Natural Gas: The Oversupply Hangover That Won't Go Away
Published: March 17, 2025 Category: Market Intelligence Access: Free
If you work in the oil side of upstream, you might be tempted to skip this piece. Don't. What's happening in natural gas is going to reshape U.S. upstream capital flows over the next three years in ways that affect everyone — including oil-focused operators dealing with associated gas economics.
The headline: Henry Hub averaged approximately $2.20/MMBtu in early 2025. That's near decade lows for gas. The producers who bet their business model on gas prices recovering to $3.50+ are sitting on losses they don't want to discuss publicly. And the structural forces keeping prices suppressed aren't going away on their own — but they are, eventually, going away.
Here's how to think about it.
How We Got Here
The natural gas market has been in structural oversupply since the COVID demand collapse of 2020, with a brief reprieve in 2022 when European energy demand spiked following Russia's invasion of Ukraine and the subsequent LNG export surge. That reprieve masked the underlying problem: U.S. gas production has been extraordinarily resilient even at low prices, driven by Appalachian producers with sub-$1.50/MMBtu breakevens and by associated gas from Permian oil wells that flows regardless of gas price.
When you have the world's lowest-cost gas producers continuing to produce because they're cash-positive even at $2 gas — and then you layer in 2-3 Bcf/d of unavoidable Permian associated gas — the market can't clear. Storage enters the winter season above the 5-year average. A mild winter like 2024-2025 doesn't draw the storage down enough to tighten the market. And you start the year in the position we're in now.
Basin by Basin: Who's Hurting
Appalachia is the most important gas-producing region in the country, and it's under serious pressure. EQT Corporation — the largest U.S. gas producer by volume — curtailed production in early 2024 and has been vocal about the need for market discipline. EQT produces roughly 5.5 Bcfe/d from its Appalachian position; when they curtail even 5-10% of that, it matters to the market.
Range Resources, another major Appalachian operator, reduced its capital program in 2024 and has been explicit that it won't chase production growth into a weak price environment. Coterra Energy — straddling Marcellus gas and Permian oil — has similarly tilted capital allocation toward oil in response to gas weakness.
The Marcellus and Utica formations are genuinely world-class resources. Breakeven on EQT's best Marcellus acreage is around $1.20-1.40/MMBtu — meaning they're still generating positive cash margins at $2.20 Henry Hub, just not attractive returns on capital. The question isn't whether they survive; it's whether they grow, and the answer right now is no.
Haynesville has been hit harder. The Louisiana/East Texas shale basin relies on Gulf Coast pricing and proximity to LNG export facilities — which should be an advantage — but Haynesville breakevens are higher than Appalachian costs, typically in the $1.80-2.30/MMBtu range depending on the vintage and operator. The rig count dropped from approximately 55 active rigs in early 2024 to around 35 by year-end. That's a 36% decline in activity that will eventually manifest as production decline, but not for another 12-18 months given the nature of well decline curves.
The Structural Fix: LNG Export Capacity
Here is where the analysis gets genuinely interesting, and where patience becomes a competitive advantage.
The United States is becoming the world's dominant LNG exporter. The buildout is happening — it's just not happening fast enough for producers who needed $3+ gas in 2024.
Current operational LNG export capacity (as of early 2025): - Sabine Pass (Cheniere): ~30 Mtpa capacity, running near full utilization - Corpus Christi (Cheniere): ~15 Mtpa, operational, expanding - Freeport LNG: ~15 Mtpa, fully operational after 2022 fire restoration - Calcasieu Pass (Venture Global): ~10 Mtpa, in early operations - Sabine Pass and Corpus Christi Train 7 expansions: under construction
Under construction and expected online in the 2026-2028 window: - CP2 LNG (Venture Global): 20 Mtpa, FID taken, construction active - Port Arthur LNG (Sempra/Saudi Aramco): 13+ Mtpa Phase 1, FID taken in 2023 - Golden Pass LNG (ExxonMobil/QatarEnergy): 16 Mtpa, delayed but advancing
The math: each 1 Mtpa of LNG export capacity consumes roughly 130 MMcf/d of natural gas. Add 30-40 Mtpa of new capacity by 2027-2028, and you're talking about 4-5 Bcf/d of incremental demand absorption. Against a U.S. market producing ~103 Bcf/d, that's a meaningful structural shift.
The Timeline for Gas Market Recovery
I want to be precise here, because the timing matters for capital allocation decisions.
2025: Oversupplied. Prices stay range-bound around $2.00-2.50/MMBtu barring a cold winter. Activity stays suppressed in Haynesville and flat in Appalachia. No structural recovery.
2026: The first material wave of new LNG capacity comes online. Demand starts absorbing more production. Prices likely firm toward $2.75-3.25/MMBtu range. Early-mover gas producers who have been holding inventory start to see improving returns.
2027-2028: If CP2, Port Arthur, and the various expansion trains execute on schedule — which is a meaningful if — U.S. LNG export capacity approaches 150-160 Mtpa total. That's a fundamentally different demand picture. Gas at $3.50-4.00/MMBtu is plausible on a sustained basis for the first time since the pre-fracking era.
The risk: Project delays. LNG construction is notoriously prone to schedule slippage. Venture Global's Calcasieu Pass was delayed significantly from original projections. If CP2 or Port Arthur slip by 12-18 months, the supply-demand rebalancing slides accordingly.
The Patience Play
EQT's strategy deserves more credit than it's getting. They're curtailing production at low prices, maintaining balance sheet health, preserving drilling inventory, and waiting for the market to turn. This is rational behavior that's easy to describe but hard to execute when quarterly earnings calls require an explanation for why production is down.
The Appalachian producers with the lowest-cost structures — EQT, Range, Coterra, CNX Resources — are the ones who will be positioned to capture upside when LNG demand pulls the market tighter. The ones who drilled aggressively through the downturn, took on debt, and degraded their inventory will not.
So What?
Gas is bad now. The setup for 2026-2027 is actually compelling — and I don't say that lightly. The LNG export buildout is real, the timeline is visible, and the low-cost Appalachian producers who survive the trough with clean balance sheets will generate exceptional returns when the market turns.
For oil operators: the associated gas situation in the Permian is a near-term drag on economics in areas with Waha exposure. That problem gets better when new takeaway comes online, not when Henry Hub recovers.
For gas-focused professionals: if your operator is living within cash flow, curtailing into weakness, and holding inventory — they're making the right call. Don't confuse current price pain with long-term asset impairment.
The patient money in gas is probably right. The question is whether you can afford to wait.
Crude Intelligence Report — crudeir.com | Upstream. Unfiltered.
