Noreva Evaluates Risks to US Natural Gas Supply, Industrials

What the NGI coverage examined

Petrochemical plants, LNG terminals, refineries, and large manufacturers along the Texas Gulf Coast depend on continuous water for cooling, processing, and production. NGI asked how long those facilities can run normally as reservoirs draw down, and what a slowdown would do to gas demand, given that the petchem sector uses natural gas as feedstock for ethylene, propylene, and butadiene.

The reporting anchored the question in the following data (NGI, Nov. 24, 2025):

• The Texas Water Development Board’s 2022 State Water Plan warned the state could face severe shortages by 2030, with groundwater availability projected to drop 25% by 2070.
• Texas industrial natural gas consumption averaged roughly 5.8 Bcf/d in November 2025, down from 6.1 Bcf/d in January of that year (EIA, via NGI).
• In the 2022 drought year, industrial demand averaged 5.4 Bcf/d through August (NGI analysis) and fell to 5.16 Bcf/d in September 2022 (EIA, via NGI).
• Spot prices spiked over that 2022 window: Houston Ship Channel reached $8.665/MMBtu in September 2022, Tennessee Zone 0 South rose to $8.545 from $4.020, and Waha climbed to $7.950 from $4.565 (NGI Bidweek Historical Data).
• By comparison, on November 21, 2025, Houston Ship Channel averaged $3.895, Tennessee Zone 0 South averaged $3.745, and Waha settled at negative 99.0 cents (NGI).

The 2022 comparison is the analytically awkward one. That year combined drought with post-Covid capital discipline, so attributing the price move to water alone was never clean.

Gardett’s assessment was that the demand-destruction scenario requires conditions far outside the observed range. On the long-term petchem case: “Over the long term, if water constraints were severe enough to meaningfully lift gas prices for years, petrochemical producers could face incentives to adjust feedstocks or focus on higher-margin specialties.”

He stressed to NGI that such a scenario would require an “off-the-charts” water crisis. On the supply side, he was direct about the history: “Hydraulic fracturing is extremely water-intensive, and this has been something Texas has struggled with since fracking became widespread.”

Water has nonetheless never been the ultimate constraint on production, he told NGI, because producers have an adjustment path. Recycling produced water remains available even under tight conditions: “It is expensive and lifts operational costs, and thereby puts upward pressure on gas pricing. But it can be done if concerns about water supply become intense enough.”

At prevailing prices, though, the economics do not support it: “Gas prices are too low to justify the cost of recycling water, which is generally more expensive than simply piping it in. Sometimes that math flips or authorities just limit how much water gas companies can use, but with relatively low gas prices any restrictions to water supply would probably mean they’d just cut fracking at the margin rather than recycle water.”

On the industrial demand side, he drew on a long observation window: “In 25 years, I’ve never heard of petchems shutting in because of water constraints related to gas production, and none of the big petchem facilities are captive to live production flows in that way.”

The reason is structural. US pipelines and cavern storage, he noted, “will continue to run, even in a potentially dire emergency water shortage.” Physical delivery is decoupled from live wellhead flows.

Why the regulatory risk outranks the hydrological one

Gardett’s substantive contribution was to relocate the risk. He told NGI that potential regulatory shifts may ultimately matter more than hydrological limits, pointing to the US Supreme Court case NGI identified as Chevron v. Louisiana, whose oral arguments were expected in January at the time of the reporting, and which could reshape the balance of federal and state authority over oil and gas development: “If the court rules on behalf of the state, Texas could conceivably take more direct action to limit water use in natural gas production or otherwise account for water usage.”

Such policy shifts, he emphasized, could have more immediate implications for producers than water scarcity alone.

That distinction changes how the risk should be modeled. Drought is a slow, continuous variable that producers absorb through cost. A jurisdictional ruling is a discrete event with a date attached, and it can impose a hard constraint on completions in a specific basin regardless of what the reservoir levels say. The first belongs in a cost curve. The second belongs in a scenario.

Update, July 2026. The case, docketed as Chevron USA Inc. v. Plaquemines Parish, was argued on January 12, 2026 and decided on April 17, 2026. The Court ruled 8-0 for the oil and gas companies, returning the suit to the federal courts. The conditional Gardett described, a ruling on behalf of the state, did not arrive, so that particular route to direct Texas action on water use in gas production did not open. The method holds even though this specific scenario resolved the other way: the jurisdictional question moved from open to settled in five months, while the reservoir levels behind the original story moved hardly at all.

For producers, marketers, and the desks pricing Permian and Gulf Coast basis, that is the practical read. Noreva’s fuels coverage builds transaction-aligned gas curves with the hub-level basis detail where a completions constraint would actually show up first, and treats regulatory outcomes as scenario inputs rather than background noise. Waha settling negative on the Friday before the water story ran is a reminder that basin-level constraints and basin-level pricing are not moving in the direction intuition suggests.