(June 30th 2026)
June marked a clear turning point for U.S. natural gas markets as the spring shoulder-season lull gave way to summer cooling demand. Prices firmed steadily throughout the month, moving back above the $3 per million British thermal units (MMBtu) threshold on a sustained basis for the first time since late March, with a severe late-month heat wave in the eastern United States pushing prices to their highest levels since early February. Rising domestic production and above-normal underground storage kept the market well-supplied, but liquefied natural gas (LNG) exports, summer power burn, and ongoing global supply disruptions all began pulling in the other direction. Globally, a U.S.-Iran Memorandum of Understanding signed on June 17 technically reopened the Strait of Hormuz, but commercial LNG shipments have yet to meaningfully resume. In short, the U.S. market exited June meaningfully tighter than it began, with weather, exports, and demand all firming at once.
Bull Factors:
– A severe multi-day heat wave gripped the eastern United States in late June and extended into early July, pushing power demand toward all-time record levels. The U.S. Department of Energy issued emergency orders allowing PJM Interconnection to curtail data centers and waive pollution limits at power plants, with peak demand forecast to potentially exceed the 2006 all-time record of 165,563 megawatts (MW). Real-time wholesale power prices in PJM spiked to $1,334 per megawatt-hour (MWh) on June 23, up from just $52/MWh a week earlier. For U.S. markets, extreme heat events like this force gas-fired power plants, which generate roughly 40% of U.S. electricity, to burn far more fuel, which pulls gas out of storage, tightens supply balances, and pushes both natural gas and electricity prices meaningfully higher.
– Global liquefied natural gas (LNG) supply remained severely constrained despite a nominal easing of the Strait of Hormuz situation. A U.S.-Iran Memorandum of Understanding signed on June 17 technically reopened the waterway, but commercial LNG shipments have yet to meaningfully resume, outbound LNG traffic from Qatar and the United Arab Emirates remains effectively at zero, and total shipping through the strait is running at roughly 5% of pre-war levels. Iran also declared the strait “closed” again on June 20 over Lebanon ceasefire disputes, keeping the situation fragile. For U.S. markets, this sustains a heavy international pull on American gas exports and keeps global buyers reliant on U.S. supply as their primary alternative, which tightens domestic balances and puts steady upward pressure on both natural gas and power prices over time.
– U.S. liquefied natural gas (LNG) export flows continued climbing, averaging 17.3 to 17.4 billion cubic feet per day (Bcf/day) in June, up from 17.1 Bcf/day in May, with record feedgas activity at Golden Pass LNG in Texas driving much of the gain. Corpus Christi Train 6 is scheduled to come online this summer, with additional new capacity from Port Arthur, Rio Grande, and the final Golden Pass train expected next year. For U.S. markets, every additional Bcf/day flowing to export terminals is a Bcf/day permanently removed from domestic supply, which is a structural tightening force that reinforces the market’s expected shift toward higher prices in the second half of 2026 and beyond.
Bear Factors:
– U.S. natural gas production remains at healthy levels near 109.7 Bcf/day and continues to trend higher. The U.S. Energy Information Administration (EIA) now forecasts marketed natural gas production growing 3.3% in 2026 (roughly 3.9 Bcf/day of new supply), driven primarily by rising associated natural gas coming out of the Permian region as high oil prices encourage more crude drilling. For U.S. markets, associated gas from the Permian is a particularly stubborn source of supply because producers can’t easily shut it off, it comes out of the ground alongside oil regardless of gas prices. That reliable supply growth softens the impact of rising demand and caps how quickly prices can rise in the near term.
– Underground storage is comfortably above seasonal norms and building toward a potential record. U.S. working natural gas in underground storage sits roughly 5.7% above the five-year average, and the U.S. Energy Information Administration (EIA) now projects end-of-October inventories to be about 80 Bcf higher than its January forecast, expected to exceed the five-year maximum for the first time in years. The most recent weekly injection of 76 Bcf came in close to the five-year average despite the late-month heat wave, meaning storage kept building even as gas-fired power plants burned more fuel. For U.S. markets, storage is essentially the country’s natural gas savings account, and heading into winter with this much cushion means the market can absorb weather events, unexpected supply disruptions, or export demand surges without the panic-buying that typically drives price spikes. It’s the single biggest reason near-term prices haven’t run harder despite everything else pulling in the tightening direction.
– Looking further out, record-high electricity costs are beginning to lay the groundwork for real demand destruction. The Department of Energy’s emergency orders during the late-June heat wave authorized PJM to curtail data centers during peak grid stress hours, and PJM’s record $329.17 per megawatt-day capacity auction result is pushing commercial and industrial bills up 10-20% this summer. New York is seeing similar pressure, with NYISO’s New York City (Zone J) capacity clearing an all-time high $32.6 per kilowatt-month, more than double summer 2025 levels. In response, large consumers are reducing load, accelerating efficiency investments, and exploring behind-the-meter options like on-site solar and battery storage — with some data center operators even rethinking the pace of new construction in constrained regions. For U.S. markets, this is a longer-term bearish counterweight rather than a near-term price weight, but once these investments are made the demand reduction is permanent. Since natural gas fuels roughly 40% of U.S. electricity, every megawatt-hour of demand that gets shed or self-generated is gas that doesn’t get burned — a slow-building headwind against the demand growth story.
Final Takeaways:
June marked the pivot from spring shoulder season to summer burn season for U.S. energy markets. Natural gas prices firmed meaningfully as cooling demand arrived, LNG exports climbed, and the late-month heat wave gave a preview of the summer’s stress conditions. At the same time, resilient production, above-normal storage, and growing renewable generation kept a lid on how quickly prices could rise. The forward curve continues to point higher into late 2026 and 2027, and with global LNG flows still severely constrained and new U.S. export terminals coming online, most signs still favor tighter conditions ahead. Power markets tell an even more dramatic story. Record capacity auction results in both PJM and NYISO, near-record demand across the eastern United States, and emergency federal orders to curtail data centers highlight just how tight capacity has become in the Mid-Atlantic and Northeast, with Texas facing similar pressures. Data center load growth is now the single largest structural force reshaping U.S. electricity markets.
Sources: U.S. Energy Information Administration (EIA) — Short-Term Energy Outlook (June 2026), American Gas Association — Natural Gas Market Indicators, U.S. Department of Energy — Section 202(c) Emergency Orders (June 30, 2026), PJM Interconnection & New York Independent System Operator (NYISO) — 2026-2027 Capacity Auction Results and Summer 2026 Reliability Assessments.
Charts and graphs sourced from Constellation
