Oil Is Near $90 And Gas Is Near $3. Same Wells, Different Markets.

Associated gas, healthy storage and an LNG buildout are pulling gas prices away from oil, and contracts written for one price environment are being tested in another.

WTI crude has recently traded around $90 a barrel. Henry Hub natural gas futures settled at $3.03 per million Btu on September 30. In the Permian, many operators pull both out of the same wells, and right now the economics of the two look very different.

The forecasts show the same gap. The U.S. Energy Information Administration’s September Short-Term Energy Outlook has Henry Hub averaging $3.43 per million Btu in 2026 and $3.28 in 2027. That second number is worth a second look. In January, EIA expected 2027 gas to average $4.59, because it expected demand growth, driven largely by LNG export plants, to outpace supply growth. The agency has since cut that forecast by $1.31.

Gas Comes Up With the Oil

Most Permian gas is associated gas, meaning it comes out of wells drilled primarily for oil. EIA describes it the same way: most Permian natural gas production is associated with crude-oil production. And the gas-to-oil ratio keeps climbing. The Permian averaged nearly 4,200 cubic feet of gas per barrel of oil in 2025, 15 percent higher than in 2021. As long as oil prices justify drilling, associated gas can keep growing even when local gas prices are weak or pipeline space is scarce.

Nationally, dry gas production is close to record levels. EIA expects it to average 111.7 billion cubic feet a day in 2026 and 115.9 Bcf a day in 2027.

The Permian has already shown what happens when that gas has nowhere to go. As of mid-April, prices at the Waha hub in West Texas had stayed negative for a record 47 consecutive days because limited pipeline capacity trapped associated gas in the basin. EIA notes that Energy Transfer’s Hugh Brinson pipeline, which starts in the Permian, began moving gas into interstate markets in June, earlier than the agency expected.

Storage Is Comfortable

EIA reported working gas in storage at 3,415 billion cubic feet for the week ending September 25. That’s 2.4 percent above the five-year average and nearly 4 percent below a year ago.

EIA’s outlook has inventories reaching 3,969 Bcf on October 31, 5 percent above the five-year average, when the injection season ends. EIA also says the Permian and Haynesville regions together account for more than 70 percent of the production growth in its forecast.

January looked different. EIA then expected supply growth to run slightly ahead of demand growth in 2026 and fall behind in 2027 as LNG feedgas demand picked up, and it forecast Henry Hub prices rising about 33 percent in 2027. The September outlook has 2027 averaging slightly below 2026.

LNG Is Pulling the Other Way

LNG demand keeps growing. EIA expects U.S. gross LNG exports to average about 17 Bcf per day in 2026 and about 19 Bcf per day in 2027. In its January outlook, EIA attributed export growth to the ramp-up of three facilities: Plaquemines LNG, Corpus Christi Stage 3 and Golden Pass LNG.

Demand is still growing, and EIA still cut its price forecast. Anyone who leaned on the January outlook when pricing a long-term deal is now working from a very different number.

Where the Contracts Start to Matter

Most of the trouble starts with contract language nobody read closely. Here’s where I’d look.

Start with the index. Gas sales and gathering agreements can price off Henry Hub, a regional hub like Waha, or a formula that blends several, and those prices can move far apart, as Waha showed. Some agreements say nothing about what happens when prices go negative or when the sales price drops below what it costs to gather, treat and transport the gas. If yours is silent, the parties may end up arguing over how the pricing, delivery and payment provisions split the loss.

Associated gas adds a wrinkle. Because the gas follows the oil, a producer’s drilling schedule can drive its future gas volumes. That matters for acreage dedications, minimum volume commitments and deficiency payments. A producer with a strong oil program may push more gas into a weak market than it expected. One that slows drilling may struggle to meet commitments it made when its plans looked different. The definitions of committed gas, delivery points, minimum volumes and shortfalls can decide who pays.

Next, curtailment and shut-in rights. With a conventional gas well, an operator can consider shutting in production instead of selling at a loss. Associated gas is harder, because curtailing the gas can mean curtailing the oil well that produces it. The operator has to weigh the gas contract, any acreage dedication, the oil and gas lease, and operational or regulatory limits on what it can do with the gas.

Some leases let the lessee hold the lease through shut-in royalty payments if certain conditions are met, but the trigger language, payment mechanics and time limits vary widely. Don’t assume force majeure will rescue you. Under Texas law, the analysis starts with the language the parties negotiated, and economic hardship or a bad market, standing alone, generally isn’t enough to excuse performance unless the clause covers that situation.

Service companies face their own version of this. Baker Hughes counted 598 U.S. rigs working on October 2, 49 more than a year earlier, so drilling activity is up from this time last year. The mix matters, though: 456 were oil-directed, 133 were gas-directed and nine were miscellaneous. An oil-focused customer and a gas-focused customer can be in very different positions. If a contract ties you to a gas-weighted customer, review the minimum commitments, standby charges, early-termination rights and payment protections.

Finally, long-term supply agreements. LNG contracts can be priced off Henry Hub, tied to oil, or built on a hybrid. When gas and crude prices pull apart, that choice matters a great deal. Check the price-adjustment provisions, volume tolerances and the remedies that kick in when volumes change. A deal evaluated when EIA expected $4.59 gas in 2027 may look different against the agency’s current $3.28 forecast.

What to Watch

EIA releases its next Short-Term Energy Outlook on October 6, and the weekly storage report follows on October 8. Both will show whether inventories are tracking the current forecast and whether EIA changes its 2027 price projection again.

The numbers will keep moving. The contracts won’t, unless somebody changes them. Pull the ones that touch gas and read the pricing, curtailment and termination provisions before winter gets here.