NG; September Futures at $2.766 as Production Matches the December Record — Resistance $2.872, Support $2.682

Gas Bounces Off a Three-Month Low as September Takes Over

Natural gas futures traded $2.766 on Friday against a prior settle of $2.722, up roughly 1.6% inside a $2.681 to $2.776 band. That recovery comes off the lowest print in three months and leaves the contract down 10.95% over the trailing year against a 52-week range of $2.483 to $7.827.

The August contract expired Wednesday, and September took over as prompt. Prices rebounded from a three-month nearest-futures low on fund short covering into that expiry, then held the bounce through Thursday's storage report and into Friday.

The breakdown that produced the low was clean. Gas sliced through the $2.989 swing high from late last month, cut the rising trend line connecting the July lows, and found footing near $2.682. The contract is now testing the underside of a former support zone that has flipped into resistance.

Every fundamental input turned bearish inside three weeks. Lower 48 dry gas production averaged 110.6 Bcf/d across July, up from 110.0 Bcf/d in June and matching the record monthly high set in December 2025, with one session printing 110.9 Bcf/d — a 2.5% year-over-year increase. Working inventories closed the week ending July 24 at 3,084 Bcf, sitting 185 Bcf or 6.4% above the five-year average of 2,899 Bcf. LNG flows to export terminals softened to 17.2 Bcf/d in July from 17.4 Bcf/d in June on Freeport maintenance. And weather models flipped cooler across the eastern two-thirds of the country.

The Commodity Weather Group now calls for normal to below-normal temperatures across the central and eastern United States through August 7, which removes the cooling-demand catalyst that had propped prices during the heat wave earlier in the month.

The technical read matches. The 100-day simple moving average sits below the 200-day and the daily buy/sell signal reads Strong Sell.

What keeps this from being a straightforward short is the back of the curve. The EIA's July Short-Term Energy Outlook projects Henry Hub averaging close to $3.70/MMBtu across 2026 with the prompt contract at $2.77, and winter forwards at Cove Point have been climbing while the front month collapsed. The market is pricing a summer glut and a winter squeeze simultaneously.

Contract specifications matter for sizing. Each NYMEX natural gas contract represents 10,000 MMBtu, the tick is 0.001 worth $10, and each full point is worth $10,000.

A 28 Bcf Injection Against a 37 Bcf Consensus

Thursday's storage report was the only genuinely bullish data point of the week, and it arrived small.

The EIA reported a 28 Bcf net injection for the week ended July 24, bringing working gas in storage to 3,084 Bcf. Consensus had looked for a 37 Bcf build, and the five-year average for the comparable week is 26 Bcf. Futures settled higher on the print.

The trajectory across July shows how the surplus accumulated before this week corrected it. Storage rose 61 Bcf for the week ending July 3 to 2,983 Bcf. It added 43 Bcf to reach 3,024 Bcf for the week ending July 10, sitting 181 Bcf above a five-year average of 2,843 Bcf. It gained 32 Bcf to 3,056 Bcf for the week ending July 18, 183 Bcf above 2,873 Bcf. The 28 Bcf figure for July 24 continues the deceleration.

Injections shrinking from 61 to 43 to 32 to 28 Bcf across four consecutive weeks is the pattern bulls need, and it happened during the heat wave that broke ERCOT load records with widespread highs in the upper 80s to 100s and some 110-degree readings.

The problem is that the surplus barely moved. Storage sits 185 Bcf above the five-year average, holding the surplus at 6.4% — the same figure that applied as of July 17. Four weeks of below-average builds did not shrink the cushion in percentage terms because the base kept rising alongside it.

Year-over-year the picture is marginally tighter. Stocks declined 32 Bcf against the same week last year, which is the first meaningful year-on-year deficit the market has produced in months.

The EIA's forward projection frames the season. The agency forecasts working inventories reaching 3,966 Bcf by the end of October, 5% above the five-year average, with inventories remaining above average through much of the forecast period and limiting upward price pressure. End-of-June stocks were 6% above the five-year mark.

Getting from 3,084 Bcf on July 24 to 3,966 Bcf by October 31 requires roughly 882 Bcf of net injections across fourteen weeks — an average of 63 Bcf per week against a July run rate closer to 40. That math assumes the heat breaks and demand falls off, which is exactly what the current forecasts show.

Entering winter with a 5% cushion above normal is the single largest structural cap on any rally.

Production at 110.6 Bcf/d Matches the December Record

Supply is the reason every bullish catalyst this summer has failed to hold.

Lower 48 dry gas output averaged 110.6 Bcf/d across July, up from 110.0 Bcf/d in June and matching the record monthly high set in December 2025. A single session printed 110.9 Bcf/d, running 2.5% above the year-ago level. The EIA raised its 2026 production forecast to 111.2 Bcf/d earlier this month.

That is record supply arriving in the middle of a heat wave, which is why storage kept building through the hottest weeks of the year.

The rig count says the surge is not accelerating from here. Rigs held unchanged at 126 last week, below February's 134-rig high. Producers are generating record volumes on fewer rigs, which is the signature of drilled-but-uncompleted inventory being worked down and of Permian associated gas rising alongside oil activity.

That last point matters more than it usually would. Brent closed July at $90.36, up 22% on the month, and WTI at $85.41. Oil at $90 keeps Permian drilling economics strongly positive, and Permian associated gas comes out of the ground regardless of what Henry Hub does. A gas producer facing $2.77 can shut in. An oil producer facing $85 crude cannot, and the gas comes anyway.

The EIA has flagged that dynamic directly, noting that inventories remain relatively high because record production, led by growth in the Permian region, helps meet rising demand.

Production forecasts for next year extend the pressure. The agency models 118.9 Bcf/d for full-year 2026 on its broader measure and 124.0 Bcf/d for 2027, with Lower 48 output having averaged 117.2 Bcf/d in the first quarter — up 4% year over year.

The one variable that could break the supply argument is a Gulf Coast weather event. Tropical Storm Bertha was flagged as a short-term risk earlier in the month, and any disruption to Gulf Coast infrastructure cuts both ways — it can shut in production, but it can also shut in export terminals, which leaves more gas at home and turns a weather rally into another storage build.

At 126 rigs producing 110.6 Bcf/d, the marginal barrel of supply is not price-sensitive at current levels.

LNG Feedgas Softened at Exactly the Wrong Moment

The demand channel that was supposed to absorb the surplus went the other direction in July.

Gas flows to major U.S. export terminals averaged 17.2 Bcf/d so far this month, down from 17.4 Bcf/d in June, with scheduled maintenance at Freeport LNG's Texas facility carrying most of the shortfall. Golden Pass has produced its own operational swings, and the combination clouded nominations at exactly the point in the season when export pull matters most.

Individual sessions have shown what the system can do when it runs clean. Net flows reached 17.9 Bcf/d on one day, up 7.9% week over week, and BNEF estimated 19.3 Bcf/d on a separate session earlier in the summer. Wood Mackenzie projected exports averaging 18.5 Bcf/d during a June window, not far from records north of 20 Bcf/d and more than 3 Bcf/d above year-earlier levels.

The gap between 17.2 and 20 Bcf/d is roughly 2.8 Bcf/d of demand that exists in the infrastructure but is not currently flowing. Over a four-week period that is nearly 80 Bcf — meaningful against a 185 Bcf surplus.

The EIA projects LNG exports at 16.7 Bcf/d for 2026 against 15.1 Bcf/d in 2025, which the current run rate already exceeds. Export capacity additions from Plaquemines and Corpus Christi Stage 3 were the basis for Goldman Sachs raising its 2026 Henry Hub forecast to $4.15/MMBtu in January.

One analyst framing captures the tension: storage remains above average today, but strong LNG exports could quickly erase the surplus by fall. That is the bull case in a sentence, and it depends entirely on maintenance ending and terminals running at capacity through the injection season.

The international dimension is now unusually complicated. QatarEnergy has extended force majeure on LNG deliveries, which reshapes global supply over time without moving Henry Hub on any given day. The Strait of Hormuz carries approximately 93% of Qatar's LNG exports and 96% of the UAE's — together about 19% of world LNG trade — and throughput sits at 30% to 35% of pre-war levels.

Qatar dispatched its first LNG cargo through the waterway this week, a genuine de-escalation signal given that laden LNG carriers are the highest-value assets any owner sends through a contested channel.

The Weather Turned and Took the Rally With It

Cooling demand was the only thing holding the front month above $3.00, and the models flipped.

The Commodity Weather Group said forecasts call for normal to below-normal temperatures across the central and eastern United States through August 7. That is a direct reversal from the shift hotter that had covered July 27 through July 31 with above-normal temperatures across the central U.S., when NatGasWeather called for widespread highs in the upper 80s to 100s and some 110-degree readings.

The physical market confirmed the heat while it lasted. ERCOT broke load records and cash prices strengthened across the West, which told traders the temperature was reaching burners rather than sitting on a model. Regional spot prices firmed on intensifying heat in the West and parts of the South.

Then it went away, and updated forecasts pointing to cooler weather across the central and eastern U.S. in the coming weeks reduced expected air-conditioning demand and pressured prices directly into the three-month low.

August is the last month of the year where weather can materially change the storage trajectory. Injection season runs through October 31, and roughly fourteen weeks of builds remain. A hot August pulls gas into power burn and slows the builds. A normal-to-cool August lets the surplus rebuild toward the EIA's 3,966 Bcf October target.

The medium-term risk skews bearish. Speculation around a powerful El Niño pattern developing is a recognized headwind for winter heating demand, and El Niño winters in the U.S. have historically produced milder conditions across the northern tier where residential heating load concentrates.

Weather is the only variable in this market that cannot be forecast beyond two weeks with useful confidence, which is why the front month carries the volatility it does while the back of the curve barely moves.

Wholesale electricity prices are forecast lower this summer than last, primarily on lower delivered gas costs to power plants, though the EIA flagged that heat waves could still cause price spikes.

What the Curve Remembers About January

The reason nobody wants to be aggressively short natural gas into winter is seven months old and still fresh.

Henry Hub averaged $7.72/MMBtu in January 2026, rising sharply from December's $4.26 average and marking the highest nominal monthly average since September 2022. On a daily basis, the hub set a nominal record of $30.72/MMBtu on January 23. Winter Storm Fern intensified heating demand while production declined on temporary well freeze-offs.

For the week ending January 30, the combination of demand and lost supply produced a 360 Bcf withdrawal — the largest storage draw on record. The full withdrawal season took 2,020 Bcf out of inventory.

The collapse afterward was equally violent. The February contract settled at $7.46/MMBtu on January 28 while March closed at $3.73 — the largest front-to-second-month spread since at least 2014. On February 2, the new March prompt contract fell 25.7% to $3.24, its largest one-day decline in thirty years. February averaged $3.62.

That sequence is why the forward curve carries the shape it does. As of the spring, the strip showed April near $3.03, July near $3.43, November near $3.86, December near $4.70, and January 2027 near $5.10. The market is pricing seasonality rather than a continuous shortage — softer spring, firmer summer, and a clear winter premium.

Forward prices for winter at the Cove Point hub in Maryland have been described as on fire, which is the same signal from the demand side of the pipeline network rather than the supply hub.

At $2.766 for September against roughly $4.70 for December, the front-to-winter spread is approximately $1.93, or 70%. A trader short the prompt is short the cheapest month on the board.

The structural read is that record production caps the summer while storage carryover determines whether the winter premium is justified. Entering November with 3,966 Bcf and a 5% cushion means the market can absorb a normal winter. It cannot absorb another Fern.

Data Centers Are the Demand Story Nobody Can Yet Quantify

The structural bull case for gas has shifted from LNG to power, and the evidence is showing up in infrastructure rather than in price.

Energy Transfer's Green Chile Project faces a longer approval path after federal regulators moved the New Mexico lateral out of fast-track review, potentially delaying a decision until December. That line is intended to supply Oracle and OpenAI's Project Jupiter data center campus.

That single project captures the entire thesis. AI compute requires firm, dispatchable power at scale, and the fastest path to firm power in the United States runs through gas turbines. Every hyperscaler capex announcement — and four of them guided to $720 billion to $745 billion of combined 2026 capital projects — implies electrical load that does not exist yet.

Expand Energy, the largest natural gas producer in the country, boosted its Haynesville Shale footprint specifically to position for fast-growing Gulf Coast power, industrial and LNG export markets. Haynesville sits closer to Gulf Coast demand centers than Appalachia and has been the swing basin for both LNG feedgas and industrial load.

The producer complex reported through this week. CNX Resources and National Fuel Gas both posted results on July 30, alongside DT Midstream on the infrastructure side and NextDecade's second-quarter investor update on the export side.

International contracting continues to lengthen. Uniper, one of Germany's largest gas traders, signed a long-term offtake deal for LNG from the proposed Ksi Lisims project in British Columbia, deepening a Canada-Germany energy relationship as both pursue supply diversification.

The timing problem is what separates the thesis from the trade. Data center load arrives across 2027 through 2030. Pipeline laterals face regulatory review that just pushed one decision to December. LNG trains take years. None of that helps a September contract at $2.766 with storage 6.4% above normal.

The economic landscape for the next wave of U.S. LNG export projects is also getting harder, with developers facing more expensive Henry Hub prices in their project economics than the original wave assumed.

Structural demand is real and it is slow. Record production is real and it is now.

Forecast Dispersion: $2.83 to $5.00

The published range on natural gas is wide and the revisions this year have been aggressive in both directions.

The EIA's July Short-Term Energy Outlook, released July 7 with the forecast completed July 1, projects the Henry Hub spot price averaging close to $3.70/MMBtu in 2026 before declining below $3.50/MMBtu in 2027. Record U.S. production helping meet rising demand is cited as the source of moderate downward pressure.

Earlier iterations show how much has moved. The agency maintained a full-year 2026 average of $3.50/MMBtu with the second quarter at $2.83, while cutting its 2027 forecast 11.5% to $3.18 from $4.60 on stronger-than-expected storage builds and production growth. A separate March base case had 2026 at $3.76 against $3.53 in 2025.

Bank forecasts sit higher. Goldman Sachs raised its 2026 Henry Hub target to $4.15/MMBtu in January, citing a colder-than-expected winter tightening storage and LNG export growth from Plaquemines and Corpus Christi Stage 3. Morgan Stanley carries a structural target near $5, which technical channel work places at the upper boundary and describes as reachable only under a significantly colder-than-normal winter.

The mid-range of that channel sits around $4/MMBtu, identified as the most likely destination heading into winter 2026-27.

On the downside, a sustained close below $3 opens the path toward $2/MMBtu — a level most analysts view as unsustainable given LNG export dynamics but possible in a severe warm-winter scenario. The front month has already broken $3 and traded to $2.681.

The gap between the EIA's $3.70 full-year 2026 average and a September contract at $2.766 is roughly 34%. With seven months of the year already recorded — including a January that averaged $7.72 — the remaining months have to average considerably lower for the annual figure to land near $3.70, which the current strip already implies.

The forecast that has aged best is the seasonal one. Nobody is calling for a summer squeeze. Everyone is pricing a winter premium. The disagreement is entirely about how much carryover storage neutralizes that premium.

Analysts describe a much larger breakout as requiring a weather shock, a bigger LNG surprise, or a sharper-than-expected slowdown in supply growth. None of the three is currently present.

The Producer Complex and the Leveraged ETFs

The equity and fund side of this market shows how positioning has adjusted to the front-month collapse.

Expand Energy — the largest U.S. natural gas producer and the successor entity to Chesapeake — has been adding Haynesville acreage to serve Gulf Coast power, industrial and LNG demand rather than betting on Henry Hub. EQT, Coterra and the broader Appalachian complex face the same calculus: production economics at $2.77 are marginal for dry gas, and the equity market has been rewarding basin position and takeaway access over volume growth.

Cheniere sits on the other side of the spread entirely. As the largest U.S. LNG exporter, lower Henry Hub feedstock costs expand the arbitrage against international delivered prices, which is why export names and producer names have decoupled through the summer.

The fund complex is where retail positioning concentrates and where the structural cost is highest. The unlevered U.S. natural gas fund tracks front-month futures and carries the full weight of contango when the curve is upward sloping — and at $2.766 for September against roughly $4.70 for December, the roll cost is severe. The 2x long and 2x inverse products compound that daily.

A trader holding the long leveraged product through a $2.989 to $2.681 breakdown lost roughly twice the 10.3% move plus roll and decay. The inverse product delivered the mirror image. Neither is a position to carry into a weather event.

The 52-week range on the futures — $2.483 to $7.827 — quantifies why. That is a 215% spread inside twelve months on the underlying, which means leveraged exposure to this contract is closer to an option than to a directional holding.

Rig count at 126 against February's 134 tells you producers have already responded to price without capitulating. A drop below 120 would be the first genuine supply-side signal, and it has not happened.

The Permian complication runs underneath all of it. Associated gas from oil-directed drilling arrives regardless of Henry Hub, and with Brent at $90.36 and crude up 22% in July, that drilling is not slowing. Waha basis has traded deeply negative for exactly that reason, averaging $1.811 in one recent session against Henry Hub cash near $3.086.

The Technical Map: $2.799 Caps and $2.682 Floors

The chart is a confirmed breakdown attempting its first retracement, and the Fibonacci levels are precise.

Natural gas broke sharply from the $2.989 swing high late last month, slicing through a rising trend line that connected the July lows and confirming a shift in short-term momentum. Price found footing near $2.682 before staging the current recovery, and the contract is now testing the underside of a former support zone that has flipped into resistance.

The retracement drawn from the late-July high to the recent low sets the ceilings. The 38.2% level sits at $2.799, coinciding with the shaded broken-support region. The 50% level lines up at $2.836. The 61.8% level comes in at $2.872, close to where the 100-period simple moving average is curving lower as dynamic resistance.

That $2.872 convergence — Fibonacci plus moving average — is the level that separates a dead-cat bounce from a genuine reversal. Clearing it puts $2.989 back in play, and above that the $3.00 handle that contained trade through most of July.

Support is layered and close. The $2.722 prior settle is immediate. Below it, $2.681 marks Friday's low and $2.682 the recent floor. A break there opens the 52-week low at $2.483, which is 10% below spot and the last defined level before the $2.00 handle that analysts describe as unsustainable given export economics.

The moving average structure is unambiguously bearish. The 100-period SMA sits below the 200-period, keeping the path of least resistance pointed lower, and the daily buy/sell signal reads Strong Sell.

Volume at 42,877 contracts is moderate for a first full session after prompt-month rollover, which means the bounce is not yet backed by conviction.

The seasonal calendar frames the risk window. Injection season runs through October 31, and the front month has fourteen weeks of storage builds ahead of it before heating demand arrives. Historically the front month bottoms somewhere in the August-to-September window and begins pricing winter risk from mid-September.

The single most useful reference is that a sustained close above $3.00 would invalidate the breakdown entirely and signal the market is repricing the injection trajectory. A sustained close below $2.68 confirms it and targets $2.483.

Forecast: $2.682 Holds or $2.483 Comes Next

The base case into the back half of August is continued range trade between $2.682 and $2.872, with direction set by weekly storage builds rather than by any structural development.

The bear path requires only continuation of what is already in place. Production at 110.6 Bcf/d matches the all-time monthly record, storage sits 185 Bcf and 6.4% above the five-year average at 3,084 Bcf, LNG feedgas has softened to 17.2 Bcf/d on Freeport maintenance, and the Commodity Weather Group calls for normal to below-normal temperatures across the central and eastern U.S. through August 7. The EIA models inventories reaching 3,966 Bcf by October 31, and hitting that number requires roughly 63 Bcf weekly builds against a July run rate near 40 — meaning the agency expects injections to accelerate as heat fades. A close below $2.682 targets $2.483, and El Niño speculation extends that risk into the winter strip.

The bull path needs a specific event rather than drift. Feedgas returning to the 19.3 Bcf/d and 20 Bcf/d levels the system has demonstrated would pull roughly 2.8 Bcf/d out of the domestic balance and erase the surplus by fall. A Gulf Coast tropical system that damages production without shutting export terminals inverts the balance immediately. And a hot August that repeats July's ERCOT-record heat pulls power burn back up. Reclaiming $2.872 opens $2.989 and the $3.00 handle.

The structural picture stays bullish and stays slow. LNG exports guide to 16.7 Bcf/d for 2026 against 15.1 Bcf/d in 2025. Data center load behind projects like the Oracle and OpenAI campus is real and arriving across 2027 through 2030. Winter forwards at Cove Point are climbing while the prompt collapses, and December sits near $4.70 against a September at $2.766 — a 70% premium the market is unwilling to arbitrage.

Targets: downside $2.682, then $2.483, then $2.30 on a confirmed break. Upside $2.799, then $2.872, then $2.989 and $3.20 on a reclaim.

Natural gas closes July at a three-month low with record production, a 6.4% storage surplus, softening export demand and cooler weather ahead — and a forward curve that still pays $1.93 to hold the contract four months out.

That's TradingNEWS