TITLE: Natural Gas Prints $3.12 and Nobody's Pricing the Back Half
TAG: gas
EXCERPT: 7.72 in January to $3.12 in June… the fastest commodity round-trip of the year just gave back a polar vortex, erased the LNG bid, and priced like abundance is permanent. December futures sit forty cents higher—the curve knows what spot refuses to admit…
IMAGE: natural gas processing plant
BODY:
Henry Hub closed Wednesday at $3.12 per million British thermal units, down more than half from the $7.72 spike in January and trading like the tightest winter in years never happened. The polar vortex is over, the injection season is here, and spot prices collapsed back to levels that assume supply will stay abundant and LNG export demand will stay polite. One problem: December 2026 futures are holding above $4, a forty-cent contango that says the market knows exactly what's coming and spot hasn't figured it out yet.
The curve is the tell—front-month weakness against a bid that starts the moment summer ends. Traders are pricing this like a storage-driven collapse, not a structural shift. Total stockpiles climbed to 2.759 trillion cubic feet, around 1% below last year but 5.8% above the five-year average, and the injection pace has slowed after three consecutive builds. What consensus calls oversupply is a brief seasonal window before LNG export capacity reasserts itself and winter demand pulls every molecule out of storage the market just spent spring filling.
LNG export activity has softened, with average gas deliveries to the nine major US LNG export terminals declining to 17.0 billion cubic feet per day so far in June due to seasonal maintenance at Golden Pass and Freeport. That maintenance is temporary, the capacity additions are permanent, and the EIA expects Henry Hub to average $3.34 per MMBtu in the second half of 2026 and $3.55 in the second half of 2027—a forecast that puts current spot pricing seven percent cheap to where it needs to be by October.
The mechanism here is straightforward: US Lower 48 production has eased to 109.4 billion cubic feet per day in June from 109.7 in May, a modest decline that matters because it's happening while export infrastructure is expanding. US marketed natural gas production is forecast to grow 3.3% in 2026, driven almost entirely by higher associated gas in the Permian region, but that growth isn't keeping pace with the LNG buildout. The Permian produces gas as a byproduct of oil drilling—it's not price-responsive the way dry-gas plays are. When winter arrives and exports ramp back to full capacity, the supply cushion the market is leaning on disappears.
The January spike to $7.72 wasn't noise—it was a preview. Record storage withdrawals and a polar vortex pulled inventory down faster than anyone expected, and spot prices quintupled because the system had no give. That same tightness is being built back into the curve as soon as maintenance wraps and summer shifts to fall. The difference is nobody's paying for it in prompt-month anymore; they're paying for it six months out, where the risk actually sits.
What spot is missing: temperatures are expected to remain above normal through July 1, supporting stronger gas consumption from power generators, and every hot day this summer is a molecule that doesn't make it into storage for winter. The injection season that's supposed to refill the system is running into air-conditioning demand and flattening just as the curve starts pricing scarcity again. By the time the market realizes storage didn't rebuild enough to meet winter plus exports, spot will be back above four and December will be above five.
The contango is the trade—you're buying what the market already knows against what it's pretending not to see. Front-month is priced for abundance that lasts until it doesn't; the back is priced for a winter that behaves like the last one. Somebody's wrong. The curve says it's spot.