Prepared from SynMax storage-call tracking, Hyperion S/D and storage balances, EIA weekly storage, EIA-930 generation, and GFS weather. Figures refresh each Monday.
The EIA reported a +67 Bcf injection for the week ending October 9, 2026. SynMax had modeled +73 Bcf, an over-call of 6 Bcf, just outside our typical ±5 Bcf band.
Seasonal scorecard: Since July 17, the model's mean absolute error is 3.6 Bcf with a bias of +0.5 Bcf, a slight over-call tendency. The largest single miss of the season remains the mid-August print (about +7 Bcf), not last week. The shoulder-season transition will likely prove interesting as cooling load collapses and heating load has yet to take over.
The stated model accuracy and corresponding chart reflect SynMax's latest supply/demand models. These storage numbers will differ modestly from the official weekly storage-number call at the time of the number.
Working gas inventories stand at 3,567 Bcf as of October 9, 45 Bcf (1.3%) above the five-year average but 143 Bcf (3.9%) below last year. Looking ahead, the next three storage weeks are currently modeled at +89, +78, and +68 Bcf, which would lift inventories to roughly 3,802 Bcf by October 30.
Current SynMax call: +89 Bcf, lifting inventories to 3,656 Bcf.
Week-over-week drivers (Oct 16 vs Oct 9):
Total U.S. LNG feedgas climbed to about 19.6 Bcf/d on a weekly-average basis (from ~18.1 Bcf/d the prior week) and reached roughly 20.8 Bcf/d on October 18, a record high. Three terminals drove the gain: Cove Point ramping back up after completing its annual turnaround (Sep 20 – Oct 11), Freeport recovering from the prior week's dip, and Golden Pass posting its first sustained feedgas pulls as the new facility continues to commission. Golden Pass is the first of the next wave of U.S. export capacity to begin showing up in the demand stack.
Fall-maintenance season is active and the critical-notice count is elevated, but most items remain regional. The notable new discrete events this week are a fresh Columbia Gas (TCO) Force Majeure (posted Oct 14 but resolved by Oct 17) and an ANR Force Majeure running October 3 – November 1. On the longer-dated side, the Texas Eastern (TETCO) Line 15 situation continues to generate capacity constraints and OFOs extending into mid-January 2027, and Equitrans has posted maintenance running through January 31, 2027. The remainder is routine western-system capacity constraints (El Paso, Transwestern, Northern Natural) plus scattered OFOs.
The comfortable national surplus hides a sharp regional split. The Lower 48 sits 45 Bcf above the five-year average, yet every bit of that cushion is outside the South Central salt tier, which is entering winter 43 Bcf (15.4%) below its five-year average and 22% below last year. Salt caverns are the market's most flexible, highest-deliverability storage (the tier that often does the heavy lifting during cold snaps) so a deficit there matters more for winter reliability and Gulf/Henry Hub basis risk than the headline surplus suggests. Every other region is at or above its five-year average.
| Region | Stocks (Bcf) | vs 5-yr avg | vs last year |
|---|---|---|---|
| East | 884 | +28 (+3.3%) | +4 (+0.5%) |
| Midwest | 1,037 | +20 (+2.0%) | +10 (+1.0%) |
| Mountain | 255 | +13 (+5.4%) | −23 (−8.3%) |
| Pacific | 294 | +18 (+6.5%) | −13 (−4.2%) |
| South Central — nonsalt | 861 | +8 (+0.9%) | −55 (−6.0%) |
| South Central — salt | 236 | −43 (−15.4%) | −66 (−21.9%) |
| Total Lower 48 | 3,567 | +45 (+1.3%) | −143 (−3.9%) |
End-of-season baseline levels and modeled peaks/troughs:
| Season endpoint | Baseline level | Modeled peak / trough |
|---|---|---|
| End-injection Oct 31, 2026 | 3,814 Bcf | peak 3,887 Bcf @ Nov 15, 2026 |
| End-withdrawal Mar 31, 2027 | 2,159 Bcf | trough 2,102 Bcf @ Mar 18, 2027 |
| End-injection Oct 31, 2027 | 3,883 Bcf | still building past month-end (see note) |
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 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 forecasters continue to lean toward 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-of-withdrawal-season carryout on March 31, 2027 ends near 2,716 Bcf (2015 analog) or 2,518 Bcf (2023 analog), well above the Baseline trough. Beginning in April, those paths revert to the Baseline demand scenario, so 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, Corpus Christi, and the new Golden Pass ramp. Core heating demand is little changed to slightly softer. The Net balance Δ bar on the chart aggregates all components on a signed basis (supply positive, demand and exports negative): netting the supply gains against the demand gains, the implied daily balance loosens by +2.52 Bcf/d this winter versus last (−11.0 Bcf/d average net draw vs −13.5 Bcf/d a year ago).