SoCalGas Customer Forum: 185 High OFOs, No North-South Expansion, & What 0.5 Bcf/d from Costa Azul Means for Reliability

SoCalGas hosted its 2026 Annual Customer Forum this morning, detailing the April 2025-March 2026 reporting period, the pending 2024 Cost Allocation Proceeding implementation, and its active 2027 CAP proposal.

Notably:

• The Southern System reliability strategy the CPUC acknowledged in D.22-07-002 may require reassessment once Energía Costa Azul LNG begins drawing feed gas this summer.
• The forum's most consequential exchange involved the long-rejected Adelanto-to-Moreno North-South pipeline project. A participant asked whether SoCalGas would revisit that expansion given imminent ECA demand. SoCalGas's answer, that the CPUC has instructed staff to wait until operational data arrives from the liquefaction plant before reconsidering North-South capacity, is the regulatory holding pattern trading desks and large industrial customers should understand heading into Q3 2026.

OPERATIONAL FLOW ORDERS

High OFO declarations rose about 80% year over year. The bulk of the increase came at Stage 3.1, with new activity emerging at Stage 3.2. Cycle 2 declarations climbed from 98 to 172. Daily imbalance tolerances ranged from 2% to 15% during the current period.

SoCalGas attributed part of the increase to a relatively warm winter. Storage injection capacity is stressed when system demand runs below normal and excess supply needs to be absorbed. But a relatively warm winter should also have suppressed Low OFOs by less than the 50% reduction the data actually shows. The asymmetry between the two directions suggests other dynamics are in play and is the kind of pattern that should draw questions in the post-forum process.

Low OFOs fell from 32 to 16, with the entire reduction coming from Cycles 2 and 3.

SOUTHERN SYSTEM RELIABILITY PURCHASES & THE $15 OTAY QUESTION

SoCalGas purchased and sold approximately 2,560 MDth during the reporting period at a net cost of $1.53/Dth, generating $3.9 million in System Reliability Memorandum Account costs. Of the five tools available for southern system reliability, SoCalGas used only two: spot transactions and the Memorandum in Lieu of Contract. Seasonal baseload purchases, discounted BTS contracts, and RFPs went unused. No BTS discounts were applied.

Net volumes are the second-highest in the six-year history shown. 2022–2023 remains the peak at 4,124 MDth and $31 million in SRMA costs. Average net cost per Dth is the lowest of any year with Southern System Reliability activity. Most purchases occurred during summer 2025, with a smaller cluster in February 2026.

One trading-side question concerned a specific transaction within that activity: an intraday purchase of 123,000 Dth at Otay on September Gas Day 3 at $15/Dth, about $12 above the Ehrenberg ICE settle for that day. The participant asked how the pricing was justified.

SoCalGas identified the personnel responsible for soliciting intraday gas in response to Gas Control requests, and deferred specific justification to the 2026 annual compliance report, Advice No. 6558-G-A. That same advice letter contains SoCalGas's pending request to modify the Rule 41 Safe Harbor Guidelines for baseload purchases, discussed below. The two items are linked: a $12/Dth premium over an inter-basis differential is the kind of pricing outcome that would be more difficult to defend if the utility had broader baseload procurement authority.

THE NORTH-SOUTH PIPELINE

A participant asked whether SoCalGas had revisited expanding the Moreno compressor or other North-to-South capacity given Costa Azul's expected demand, rather than relying solely on southern system reliability concerns or warnings.

SoCalGas identified the actual constraint: the issue is not really Moreno, but the pipeline capacity to move gas south from the Northern System to Moreno. SoCalGas applied for funding authority over 10 years ago for a pipeline from Adelanto to Moreno to expand its North-South capability. The CPUC rejected the project.

Asked whether the project might be revisited given changed fundamentals, SoCalGas pointed to the Long-Term Gas System Planning docket and suggested that the CPUC has advised to "do nothing" until data on the ECA liquefaction facility and its impacts is available.

ECA Phase I is expected in-service summer 2026, with Natural Gas Intelligence recently reporting that the first volumes of feed gas had entered the plant. SoCalGas expects ECA to take approximately 0.5 Bcfd from the El Paso Natural Gas South Mainline at full operation, the same supply path that feeds the southern zone.

In short:

• CPUC policy is to wait on ECA operating data before authorizing capital investment in North-South capacity; and
• ECA is poised to reduce southern zone receipts by about half a Bcfd.

In the interim, the reliability-tools approach (spot purchases, the Memorandum in Lieu of Contract, the pending Safe Harbor modification for baseload) becomes the operational response to a demand event the CPUC anticipated but did not pre-position infrastructure to address.

CAP IMPLEMENTATION ON ENVOY OCTOBER 1

D.24-07-009, the CPUC's 2024 decision authorizing an all-party settlement in the 2024 CAP, is moving into implementation. Three items remain pending:

• G-BTS5 firm volumetric rate is effective October 1, 2026 (100% volumetric, no reservation charge);
• G-BTS2 conversion of existing G-BTS2 contracts reverts to a Modified Fixed Variable structure once G-BTS5 becomes available; and
• The Open Season is extended by one month, aligning the BTS term with the November–October gas industry seasonal practice

SoCalGas filed Advice No. 6626-G in April to implement these changes. Approval is expected ahead of the next Open Season. Envoy will reflect the changes on October 1, including secondary trade of G-BTS2 contracts with negotiable reservation charges, and a buy/exchange rights window opening September 16, 2026 for contracts beginning October 1.

2027 CAP (A.25-09-014): THREE PROPOSALS AFFECTING SHIPPERS

The 2027 CAP application, for rates effective January 1, 2027, includes three proposals BTS shippers and noncore customers should track:

1. NSBA-to-FASRMA reallocation: The proposal would apply the Noncore Storage Unbundled Storage Balancing Account overcollections to the Firm Access Storage Rights Memorandum Account until the current undercollection is fully offset.
2. BTS sale ceiling: The proposal would modify BTS to limit the maximum amount of firm BTS available for sale to 110% of the minimum backbone system design standard, based on the average day quantity in a 1-in-10 cold-and-dry year.
3. Rule 30 modification: The proposal would confirm BTS nominations up to Total Net System Capacity for the Evening, Intraday 1, Intraday 2, and Intraday 3 cycles regardless of a Gas Day's OFO status.

Proposal 2 is the most consequential for shippers. Today's BTS availability is implicitly bounded by system economics and design. The 110% of 1-in-10 cold-and-dry framework would convert that into an explicit ceiling tied to a planning standard SoCalGas controls. The 1-in-10 cold-and-dry parameterization warrants close attention from industrial coalitions, both for the underlying methodology and for how the design quantity itself gets calculated and refreshed over time.

Per the scoping ruling, a CPUC decision is expected in Q4 2026.

ALISO CANYON: SOCALGAS PUSHES BACK ON INVENTORY REDUCTION

The first Biennial Assessment under D.24-12-076, issued by Energy Division on October 1, 2025, recommended reducing Aliso Canyon's maximum inventory by 10 Bcf (from 68.6 Bcf to 58.6 Bcf) for winter 2025–2026. The assessment also indicated that a smaller incremental reduction or no reduction at all may be appropriate for winter 2026-2027, given forecasts of higher gas commodity prices.

SoCalGas filed an application in January requesting CPUC review, asking the Commission to decline the recommended reduction and to authorize an increase to maximum inventory if necessary to maintain reliability and just-and-reasonable rates.

The Biennial Assessment's own caveat about higher winter 2026-2027 gas prices is an interesting analytical point. Energy Division is acknowledging that the cost of holding less inventory at Aliso Canyon becomes increasingly difficult to justify as the commodity environment changes, even before considering ECA's effect on southern zone supply.

SAFE HARBOR MODIFICATION STILL PENDING

SoCalGas's request to modify the Rule 41 Safe Harbor Guidelines for baseload transactions remains pending under Advice No. 6558-G-A. SoCalGas explained the underlying issue: when SoCalGas previously used baseload transactions, firm BTS capacity was available to assign on a day-to-day basis. Current conditions do not permit that, and the existing Safe Harbor framework does not accommodate the type of baseload purchases SoCalGas now needs to make for southern system reliability.

A separate question later in the forum addressed the operational consequence: would SoCalGas communicate any shift from daily spot to monthly baseload procurement? SoCalGas confirmed there is a solicitation process for baseload purchases if the company goes that direction.

The implication: if the Safe Harbor modification is approved, SoCalGas could move from event-driven spot activity to systematic baseload procurement on the southern system. That would alter the activity profile reflected in the Southern System Reliability cost graph and likely change the pricing dynamics raised in the Otay question earlier in the forum. Trading desks should plan for that possibility in their southern system supply models for 2027.

RENEWABLES & THE MINIMUM FLOW REQUIREMENT

An industrial-side question asked whether the southern system minimum flow requirement might decrease as renewable power capacity grows, citing the SunZia wind project ramping in the Southwest Power Pool. SoCalGas answered in general terms: that depending on grid interconnection, plants outside the southern system get dispatched to cover demand inside it, and that effect is presumably already reflected in current minimum flow requirements.

The question is notable. SunZia Phase I (3 GW transmission, approximately 2.4 GW of associated wind) has been ramping commercial operation through 2025–2026. The Southern System minimum flow requirement is a function of gas-fired generation needs in the southern zone. Sustained displacement of southern gas-fired generation by imported renewables would allow the minimum to come down.

Whether SoCalGas's planning methodology captures that dynamic on a rolling basis or only at major system planning intervals is a question worth raising in the Long-Term Gas Planning docket, and one the 2027 CAP design quantity calculation should engage with directly.

The forum presentation is available here.

NEXT STEPS

SoCalGas will publish draft post-forum report to Envoy by May 29. A revised draft will be available by June 18. The final post-forum report will be filed via advice letter by July 14. Customers with forum proposals should submit them before issuance of the draft post-forum report.

INSTANT ANALYSIS

Today's forum clarified SoCalGas's regulatory trajectory heading into ECA startup. The utility placed three items on the record in the same setting.

• First, ECA is expected to take approximately 0.5 Bcfd from the El Paso South Mainline once at full operation.
• Second, the CPUC's stance on North-South capacity is to wait for ECA operating data before reconsidering any infrastructure proposal, including the Adelanto-to-Moreno project the Commission rejected more than a decade ago.
• Third, the existing Rule 41 Safe Harbor framework does not accommodate the baseload procurement SoCalGas may need under current BTS conditions, and the modification request remains pending under Advice No. 6558-G-A.

A demand event the Commission anticipated is about to arrive. The capital response the utility proposed years ago was rejected. The procurement framework the utility now needs has not yet been approved. In the interim, southern system reliability runs on spot purchases, the MILC, and whatever operational latitude the CPUC grants on a case-by-case basis. The Otay transaction discussed at the forum (123,000 Dth at about $12 over Ehrenberg ICE) is the visible cost of that stance.

The next 12 to 18 months will be defined by three observables:

• How quickly ECA changes actual southern zone flow patterns;
• Whether Southern System Reliability activity continues at or above the current $3.9 million annual run-rate; and
• Whether the CPUC becomes more receptive to either the Safe Harbor modification or revisiting North-South infrastructure once ECA operating data is on the record.

The 2027 CAP's proposed 110% of 1-in-10 cold-and-dry BTS sale ceiling should be read as part of the same arc: a constraint on shipper access to firm capacity at the same moment SoCalGas is asking for additional operational latitude on the procurement side.