LNG Export Wave: When the Math Stops Working

01The Setup

US LNG export capacity stood at roughly 14 Bcf/d at the start of 2026. Three projects — Plaquemines Phase 2, Corpus Christi Stage 3, and Rio Grande LNG — will add capacity over the next twenty-four months. The collective addition pushes US LNG export takeaway near 21 Bcf/d by end of 2027. Demand-pull comes from European and Asian markets where the post-2022 reorientation away from Russian supply created durable structural demand for US gas.

The complication: this capacity comes online during a period when US dry gas production is roughly flat to slightly declining — modest decline rates not offset by drilling activity at current price levels — and when domestic gas demand for power generation is growing structurally. More export. Flat production. More domestic demand. The math gets interesting.

02The Data

The Henry Hub forward strip for 2026 through 2028 has firmed roughly 12-18% over the last six months, but the back of the curve (2028-2029) hasn't moved as much. This is the disconnect worth watching. If the demand assumptions underlying the consensus forward curve are right, the back-of-curve pricing is about to update. If they're wrong, it stays flat. Either way, the asymmetry favors buyers locking longer-dated supply at current pricing — limited downside if the curve flattens, meaningful upside if it firms.

Basis differentials in producing regions — particularly the Gulf Coast — have started to compress against Henry Hub as LNG demand pull intensifies. Historic basis relationships from the production-surplus era may not hold when production and takeaway are more closely matched.

03The Implication

Domestic gas prices are connecting more tightly to global gas prices than they were five years ago. When TTF (the European benchmark) or JKM (the Asian benchmark) spikes on a cold winter or geopolitical event, Henry Hub increasingly follows — because marginal US gas can clear into export markets faster than it could before. The volatility profile of US gas is changing, and not in ways that favor buyers who modeled procurement based on the 2020-2023 era.

For commercial gas procurement, the practical implication is that historical relationships between Henry Hub futures and basis pricing in producing regions may compress as export demand pulls more aggressively. Basis-only strategies that worked when production exceeded export capacity may behave differently when the ratio inverts — and it's inverting now.

04The Recommendation

1. Reassess forward tenor. For multi-year procurement decisions, consider the 2027-2028 window carefully. Forward curves are likely to firm as terminals commission and demand materializes. The window to lock 2027-2028 supply at current curve levels is open now and probably narrows through 2026.
2. Watch basis carefully. In high-export-exposure regions (Gulf Coast, particularly), basis differentials should be evaluated against new marginal demand from export pull. Historic basis assumptions are the most likely thing to break first.
3. Plan for volatility. The connection to global gas markets means weather events, geopolitical shocks, and demand surprises elsewhere now flow more directly into US prices. Customers with cash-flow sensitivity to gas price volatility should evaluate hedge structure with that in mind.
4. Stress-test current contracts. A contract priced in 2024 assuming 2020-era basis behavior may have embedded risks the customer didn't price for. Audit before renewal.

The LNG export buildout has been forecast for years. What's changing now is that it's actually happening, on schedule, into a domestic market that's tighter than most procurement decisions still assume.