Prepared from SynMax storage-call tracking, Hyperion S/D and storage balances, EIA-930 generation, and GFS weather. Figures refresh each Monday.
The EIA reported an +85 Bcf injection for the week ending October 2, 2026. SynMax called +80 Bcf, an under-call of 4.6 Bcf. Last week's miss falls toward the wider end of the normal weekly band, but still inside it.
Seasonal scorecard: Since July 17, the model's mean absolute error is 2.4 Bcf with a bias of +0.5 Bcf, a slight over-call tendency. The last 8 weeks have run tighter at 2.0 Bcf MAE / +0.2 Bcf bias. Every weekly call since mid-July has been within 5 Bcf of the EIA, with the largest miss just +4.7 Bcf (week ending July 24).
Working gas inventories now stand at 3,500 Bcf as of 10/2, 22 Bcf above the 5-year average but 131 Bcf below last year. Looking ahead, the next three storage weeks are currently modeled at 73, 79, and 68 Bcf, which would put inventories at 3,720 Bcf on Oct 23.
Current SynMax call: +73 Bcf, lifting inventories to 3,573 Bcf.
Week-over-week drivers (Oct 9 vs Oct 2):
Total U.S. LNG feedgas eased modestly week-over-week to ~18.1 Bcf/d, driven mainly by a Freeport dip; Sabine Pass firmed and the remaining terminals were little changed.
Cove Point's annual turnaround (Sep 20 – Oct 11) was resolved on time and the facility is operational again as of this morning, adding back ~0.8 Bcf/d of feedgas demand.
Fall-maintenance season is active but mostly regional. The notable discrete event is the Texas Eastern (TETCO) Force Majeure on Line 15 (Tompkinsville and Danville compressor stations, Valve Sections 2–4), posted Oct 2 and still in effect, with Force Majeure terms extending into November.
Two other multi-month items are worth tracking: Northern Natural's Carlton-area Force Majeure (latest update Sep 30) runs through year-end, and Natural Gas Pipeline's (NGPL) Moraine Lateral Force Majeure runs through Oct 31. The Columbia Gas (TCO) Force Majeure on the MXP/Mountaineer Xpress line in West Virginia, which pinched firm capacity in late September, was lifted effective Sep 27.
The remainder of the "critical" traffic is routine daily western-system capacity constraints (Northern Natural, Transwestern, El Paso Natural Gas) plus scattered low-level OFOs. These events are noisy at the local level but not materially moving the national balance this week.
End-of-season baseline levels and modeled peaks/troughs:
| Season endpoint | Baseline level | Modeled peak / trough |
|---|---|---|
| End-injection Oct 31, 2026 | 3,793 Bcf | peak 3,853 Bcf @ Nov 11, 2026 |
| End-withdrawal Mar 31, 2027 | 2,128 Bcf | trough 2,071 Bcf @ Mar 18, 2027 |
| End-injection Oct 31, 2027 | 3,854 Bcf | still building past month-end |
SynMax's Baseline storage scenario assumes the short-term GEFS forecast followed by the average demand across the ten most recent weather years. This is deliberately not demand at "average weather": demand responds quite nonlinearly with respect to temperature, and averaging the demand outcomes preserves the weight of cold snaps and heat waves that a smoothed temperature profile would wash out.
As many weather forecasters are calling for an El Niño winter, the chart below also shows our projected storage outlook under the two most recent El Niño winter weather paths through March. Under those paths the end-withdrawal carryout on Mar 31, 2027 lands near 2,715 Bcf (2015 analog) and 2,492 Bcf (2023 analog), well above the Baseline trough. Beginning in April, those paths utilize the Baseline demand scenario and thus the storage outlooks run in parallel with the Baseline through summer 2027. Refer to the Long-Term Storage Outlook dashboard for other weather paths.
Year-over-year S/D for the withdrawal season (Nov–Mar 2026/27 vs 2025/26): supply growth continues to outpace demand through the heating season, which supports the higher projected carryout and the shallower modeled trough. Averaged across November–March, dry-gas production is +5.4 Bcf/d year-over-year and only partly offset by increased LNG feedgas (+2.1 Bcf/d) driven by Plaquemines and Corpus Christi. Core heating demand is little changed to slightly softer: residential and commercial each ease ~0.3–0.4 Bcf/d, electric power firms ~0.3 Bcf/d, Mexico exports add ~0.3 Bcf/d, and Canadian imports slip ~0.3 Bcf/d. Net, the implied daily balance loosens by roughly 2.5 Bcf/d this winter vs last (−11.0 Bcf/d avg net draw vs −13.5 Bcf/d a year ago).