Natural gas prices in Texas plunge deep into negative territory and producers are burning it off, while the rest of the world braces for shortages

Waha spot gas prices in the Permian plunged to -$9.75/MMBtu (could hit -$10) as pipeline constraints create local gluts and flaring is at five-year highs. Producers are holding output because oil economics are attractive—WTI is up ~47% to nearly $100/bbl over three weeks—while the Iran-related disruptions (closure threats to the Strait of Hormuz and damage to two LNG trains in Qatar affecting ~17% of its LNG exports) have spiked global gas prices; European futures jumped ~35% to ~€70/MWh (~>$20/MMBtu), pressuring summer restocking needs after winter drawdowns.

Analysis

Local takeaway constraints create a persistent regional basis that will not correct without either physical capacity additions or forced supply curtailment; that dynamic decouples Permian gas economics from global LNG bid levels and creates idiosyncratic volatility in producer margins and midstream utilization. Companies with oil-dominant cashflows can continue to produce through negative local gas economics, which preserves overall hydrocarbon output and delays any natural rebalancing of local gas supply.

On the global side, structural loss of liquefaction/regas capacity and higher marginal shipping costs raise the threshold price at which U.S. gas can arbitrage into Europe/Asia, making spot LNG volumes a function of vessel/regas availability as much as Henry Hub. That means exporters with existing committed trains and long-term offtakes will capture outsized near-term economics while greenfield projects remain supply-constrained for multiple seasons.

Midstream capex and regulatory risk are the levered outcomes: pipeline builds and brownfield expansions are the predictable market remedy but require 12–36 months to shift flows materially, while ESG-driven flaring restrictions could force near-term curtailments and compress local basis almost overnight. Financial instruments tied to capacity (firm transportation contracts, basis swaps) will reprice before commodity-only exposures, creating a two-tier return profile for investors in midstream versus upstream gas-weighted names.

Monitor three high-frequency indicators as imminent catalysts: storage draw/stock build trajectories versus seasonal norms, publicly announced curtailments or flaring restriction enforcement from state regulators, and real-time LNG shipping/regas outages. Any one of these can produce multi-week reversals in regional spreads and a rapid reallocation of cash flows between E&P and midstream players.

Key Decisions for Investors

• Long Cheniere Energy (LNG) — buy shares or a 12-month call spread (eg. buy 12mo ATM calls, sell 12mo OTM calls) to capture elevated global LNG netbacks. Timeframe 6–18 months. Reward: levered exposure to tight export economics; Risk: feedstock/margin compression and project outages. Target R/R ~3:1 if LNG prices remain > long-run breakeven.
• Pair trade: Long Permian oil-weighted E&P (PXD) / Short Appalachian gas-weighted producer (EQT) — 3–9 month horizon to capture basis divergence normalization. Reward: oil offsets keep Permian free-cash-flow positive while Appalachian names suffer if regional gas stays weak; Risk: broad oil price correction or a sudden European supply shock that tightens all gas hubs. Position size: moderate, hedge 30–50% of directional exposure with oil futures or calls.
• Buy midstream optionality (KMI or TRGP) — accumulate equity or buy 9–24 month call spreads on firms with sanctioned brownfield expansion projects and fee-based contracts. Timeframe 12–36 months. Reward: re-rate as capacity is commissioned and takeaway constraints ease; Risk: execution delays, permitting setbacks, political/regulatory pushback. Expect stable distributable cashflow plus upside from capacity tolls.
• Volatility/hedge: Use Henry Hub calendar spreads and basis swaps — short near-month local basin basis (if available) and long winter Henry Hub futures to monetize seasonality and potential regulatory-driven curtailments. Timeframe tactical: 1–6 months. Reward: capture abrupt basis tightening or winter risk premia; Risk: sitting through carry and contango if spreads don’t move; size as a hedge against physical positions.