379 MW, drawn from the state's Strategic Reliability Reserve and intertie assistance. None of it is in the core RA stack.

The CAISO's model does not account for coincident extreme events (regional heat waves, drought, wildfires, or forced outages across neighboring balancing authorities). Those remain the primary risks.

INSTANT ANALYSIS: For the refiners and utilities reading this: the surplus is less comfortable than it looks. The 3,250 MW gap between what load-serving entities are obligated to hold and what the CAISO says is actually needed tells you where the risk resides. That gap gets filled by emergency resources outside the RA stack, resources that are slower to dispatch and not guaranteed to be available when a regional heat event is stressing neighboring balancing authorities at the same time.

For trading desks, September hours 19 and 20 are where the model breaks. That is not new information, but the assumptions propping up the surplus (excluded known loads, a capped SunZia contribution, low-hydro analog conditions) all move against the model at once. When supply runs short in those hours, prices move fast.