October Nymex natural gas futures traded at $2.919 per MMBtu on Thursday after the U.S. Energy Information Administration reported a 44 Bcf injection into storage for the week ended September 11. The build came in below industry expectations of a 50 Bcf injection and below historical norms for the week. Futures were already higher before the 10:30 a.m. ET release and held firmly in positive territory through the morning. Late Wednesday, the continuous contract stood at $2.896.
The print extends a run of lean injections. Over the past six reports, weekly builds have totaled 36 Bcf, 16 Bcf, 15 Bcf, 30 Bcf, 40 Bcf and now 44 Bcf. Heat across the South and a record September start for gas-fired power burn have pulled gas out of the injection stream and into generators. The inventory cushion that has capped prices since March is narrowing week by week.
The surplus numbers show the trend. As of August 7, working gas stood 198 Bcf above the five-year average. By August 14 the surplus was 185 Bcf, by August 21 it was 167 Bcf, by August 28 it was 160 Bcf and by September 4 it was 148 Bcf. That is a 50 Bcf decline in four weeks. Adding Thursday’s 44 Bcf to the 3,254 Bcf reported for September 4 puts total working gas at 3,298 Bcf. Storage was estimated at 3.6% above normal for the week ended September 11, down from 4.8% a week earlier.
The upside has limits. The October contract briefly broke above $3.00 on September 10 before reversing sharply lower. On Wednesday, the prompt month made another charge toward $3.00 that fell short as fading shoulder-season demand weighed on the front of the curve. The main top on the daily chart sits at $3.026. Twice in eight sessions, sellers have defended the $3.00 line.
The thesis for this forecast is precise. The storage surplus is shrinking faster than the futures curve admits. The EIA’s own end-of-season forecast requires injections well above the five-year average pace from here, while the last six weekly builds have run below it. That math supports October futures holding above $2.831 and testing the $3.00 to $3.026 ceiling. Record production, a strong El Niño pointing to a mild winter and calendar 2027 futures at their lowest since February 2022 cap any rally at that ceiling. Natural gas is a range trade with a bullish tilt until either side breaks.
The global backdrop is extreme. European TTF gas hit a post-2022 high on Monday and has traded near 44-month highs around $28 per MMBtu, with Asian JKM near $25. Henry Hub at $2.919 is a fraction of those prices. U.S. LNG exports are running near record levels to capture that spread. Domestic prices remain anchored by domestic supply, but the pull from overseas is the strongest it has been in years.
The 44 Bcf Build and What It Says About Demand
The September 11 print was the most important data point of the week. At 44 Bcf, the injection fell 6 Bcf short of the 50 Bcf industry estimate. That estimate had already risen by 10 Bcf from the prior week’s build, reflecting expectations that heat would ease. The heat did not ease enough. The lighter-than-expected build tells traders that power demand stayed stronger than forecasters modeled.
Weather drove the shortfall. Continental U.S. cooling degree days totaled 71 during the week ended September 11, according to National Oceanic and Atmospheric Administration data. That was 5 cooling degree days fewer than the prior week, but still 31% above normal. Summerlike heat lingered over the South, keeping air conditioners running and gas-fired generators busy.
Renewables made the build leaner. Wind and solar output fell a combined 11% week over week, based on EIA Form 930 data. When wind and solar generation drops, utilities fill the gap with natural gas. An 11% decline in renewable output during a week of above-normal heat pushed more gas into power burn and less into storage.
Power burn is running at a seasonal record. Gas-fired generation across the Lower 48 is off to its strongest September start on record as heat persists across the South. That demand propped up regional spot prices. Southeast natural gas premiums are rivaling winter peaks, and on September 10 early cash prices at several Southeast and Mid-Atlantic locations soared above $7.50 per MMBtu. Spot prices that high in September are a sign of regional tightness, even as the national benchmark trades below $3.00.
Supply pulled back slightly during the week. Lower 48 dry gas production slipped 0.9 Bcf/d to average 111.9 Bcf/d, according to pipeline flow data. Net imports from Canada fell 0.7 Bcf/d to 4.8 Bcf/d. Deliveries to LNG liquefaction facilities averaged 19.1 Bcf/d, up 0.2 Bcf/d. Lower production, lower imports and higher exports all reduced the gas available for storage.
The prior week set up this result. For the week ended September 4, the EIA reported a 40 Bcf injection, above a 34 Bcf forecast but below the five-year average increase of 52 Bcf. That report sent October futures down to a three-week low near $2.80. Thursday’s print reversed that reaction. Two consecutive builds below the five-year average confirm a pattern rather than a one-week anomaly, and futures are responding accordingly.
The Surplus Math: The EIA’s Forecast Needs 13.4 Bcf/d
The EIA’s end-of-season target frames the storage debate. In its September Short-Term Energy Outlook, the agency forecast that working natural gas inventories will total 3,969 Bcf on October 31, 2026. That would be 5% above the 2021 to 2025 average and 1% above October 2025 levels. In August, the agency had projected 3,985 Bcf, which would have been the highest end-of-season total in 10 years.
The math from here is demanding. With working gas at 3,298 Bcf as of September 11, reaching 3,969 Bcf by October 31 requires 671 Bcf of injections over the remaining 50 days. That is 13.4 Bcf/d, or 94 Bcf per week. The last two weekly builds averaged 42 Bcf. To hit the EIA’s target, weekly injections would need to more than double from their recent pace for seven straight weeks.
The five-year average pace falls short of the target. The EIA noted that if injections matched the five-year average of 10.9 Bcf/d for the rest of the refill season, inventories would reach 3,913 Bcf on October 31, 160 Bcf above the five-year average of 3,753 Bcf. The agency’s 3,969 Bcf forecast requires injections 23% faster than the five-year average rate. Recent builds have run slower than that average.
The gap matters for prices. If the season ends at 3,913 Bcf instead of 3,969 Bcf, the market enters winter with 56 Bcf less gas than the EIA projects. If lean builds continue, the shortfall grows. Futures prices for October and November reflect the expectation of a comfortable winter supply position. A storage trajectory that undershoots the official forecast would force a repricing of that comfort.
Shoulder season will test the thesis. Injections typically accelerate in late September and October as cooling demand fades and heating demand has not yet begun. Forecasts show temperatures remaining mostly above normal through September 26, though less extreme than previously projected. If heat fades on schedule, builds should climb toward the 70 Bcf to 90 Bcf range. If late-season heat persists, builds stay lean and the surplus shrinks further.
Regional balances are uneven. The EIA expects inventories to enter the withdrawal season 21% above average in the Mountain region, 10% above in the Pacific, 6% above in the Midwest and 4% above in South Central. The East is expected to enter winter at the five-year average. The national surplus is concentrated in the West, while the East, where winter demand peaks, has no cushion. That imbalance supports East Coast winter premiums even if the national number looks comfortable.
Record Production Caps Every Rally
Supply is the market’s biggest bearish force. Lower 48 dry gas output averaged 113.4 Bcf/d so far in September, above the monthly record of 112.2 Bcf/d set in August. On September 11, output reached 113.8 Bcf/d, up 4.4% from a year earlier. Record production and mild spring weather have kept inventories above the five-year average since March.
The EIA expects production to keep climbing. The agency raised its 2027 dry natural gas production forecast to 116.0 Bcf/d from 115.3 Bcf/d projected in July. That is a 0.7 Bcf/d upward revision in one month. Supply growth of that size absorbs a large share of any demand increase from LNG exports or power generation.
The Permian is the growth engine. The EIA forecasts Permian natural gas production will grow by 1.7 Bcf/d in 2026 and 2.2 Bcf/d in 2027. Most Permian gas is associated with crude oil production. The region’s gas-to-oil ratio averaged nearly 4,200 cubic feet per barrel in 2025, 15% higher than in 2021, so gas output has been growing faster than oil output. Energy Transfer’s Hugh Brinson pipeline began interstate shipments from the Permian in June, earlier than expected, adding takeaway capacity.
High oil prices add to that supply. WTI crude settled at $105.83 on Tuesday, its highest close since May 19, before falling to $100.55 on Thursday. Crude above $100 per barrel encourages Permian drilling, and every oil well brings associated gas with it. The Iran war’s oil price spike is indirectly bearish for U.S. natural gas prices, because it accelerates the associated gas output that caps Henry Hub.
The Haynesville and Appalachia add more. The EIA forecasts Haynesville production will increase by 1.4 Bcf/d in 2026 and 1.3 Bcf/d in 2027, supported by stable Henry Hub prices, proximity to Gulf Coast LNG terminals and nearby industrial demand. Appalachian production is forecast to rise 0.6 Bcf/d in 2026 and 0.3 Bcf/d in 2027.
Drilling activity turned higher. U.S. producers added 3 rigs and 6 hydraulic fracturing spreads last week, the first weekly gain in both measures since July 2. More rigs and frac crews mean more supply in the months ahead. The short-term dip in production during the week ended September 11 was a pause in a rising trend, not a reversal. Daily output readings remain strong but choppy, and production dips have been temporary.
That is why $3.00 holds as resistance. Every time futures approach $3.00, traders price in the supply response that higher prices would trigger. With production at records, rigs rising and the EIA lifting its 2027 forecast, the market does not need higher prices to secure supply. That dynamic caps rallies even when storage data turns bullish.
LNG Exports Near Record as Global Prices Soar
LNG is the strongest source of U.S. gas demand growth. Deliveries to Lower 48 LNG export facilities averaged 19.1 Bcf/d during the week ended September 11. Flows to the nine major U.S. LNG export plants reached a 20-week high of 18.8 Bcf/d on one reading, and averaged 18.3 Bcf/d so far in September, up from 17.2 Bcf/d in August. Feedgas near 19.8 Bcf/d has absorbed a large share of domestic supply.
The global price gap drives those exports. Gas traded near 44-month highs around $28 per MMBtu at the Dutch TTF benchmark and $25 at the Japan-Korea Marker in Asia. With Henry Hub at $2.919, TTF trades at 9.6 times the U.S. price and JKM at 8.6 times. That spread makes every available cargo of U.S. LNG profitable to ship. Tight overseas LNG balances are preserving a strong pull on U.S. exports.
The Iran war is behind the global squeeze. Attacks on energy infrastructure and shipping in the Middle East have disrupted global energy flows. European TTF hit a post-2022 high on Monday before falling 2.54% on Wednesday for a second straight decline. On Thursday, TTF traded under €80 per megawatt-hour after finding support just above €76. Saudi Arabia’s efforts to restore its East-West pipeline and reroute crude eased some energy supply fears across markets.
Export capacity is the ceiling on that pull. U.S. LNG terminals operate near full capacity when global prices are this high. Additional exports require new liquefaction capacity. Houston-based Catarus is expanding its Commonwealth LNG export project in Louisiana, adding five trains and 7.75 million tonnes per year of capacity. Expansions like that increase long-term demand for U.S. gas, but they take years to build.
Maintenance and weather can interrupt flows. Tropical Storm Edouard temporarily closed the port at Sabine Pass in early September, cutting feedgas before a partial rebound. One-day maintenance events at facilities such as Cameron have briefly reduced flows. With hurricane season active, Gulf Coast storms remain a risk to LNG exports. A storm that shuts a terminal for several days is bearish for Henry Hub, because gas that would have been exported stays in the domestic market and flows into storage.
Mexico adds steady export demand. Pipeline exports to Mexico averaged 7.9 Bcf/d in early September. Combined with LNG feedgas near 19.1 Bcf/d, the United States is exporting 27 Bcf/d of gas, equal to 24% of Lower 48 dry production at 111.9 Bcf/d. Exports on that scale make Henry Hub more sensitive to global prices than it was a decade ago, but domestic supply growth still keeps U.S. prices far below international benchmarks.
Power Demand: Heat, Data Centers and Record Electricity Use
Electricity demand is the second pillar of U.S. gas consumption. The EIA expects U.S. electricity sales to reach a record 4,135 billion kilowatt-hours in 2026 and 4,211 billion kilowatt-hours in 2027. The agency attributes that growth to data center development and increased manufacturing activity in the commercial and industrial sectors. Natural gas should maintain its outsized share of U.S. electricity generation because of supply abundance and reliability.
Data centers are a structural demand driver. Artificial intelligence computing requires continuous, reliable power. On Wednesday evening, Generac agreed to supply up to $8 billion of backup generators for Amazon’s data centers, with initial deliveries of $2.4 billion across 2027 and 2028. Many data centers rely on natural gas for primary or backup power. Every new campus adds baseload electricity demand that gas-fired plants are best positioned to meet in the near term.
Weather is the near-term swing factor. Cooling degree days ran 31% above normal during the week ended September 11. Forecasts show temperatures staying mostly above normal through September 26, though less extreme than earlier projections. The warmer weather should keep power generators relying more heavily on natural gas, supporting prices through the end of the month.
Regional heat created extreme spot prices. Southeast natural gas premiums are rivaling winter peaks. Cash prices at several Southeast and Mid-Atlantic hubs traded above $7.50 per MMBtu on September 10. Those prices reflect pipeline constraints that prevent cheap Permian and Haynesville gas from reaching the Southeast fast enough during peak demand. The national benchmark does not capture that regional stress.
Winter expectations are pointing the other way. Winter forward prices sank to their lowest of the year last week as a historically strong El Niño and stout supply pressured the 2026-2027 strip. El Niño winters tend to bring milder temperatures to the northern United States, reducing heating demand. That extends a months-long slide in winter prices that mirrors the pattern of the past three years.
The Northeast remains an exception. New England’s Algonquin Citygate hub traded at its second-largest discount to Henry Hub over the spring and early summer since 1999. Winter is expected to flip that relationship and bring high prices back to the region, where pipeline capacity limits supply during cold snaps. With East region storage forecast to enter winter at only the five-year average, the Northeast carries the most winter price risk in the country.
The Futures Curve: Calendar 2027 at a Four-Year Low
The shape of the futures curve tells traders how the market views supply. Calendar 2027 futures fell to $3.26 per MMBtu last week, their lowest level since February 2022. That price signals the market is not worried about supply meeting demand next year. With October futures at $2.919, the calendar 2027 strip trades $0.341 higher, an 11.7% premium.
That contango reflects storage economics. When the curve slopes upward, traders are paid to inject gas into storage and sell it forward. A 11.7% premium from October to calendar 2027 supports continued injections through the fall. It also shows the market expects prices to rise modestly as LNG capacity expands and winter demand arrives, but not dramatically.
The winter strip is weak. Winter 2026-2027 forward prices reached their lowest level of the year last week. A strong El Niño, record production and above-average storage all point to a comfortable winter. That weakness limits how far the front month can rally, because traders will not pay significantly more for October gas when winter gas is priced cheaply.
The front month is caught between two forces. Near-term heat and lean storage builds support October and November futures. Long-term supply growth and a mild winter outlook pressure the back of the curve. The result is a front month that rallies toward $3.00 on bullish weekly data and sells off when traders look past the current heat to the winter strip.
October contract expiration adds volatility. The October Nymex contract expires in late September, and trading activity will roll into November. November futures typically carry a premium to October because they are closer to the heating season. As open interest shifts, the continuous front-month price can jump when November becomes the prompt contract. Traders should watch the October-November spread for signals about near-term tightness.
Recent contract history shows the range. The September Nymex contract closed at $2.84 per MMBtu on August 26, a $0.07 increase from the prior close, as traders reacted to a 15 Bcf build that came in at the low end of expectations. The October contract closed at $2.96 on September 2. It fell to $2.831 on September 11, then climbed back to $2.919 today. Across three weeks and two contract months, prices have stayed within a $2.80 to $3.03 band.
