NG ($2.919) Clears 50-Day MA as Storage Surplus Shrinks to 3.6% — Upside Toward $3.026 Main Top

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.

Macro and Energy Cross-Currents

The Federal Reserve's first rate hike since July 2023 affects gas through the dollar and industrial demand. The FOMC raised rates by 25 basis points to 3.75% to 4.00% on Wednesday, citing energy-driven price increases and stubborn inflation. Sixteen of 18 officials projected at least one more hike this year. Higher rates slow industrial activity over time, which trims industrial gas demand, one of the three major consumption sectors.

The dollar's move matters for exports. The dollar index touched 100.37 on Thursday, its strongest level since July 31, before easing to 100.08. A stronger dollar makes U.S. LNG more expensive for foreign buyers in local currency terms. With TTF at $28 and JKM at $25 per MMBtu, the spread is wide enough that a stronger dollar does not threaten export economics. It does reduce the margin that importers earn.

Oil is the more direct cross-current. WTI crude fell to $100.55 on Thursday and briefly dipped below $100 as Saudi Arabia outlined plans to restore half of its damaged East-West pipeline capacity within days. Brent traded at $103.05. Lower crude prices reduce the incentive to drill in the Permian over the long term, which would slow associated gas growth. In the near term, oil at $100 still supports aggressive drilling.

Energy inflation links gas to rates. Crude above $100 pushed U.S. consumer prices up 3.4% year over year in August, and diesel hit a record $6.3103 per gallon on Wednesday. Electricity prices feed into inflation through utility bills, and natural gas sets the marginal price of power in much of the country. With Henry Hub below $3.00, gas is a deflationary force relative to oil. That helps the Fed's inflation fight but does not change its hiking path.

Treasury yields affect commodity investment flows. The 10-year Treasury yield fell to 4.94% on Thursday from 5.04% earlier in the week. Lower yields support commodity prices at the margin by reducing the opportunity cost of holding futures positions. Natural gas, with its extreme volatility, is less sensitive to rates than gold, but broad risk-on moves support speculative length.

Energy equities reflect sector sentiment. Energy stocks fell 2.97% on Wednesday, led by oil producers as crude dropped. Natural gas producers are less exposed to the oil price decline. Gas-weighted names benefit from rising power demand and record LNG exports, while associated gas growth from oil producers caps Henry Hub. EQT, Coterra and export terminal operator Cheniere Energy trade on the same demand-supply balance that sets the October contract.

Technical Map: Support at $2.871, $2.831 and $2.805

The daily chart has defined levels. The main trend turned down in late August, with a trade through $2.753 signaling a resumption of the downtrend and a move above the main top at $3.026 required to change the trend to up. The short-term range runs from $2.668 to $3.026. On September 11, October futures closed at $2.831, below the 50-day moving average at $2.871 and inside a retracement zone of $2.805 to $2.847.

Thursday's move changed the near-term picture. At $2.919, October futures trade above the 50-day moving average and above the top of the retracement zone. Clearing the 50-day average after a bullish storage print shows buyers regaining control of the short-term trend. The first support is $2.871, the 50-day moving average, a 1.6% decline from today's price.

The second support is $2.847, the top of the retracement zone. Below it, $2.831, the September 11 settlement, sits 3.0% below today's price. That level marks where futures closed before this week's rally. A return to $2.831 would erase the entire post-storage move.

The third support is $2.805, the bottom of the retracement zone and near the three-week low of $2.80 that October futures hit after the September 10 storage report. From today's price, $2.805 is a 3.9% decline. A daily close below $2.805 would put the bearish trend back in control.

Below $2.805, the downtrend trigger comes into play. A trade through $2.753, 5.7% below today's price, would signal a resumption of the downtrend. The bottom of the short-term range at $2.668 sits 8.6% below. A move to that level would require a combination of fading heat, a sharp increase in weekly injections above the five-year average, and production pushing to new records above 113.8 Bcf/d.

The support structure favors buyers above $2.831. The storage surplus has shrunk for six consecutive weeks, power burn is at a September record, and LNG feedgas is near record levels. A daily close above the 50-day moving average after a bullish print is the strongest technical signal since the October contract topped at $3.026. The test comes next Thursday, when the EIA reports the week ended September 18.

Resistance Stack: $2.96, $3.00 and $3.026

The upside has three layers of resistance. The first is $2.96, the October contract's September 2 close. That level sits 1.4% above today's price. It marks where futures traded before the September 4 storage report sent them lower. Reclaiming $2.96 would put October back at its early-September level.

The second is $3.00, the psychological line that has capped two rallies in eight sessions. On September 10, October briefly broke above $3.00 before reversing sharply lower on an as-expected storage report. On Wednesday, the prompt month's charge toward $3.00 fell short and futures deepened their losses. From today's price, $3.00 is a 2.8% gain. Technical resistance near $3.00 has repeatedly triggered selling.

The third is $3.026, the main top on the daily chart. A move through $3.026 would change the main trend to up and put October futures 3.7% above today's price. That breakout would require either an extension of the late-September heat, another storage print well below expectations, or a production decline back toward the two-month low of 108.4 Bcf/d that was forecast for Tuesday.

Above $3.026, the chart opens toward the calendar 2027 level. With calendar 2027 futures at $3.26, a front-month rally above $3.026 would compress the contango between October and next year. That move would signal the market is pricing near-term tightness more aggressively than long-term supply growth. From today's price, $3.26 is an 11.7% gain, well beyond a normal shoulder-season move.

Each resistance level has a clear trigger. Reclaiming $2.96 needs only a continuation of Thursday's post-storage buying. Breaking $3.00 needs forecasts to shift hotter for late September. Clearing $3.026 needs next Thursday's storage report to show another build below the five-year average and below expectations.

The resistance stack is tight. From today's price, $2.96 is 1.4% away, $3.00 is 2.8% away and $3.026 is 3.7% away. First support at $2.871 is 1.6% away. That balance means small shifts in weather forecasts or production readings can produce clean breaks in either direction. The $3.00 level is where the thesis gets tested.

Three Scenarios: Breakout, Range and Breakdown

The breakout scenario targets $3.026, then $3.26. It requires temperatures to stay above normal beyond September 26, next Thursday's storage report to show another build below 50 Bcf, and production to stay below 112 Bcf/d. LNG feedgas holding near 19.8 Bcf/d with no Gulf Coast storm disruptions would reinforce the move. In that case, October clears $3.00 early next week, breaks $3.026 on the storage report and turns the main trend up. From today's price, $3.026 is a 3.7% gain.

The range scenario is $2.805 to $3.026 through October contract expiration. Heat fades on schedule, weekly builds rise toward 60 Bcf to 80 Bcf, production stays near 112 Bcf/d to 113 Bcf/d, and LNG exports hold near 19 Bcf/d. The storage surplus stabilizes near 3% to 4% above the five-year average. Futures chop between the retracement zone and the $3.00 ceiling, with bullish storage prints lifting prices and record production capping them.

The breakdown scenario targets $2.753, then $2.668. It requires temperatures to turn mild ahead of schedule, weekly builds to exceed the five-year average, and production to push to new records above 113.8 Bcf/d. A Gulf Coast hurricane that shuts LNG terminals would accelerate the move by trapping export gas in the domestic market. A daily close below $2.805 confirms this path. From today's price, $2.668 is an 8.6% decline.

The probability weighting favors the range with a bullish tilt. Six consecutive lean builds have cut the storage surplus from 198 Bcf to 148 Bcf, and Thursday's 44 Bcf print extended that trend. The EIA's end-of-season forecast requires 13.4 Bcf/d of injections, 23% above the five-year average pace. Those facts support prices above $2.831. Record production, the calendar 2027 strip at a four-year low and a mild El Niño winter outlook cap rallies at $3.026.

The calendar sets the checkpoints. The next EIA storage report arrives Thursday, September 24, covering the week ended September 18. Weather model updates through the weekend will show whether late-September heat persists. The October contract expires in late September, rolling open interest into November. The EIA's next Short-Term Energy Outlook is scheduled for October 6.

The largest upside risk is a late-season heat wave combined with an LNG export record. That would keep builds lean into October and force the market to price an end-of-season inventory well below the EIA's 3,969 Bcf forecast. The largest downside risk is a hurricane that shuts Gulf Coast LNG terminals for a week or more. That would add several Bcf per day to domestic supply and flood storage. Natural gas at $2.919 is priced for neither.

Natural Gas Futures Price Forecast Verdict: Bullish Tilt Above $2.831, $3.026 Target

October Nymex natural gas futures trade at $2.919 per MMBtu after the EIA reported a 44 Bcf injection for the week ended September 11, below the 50 Bcf estimate and below historical norms. Total working gas reached 3,298 Bcf. The storage surplus has shrunk from 198 Bcf above the five-year average on August 7 to 148 Bcf on September 4, and was estimated at 3.6% above normal for the latest week, down from 4.8%. Futures cleared the 50-day moving average at $2.871.

The bullish case rests on demand and storage math. Cooling degree days ran 31% above normal, gas-fired power burn is at its strongest September start on record, and wind and solar output fell 11%. LNG feedgas averaged 19.1 Bcf/d with exports pulled by TTF near $28 and JKM near $25 per MMBtu. The EIA's 3,969 Bcf end-of-October forecast requires 13.4 Bcf/d of injections, 23% above the five-year average of 10.9 Bcf/d. Record electricity demand of 4,135 billion kilowatt-hours in 2026, driven by data centers, adds structural support.

The bearish case rests on supply and the curve. Lower 48 production hit 113.8 Bcf/d, up 4.4% from a year earlier. The EIA raised its 2027 production forecast to 116.0 Bcf/d. Producers added 3 rigs and 6 frac spreads, the first gains since July 2. Calendar 2027 futures fell to $3.26, their lowest since February 2022, and the winter strip hit a yearly low on a strong El Niño outlook. October futures failed at $3.00 twice in eight sessions.

The forecast is a range with a bullish tilt. First resistance sits at $2.96, then $3.00, with the $3.026 main top as the breakout target and $3.26 as the extended level. Support holds at $2.871, $2.847, $2.831 and $2.805. A daily close below $2.805 invalidates the bullish tilt and opens a move toward the $2.753 downtrend trigger and $2.668.

The trigger is the September 24 storage report. Another build below 50 Bcf with temperatures above normal through September 26 confirms a break of $3.00 and a test of $3.026. A build above the five-year average, or a Gulf Coast storm that disrupts LNG exports, sends October futures back to $2.831 and $2.805.

Verdict: bullish bias above $2.831, targeting $3.00 near term and $3.026 on another lean storage print, with the forecast invalidated on a daily close below $2.805.

That's TradingNEWS