FRIDAY AGGREGATE: SoCalGas Report Tracks Storage Dependence During High-Stress Conditions
Today's briefing includes updates on SoCalGas's system reliability for the period of April 2025 - March 2026 plus a stern letter from CPUC President John Reynolds to PG&E, which is being folded into the record of two separate proceedings.
SOCALGAS SYSTEM RELIABILITY
SoCalGas published its Seventeenth Annual Report on System Reliability, covering April 2025 through March 2026.
SoCalGas declared 185 High Operational Flow Orders over the reporting year, an 80% increase from the prior period, against just 16 Low OFOs. Gas Control issued 29 requests for additional supply to maintain minimum flow on the Southern System. The utility purchased 2.57 MMDth and sold 3.05 MMDth in the spot market, with a net cost of $3.9 million, or $1.53 per Dth blended.
Recall that a High OFO is called when forecasted injections exceed the storage capacity allocated for balancing. A Low OFO is the inverse: forecasted withdrawals exceed withdrawal capacity. Gas Control builds the sendout forecast from weather, market data, and demand inputs from the CAISO, the Los Angeles Department of Water and Power, and the Imperial Irrigation District. OFOs are called by 8 p.m. the day prior on the Evening or Intraday 1 cycle.
All 16 Low OFOs occurred in winter, from November through March. The 29 minimum flow requests tell a different seasonal story. More than half came in August alone, with individual shortfalls running from 12,000 Dth on a quiet day to 341,000 Dth at the peak of the summer stress. SoCalGas ended the year having sold more gas than it bought. The $3.9 million net cost reflects higher purchase prices relative to sale prices needed to move gas to constrained delivery points.
What SoCalGas didn't do is also worth noting:
- No Emergency Flow Orders;
- No Provider of Last Resort calls to Gas Acquisition;
- No baseload purchases; and
- No discounted interruptible backbone transportation offered to bring more gas in from Ehrenberg.
The utility managed an 80% increase in High OFOs without reaching for any of the extraordinary tools available to it.
Some regulatory takeaways are highlighted below.
- Energía Costa Azul will draw roughly half a billion cubic feet a day from the same pipeline that supplies the Southern System. The terminal received its first feed gas on April 28, and commercial service is expected this summer. The CPUC has already said it may revisit minimum flow tools once ECA is running, which means the current toolkit predates it.
- Aliso Canyon inventory levels are a contested topic. An October 2025 Energy Division assessment recommended cutting the facility's storage cap from 68.6 to 58.6 Bcf, while finding the field needs to deliver at least 550 MMcfd on a cold winter day. SoCalGas filed in January to reject the cut.
- Although SoCalGas does not make this argument explicitly, the 185 High OFOs are consistent with a system that needs more injection capacity, not less. The CPUC's eventual action on this matter is the biggest single reliability variable heading into next winter.
- Backbone rates will change on October 1. A new firm volumetric option called G-BTS5 will become available, and existing G-BTS2 contracts will convert to fully volumetric. The Seventh Memorandum in Lieu of Contract between SoCalGas's System Operator and Gas Acquisition department runs through October 2027 at the latest.
INSTANT ANALYSIS: The reporting period closed March 31, but the most consequential data point in the entire document arrived after it. Energía Costa Azul received its first feed gas on April 28, three days before SoCalGas filed this report. Every reliability number in the document describes a system that has not yet absorbed the supply diversion it was built without.
On Aliso Canyon, SoCalGas would not be fighting a 10 Bcf inventory cut so hard if its modeling showed the existing storage envelope holding under ECA-era flows. The 550 MMcfd peak day floor is a public number. The company's internal number is almost certainly higher.
The blended $1.53 per Dth annual cost hides what actually happened. January spot purchases ran $15-to-$17 on the days SoCalGas needed gas at constrained delivery points. The reliability cost for the entire year concentrates on a small number of days when weather, routing, and intraday scheduling break the wrong way at the same time.
The open question is whether the absence of Emergency Flow Orders, Provider of Last Resort calls, baseload purchases, and discounted backbone transportation reflects a utility that does not need those tools or a utility that has not been forced to use them. Winter 2026-27 will provide a big test, and the CPUC's action on Aliso Canyon is the most crucial variable.
ELECTRICAL UNDERGROUNDING
On April 30, the CPUC placed a letter from President John Reynolds to PG&E into the record of two proceedings.
- ALJ Regina DeAngelis inserted the letter into A.26-02-005, the joint utility application seeking approval of a Benefit-Cost Ratio calculation methodology, audit methodology, and cost recovery conditions under Resolution SPD-37.
- Commissioner Matthew Baker followed by placing the same letter into the PG&E 2027 General Rate Case docket (A.25-05-009).
Reynolds wrote to both Patti Poppe (CEO, PG&E Corporation) and Sumeet Singh (CEO, PG&E Company), with the full Commission copied. He frames Senate Bill 884 as the preferred undergrounding vehicle (due to its 10-year planning horizon, expedited review, better financing, lower ratepayer costs) and acknowledges PG&E's intent to use it beginning in 2028. His concern is the Electric Undergrounding Plan filing date. PG&E announced plans to underground 10,000 miles of infrastructure in July 2021. SB 884 became law 14 months later. PG&E has had nearly five years to file an Electric Undergrounding Plan. It has not.
Reynolds finds PG&E's explanation unpersuasive: the company claimed it sought to file an Electric Undergrounding Plan since 2022 while admitting it didn't begin working on one until March 2024. The result is that funding that belongs in SB 884 now sits in a GRC extension mechanism.
Reynolds closes with an encouragement, not a directive: file as soon as possible.
INSTANT ANALYSIS: Reynolds is irritated. PG&E claimed urgency on wildfire risk while taking five years to begin work on the one filing the program requires. He calls the contradiction out directly. PG&E built a GRC extension mechanism because it knows the SB 884 timeline may not hold. Reynolds is telling PG&E the Commission noticed and that it cannot escape scrutiny by letting undergrounding drift into the GRC. The Commission will apply the same prudency standard regardless of forum, and the burden is on PG&E to meet it.