Associated Gas: The Byproduct That Shale Drillers Can't Give Away

In late August 2024, gas at the Waha hub in West Texas sold for negative seven dollars per MMBtu. Read that again. Producers were paying buyers more than seven dollars to haul away a fuel that heats homes in Boston. The rigs did not stop. Oil kept coming out of the Delaware and Midland basins at record pace, and the gas that rode up the wellbore with it kept looking for somewhere to go. When it couldn't find a pipe, a lot of it went up a flare stack and burned.

This is the central paradox of oil-driven shale. The Permian is an oil play. But you cannot pull the oil without the gas, and in an oil play the gas is frequently a liability rather than an asset.

Where the gas comes from

Associated gas is the natural gas dissolved in and produced alongside crude oil. You don't drill for it. It comes up because it's chemically bound into the reservoir, and once the oil flows, the gas flows too. According to the EIA, associated gas made up 47 percent of total Permian natural gas production in 2024, reaching about 12.5 Bcf/d. Across the five major U.S. oil-producing regions, associated gas accounted for 37 percent of natural gas output in 2023 and 2024, averaging 18.2 Bcf/d last year.

Some plays are even more lopsided. In the Bakken, 67 percent of gas produced in 2024 was associated gas, the highest share of any major region. The pattern is the same everywhere: the gas volume is set by how hard you're drilling for oil, not by whether anyone wants the gas.

That decoupling is the whole problem. In a normal gas market, when prices fall, producers slow down and supply tightens. Associated gas doesn't obey that rule. It's a passenger on the oil train, and the oil train runs on crude economics.

Why the pipes fill up and the price goes negative

Gas takeaway from the Permian is finite. Production has run ahead of pipeline capacity for years, and the basin added more than 2.5 Bcf/d of gas output in 2025 alone. When the mainlines fill, gas trapped in the basin has nowhere to move, and the local price at Waha collapses.

It collapses below zero because storing or holding the gas isn't free either. A producer who can't move his gas would rather pay a marketer a few dollars to take it than shut in a well that's making money on oil. So the price of Permian gas becomes the cost of getting rid of it. Waha averaged below zero a record 49 times in 2024. In 2025 that eased to roughly six sub-zero settlements as new capacity arrived, but the mechanism never went away. In March 2026, pipeline constraints pushed Waha negative for a 25-day streak.

Maintenance makes it worse in a hurry. When spring work on Kinder Morgan's 2.7 Bcf/d Permian Highway line cut its effective capacity to around 2.2 Bcf/d, half a Bcf/d of gas suddenly had nowhere to go. That's how you get record negative stretches: one line goes down and the basin's math breaks.

Negative prices don't stop the drilling

Here's what confuses people outside the business. If gas is worth less than nothing, why keep producing it? Because nobody is producing it on purpose. A Permian well might make its money almost entirely on oil, with gas a rounding error on the revenue side. Paying to dispose of the gas, or burning it, is cheaper than choking back a well that's throwing off crude at fifty or seventy dollars a barrel.

As one industry analysis put it plainly, producers sometimes "pay for someone to take their gas so that they can focus on something more valuable: crude oil." The negative gas price is a rounding cost against an oil-weighted revenue stream. It stings, but it doesn't change the drilling decision.

The relief valve, historically, has been the flare. When the pipe is full and the price is negative and you still won't shut in the oil, you burn the gas at the wellhead. By June 2025 the Permian was flaring on the order of 500 million cubic feet per day, roughly the emissions footprint of 2.2 million cars, and flaring ticked up for three straight months as production outran takeaway.

The regulators and the numbers

Flaring in Texas runs through the Railroad Commission, which grants exceptions to burn or vent gas under Statewide Rule 32. For years critics argued the Commission rubber-stamped nearly every request. That has tightened. The Commission has moved toward ending routine flaring, with a target date that has been pushed toward the end of the decade rather than 2025, and the industry says the rate of flaring has fallen sharply, by around 79 percent by the Commission's own accounting.

The federal layer is the EPA methane rule. The 2024 update to New Source Performance Standards Subpart OOOOb requires tank batteries to demonstrate 95 percent reduction in methane and VOC emissions and constrains routine flaring of associated gas from new wells. How aggressively that gets enforced has swung with administrations, and an April 2026 EPA memo revisited how those flaring limits apply to new oil wells.

The volumes tell a genuinely mixed story. The World Bank's Global Gas Flaring Tracker found the U.S. cut flare volumes by about 400 million cubic meters, or 7 percent, in 2024 even as oil output rose 3 percent, the largest absolute reduction of any country. The Permian led it, with flare volumes down 13 percent and flaring intensity down 15 percent. Globally, though, flaring hit 151 bcm in 2024, the highest in nearly two decades, and the U.S. still sits among the top nine flaring nations.

What actually fixes it

Regulation sets the ceiling on how much you're allowed to burn. Steel in the ground is what lets you stop. The negative-price episodes are pipeline problems, not policy problems, and the fix is takeaway capacity. Matterhorn Express came on in 2024 and helped, but production climbed right past it. The next wave, including Energy Transfer's Hugh Brinson line and the Blackcomb project, was slated for 2026 service. Each new line pulls Waha back off the floor and takes pressure off the flare stack, until oil drilling fills it again.

That's the cycle to watch. Associated gas volume is written by the oil rig count, not the gas price. As long as the Permian is drilled for crude, the gas will keep coming up whether the market wants it or not. The question is never whether there's too much gas. It's whether there's a pipe for it, and whether the flare permit or the disposal check is cheaper than the barrel is worth. Right now, the barrel usually wins.