Natural Gas Futures Price Forecast: NG Slides 4.89% to $2.74 as Ceasefire Strips the Export Premium

September and August natural gas futures declined across the entire curve to start the week. The benchmark contract fell to $2.74 per MMBtu on Monday, down 4.89% from Friday's settle near $2.88, sliding through the $2.80 handle to the lowest level since May 8. Over the past month the contract has lost 13.83%. Against the same point last year it is down 10.59%.

That direction is the opposite of every other risk asset Monday, and the divergence is the story. The S&P 500 gapped up and closed the morning flat at 7,411. Gold ran to $4,106 in Asia before fading. Bitcoin touched $65,359 and slipped back. EUR/USD tagged 1.1420 and gave it up. Brent crude collapsed more than 7% below $90. Every one of those markets opened bid on the US-Iran strike pause and then faded. Natural gas opened offered on the same news and never stopped falling.

The reason is structural. For US gas, the Middle East conflict was the bull case. Disrupted Qatari LNG and a closed Strait of Hormuz meant global buyers competing for American cargoes, and that supply-security premium was the only demand-side argument capable of overpowering a domestic surplus. Remove the conflict and what remains is 3,056 Bcf in storage, 111 Bcf per day of production and a cooling season with three weeks left in it.

The early-morning read was blunt: bearish production and LNG readings, plus a shrinking window for meaningful cooling demand, dictated sentiment despite a constructive near-term weather outlook. Contract settlement is days away and peak summer is ending. Both facts cut the same way.

The path here has been a repeating loop all summer. Gas fell to $2.82 earlier in July, the lowest since May, then rebounded above $2.95 on hotter forecasts, cleared range resistance near $2.985 on July 24, pulled back to retest that level as support near $2.925, and has now failed that retest completely and broken to fresh lows. That is the fourth consecutive weather rally sold into a surplus that will not tighten.

The contract split last week told the same story from a different angle: September finished higher by 0.87% while August faded. The market saw something worth defending further out on the curve and nothing worth owning in the prompt.

The Ceasefire That Lifted Every Other Asset Removed Gas's Only Bid

The United States paused an almost two-week air campaign against Iran starting late Friday without formal announcement. Tehran said on Sunday it had halted retaliatory attacks against US allies in the region and would keep refraining as long as Washington maintained its pause. Iranian and Omani officials held talks specifically on shipping through the Strait of Hormuz, raising hopes the transit route avoids further disruption.

For crude, that arithmetic was straightforward relief — Brent fell as much as 8.2% below $90 from Friday's settle near $96.80, and WTI dropped 6.7% to $83.37. For US natural gas the same news works in reverse, and understanding why explains the whole trade.

Henry Hub has spent 2026 largely insulated from the geopolitical premium that repriced global gas. American production is domestic, storage is domestic, and the marginal buyer is a Gulf Coast power generator, not an Asian utility. The only channel through which a Middle East conflict lifts Henry Hub is the export channel: if Qatari cargoes disappear and Hormuz closes, Asian and European buyers bid harder for US LNG, feedgas demand rises, and that pull tightens the domestic balance.

That channel never fully opened. LNG feedgas deliveries have averaged 17.2 to 17.4 Bcf per day so far in July, slightly below June's 17.4, partly on scheduled maintenance at the Freeport facility in Texas. Feedgas eased 3.3% in one week to 17.8 Bcf per day at one point. A supply shock in the Persian Gulf that does not show up in American export volumes cannot support American prices, and it did not.

So the market was holding a premium for an event that was not transmitting to the physical balance. When the strikes stopped, that premium had nothing to defend it. The longer-term case survives — damage to Qatari export infrastructure could eventually pull more US gas into export channels — but it is a 2027 story and it is not in this week's feedgas numbers.

The remaining question is durability, and this is a hold-fire rather than a settlement. Iran-backed Houthi forces claimed weekend attacks on Saudi Aramco-linked facilities at the Red Sea ports of Jizan and Yanbu. If the pause breaks, gas is the asset with the most premium to rebuild.

Storage at 3,056 Bcf Is the Number That Kills Every Rally

The single figure sellers keep returning to is 3,056 Bcf. That was working gas in underground storage as of July 17, after operators injected 32 Bcf during the week. It sits 183 Bcf above the five-year average — a 6.4% surplus — and it has not tightened enough all summer to make anyone uncomfortable on the short side.

The trajectory offers a thin bullish thread. The 32 Bcf build was smaller than the prior week's 41 Bcf, and it followed inventories of 2,922 Bcf for the week through July 10. A decelerating injection pace shows power burn is doing some work. But one smaller build is not a trend, and the print still modestly exceeded historical norms for the period while falling inside the range of major polls. Its immediate impact on prompt-month futures was muted.

Thursday's report is the next real test, and it carries more weight than usual because it captures the hottest stretch of the month. A tight number — anything materially below normal — would be the first genuine evidence that heat and export demand are cutting into the cushion. Another normal or above-normal build and the market goes straight back to selling every weather rally, which is exactly the pattern that has held since May.

The arithmetic of the surplus is what makes it so difficult to erode. With roughly three weeks of meaningful cooling demand remaining before shoulder season, closing a 183 Bcf gap requires sustained withdrawals or near-zero injections across multiple consecutive weeks. Injection season typically runs through October. Even an exceptional August does not mathematically clear the surplus before the market's attention shifts to winter, which is why the front of the curve cannot hold a bid regardless of how hot the maps look.

The comparison with Europe could not be starker. European storage sits at 54.2% full against 65% at this point last year, roughly 23 points below the seasonal average, with injection rates running below the path required to reach the 80% winter target. Two gas markets, one continent apart, are experiencing opposite problems simultaneously — and the physical infrastructure to arbitrage between them is running at capacity.

Production at 111 Bcf/d With the Rig Count Refusing to Blink

The supply side has given bulls nothing, and it has not for months. Lower-48 dry gas output hit 110.9 Bcf per day on one recent Wednesday, running 2.5% above year-ago levels, and touched 111.2 Bcf per day on another, up 3.2% year over year. July production has averaged 110.4 Bcf per day against 110.0 in June. The federal short-term outlook was raised earlier this month to a 2026 production forecast of 111.2 Bcf per day, effectively ratifying the current pace as the new baseline rather than a peak.

The critical detail is drilling activity. The rig count has held steady at 126 with prices sitting below $3 per MMBtu. Producers are not pulling back. In prior cycles, a sub-$3 print triggered visible capital discipline within weeks — deferred completions, curtailed volumes, guidance cuts. That reflex has not fired, and the reason is what the market expects in 2027 rather than what it sees in 2026.

That sets up the central question of the earnings season now beginning. Producers are entering second-quarter reports with spot prices back below $3, and analysts are watching specifically for signals of restraint that could support price outlooks for late 2026 and 2027. Forward 2027 pricing has been described as entering a red zone — high enough to justify growth capital, which is precisely what would cap it.

The bind is self-reinforcing. Every producer looking at a 2027 curve that implies a 33% price increase has an incentive to drill into it now, because Appalachian and Permian associated gas takes months to bring online. Collective anticipation of tightness in 2027 produces oversupply in 2026. That is the mechanism keeping the rig count at 126 while the front month breaks to a three-month low.

For shareholders, the read-through is that the restraint narrative gets tested on conference calls over the next fortnight. If majors guide volumes higher into 2027 strength, the front of the curve has further to fall.

Heat That Sets ERCOT Records and Still Cannot Lift the National Balance

The weather is genuinely hot, and it is genuinely not enough. That contradiction is the defining feature of this summer's gas market.

Forecasts have temperatures running mostly above normal through August 7 and 8. Modelling shifted hotter for the July 27 to July 31 window with above-normal readings across the central United States, and private forecasters have been calling for widespread highs in the upper 80s to 100s with some 110-degree readings. ERCOT is already breaking load records and running heavy summer demand, and cash prices strengthened across the West as the heat reached the physical market rather than sitting in a model.

The demand response is measurable. Lower-48 dry gas demand hit 80.6 Bcf per day on one recent Wednesday, up 6.3% from a year earlier, and electricity output rose 2.0% year over year in the week ended July 18. Texas and the interior West are carrying the load, and the West is expected to stay above normal into early August.

The problem is geography. The Midwest, Great Lakes and Northeast keep getting cooler interruptions that prevent the national picture from lining up. National power burn stays contained even while regional burn sets records, because gas demand is additive across regions and one hot half of the country cannot offset a mild other half. The central heat needs to hold into August and spread east for futures to build genuine follow-through.

Then there is the calendar, and it is the input nobody can trade around. Peak summer is ending. The window for cooling demand to meaningfully draw down a 183 Bcf surplus narrows every session, and the market knows it. That shrinking window was cited explicitly as a driver of Monday's decline across the curve despite a constructive near-term outlook.

This is why the pattern repeats. A hot forecast lifts the bid, the surplus and production bring sellers back, and the net effect over four weeks is a 13.83% decline. Weather is a tactical input in a market where the strategic inputs — supply, storage, seasonality — all point one direction.

LNG Feedgas Stalled at 17 Bcf/d and That Is the Broken Leg

Export demand was supposed to be the structural offset to domestic oversupply, and this month it went the wrong way.

Gas flows to major export terminals have averaged 17.2 to 17.4 Bcf per day so far in July, slightly below June's pace. One weekly reading showed feedgas easing 3.3% to 17.8 Bcf per day. The proximate cause is scheduled maintenance at the Freeport facility in Texas, which is temporary and mechanical rather than a demand signal. But the timing is unfortunate: the one month when global buyers were most desperate for cargoes is the month American export capacity was partially offline.

The forward picture remains the strongest part of the bull case. Federal projections have LNG exports growing 9%, or 1.3 Bcf per day, in 2026 and a further 11%, or 1.7 Bcf per day, in 2027. That growth comes from three facilities ramping: Plaquemines and Corpus Christi Stage 3 continuing toward full operations, and Golden Pass beginning operations this year. Those are contracted, under-construction volumes rather than speculative capacity.

The demand-supply crossover is dated and specific. Supply growth outpaces demand growth by 0.5 Bcf per day in 2026, then falls behind by 1.6 Bcf per day in 2027, driven mainly by feedgas from export facilities reducing storage. That is the arithmetic behind an expected annual average Henry Hub price of just under $3.50 in 2026 falling 2%, followed by a rise to just under $4.60 in 2027 — a 33% increase.

Which is exactly the problem for anyone long the September contract. The tightening is real and it is next year. Between now and then sits a 6.4% storage surplus, 111 Bcf per day of production and the end of cooling season.

The one wildcard that could accelerate the timeline is damage to Qatari export infrastructure. If Ras Laffan capacity is impaired for quarters rather than weeks, Asian buyers who source over 80% of their Qatari volumes under contract must replace them with spot cargoes, and the US is the marginal supplier. That would pull feedgas above 18 Bcf per day and change the domestic balance materially. It has not happened yet.

TTF Is Up 94% Year on Year While Henry Hub Is Down 11%

The gap between European and American gas has become the widest structural dislocation in global commodities, and Monday narrowed it only marginally.

Dutch TTF front-month futures fell to €58.60 per megawatt-hour on July 27, down 7.18% on the day from Friday's close near €63.13, having opened at €63.27. Even after that decline, TTF is up 36.86% over the past month, 56.97% over four weeks, and 74.98% to 93.8% against the same point last year depending on the contract measured. The benchmark recently printed €64.02, its highest since March, after climbing near €63 on Friday.

Henry Hub over the identical windows: down 13.83% on the month, down 10.59% year over year, and now at $2.74.

One market is up more than 90% year on year. The other is down more than 10%. They price the same molecule.

The proximate reason is that Henry Hub front-month prices have remained generally insulated from volatility abroad throughout this crisis. American production covers American demand with a surplus, and the only bridge between the two markets is liquefaction capacity that is fully contracted and running at a rate set by construction schedules rather than by price signals. When TTF trades at €58.60 — roughly $20 per MMBtu — against Henry Hub at $2.74, the arbitrage is enormous and completely uncapturable in the short run. Terminals cannot liquefy faster than their trains permit.

That is the single most important thing to understand about this market. The spread does not close through trade; it closes through capacity additions over years. Golden Pass, Plaquemines and Corpus Christi Stage 3 are how the arbitrage gets monetised, and they arrive on engineering timelines.

The investable consequence is that the spread accrues to the companies holding liquefaction capacity rather than to the commodity. Cheniere raised full-year 2026 EBITDA guidance to a range of $7.25 billion to $7.75 billion and carries more than 40 million tonnes per annum of new capacity in permitting, with shares up 36% year to date. Henry Hub is at a three-month low. Both facts are consequences of the same dislocation.

Europe's Storage Deficit Is the Genuine Crisis in This Market

The bullish case for global gas has nothing to do with American weather. It sits in European storage tanks.

European gas facilities are currently 54.2% full, well below the 65% recorded at this point a year earlier and roughly 23 points below the seasonal average. The injection rate is running below the path required to hit the 80% pre-winter target, and the European regulator has been calling for higher LNG imports precisely because the trajectory does not work arithmetically.

The starting point made it worse. European inventories finished the last winter season at 28% full against a five-year average of 41%, which meant the region entered injection season needing an above-normal refill just to reach normal. Instead it got a supply shock. Reduced flows from the Persian Gulf intensified competition with Asian buyers for available cargoes, and unusually hot European weather simultaneously lifted electricity demand for cooling, raising gas consumption at the exact moment storage needed filling.

Prices reflect the squeeze rather than speculation. TTF has surged more than 45% since the start of July and traded to its highest levels in years. UK gas reached 165 pence per therm at one point, a three-year high last seen after Russia's invasion of Ukraine. The Northeast Asia benchmark hit a one-year high near €43 per MWh.

The scenario ladder from here is well mapped and uncomfortable. A one-month interruption of gas flows through Hormuz would drive TTF and the Asian marker toward €74 per MWh — the level that triggered significant demand destruction during the 2022 crisis. A disruption lasting more than two months would push European prices above €100 per MWh, where industrial demand begins shutting down and macro consequences become severe. For historical scale, European gas peaked at €345 per MWh in August 2022 when Russian pipeline supply was cut.

Monday's 7.18% decline prices a resolution. If the pause holds and Qatari volumes resume, €58.60 is expensive. If it breaks, the repricing has barely started — and this is the one channel through which Henry Hub eventually participates.

Qatar's Shutdown, One Missile, and Fourteen Tankers at Anchor

The event that broke the global gas market was specific and datable. On July 7, the Qatari LNG tanker Al-Rekayyat was hit by missiles on the Omani side of the Strait of Hormuz, suffering an engine-room fire and a days-long risk of explosion. It was the first strike on a Qatari LNG carrier since the war began.

Qatar halted its just-resumed export ramp-up immediately. Roughly 14 tankers anchored off Ras Laffan and transits through the strait collapsed. Ras Laffan and Mesaieed together represent the backbone of Qatari LNG exports, and the country had already declared force majeure on March 4 during an earlier phase of the conflict.

The exposure math is what makes this a global rather than regional event. Europe sources 12% to 14% of its LNG from Qatar. Asian buyers import over 80% of Qatari gas, largely under long-term contract, which forces them into the spot market to replace lost volumes and puts them in direct competition with European buyers trying to refill storage. Two regions bidding for the same shrunken pool of cargoes is how you get TTF up 94% year on year.

The escalation continued from there. The earlier truce broke on July 8, US strikes followed, Washington blockaded Iranian ports from July 15, and Tehran declared Hormuz closed indefinitely. Houthi threats to the Bab el-Mandeb closed the alternate Red Sea route, meaning both chokepoints were compromised simultaneously. Roughly a fifth of global oil and gas moved through Hormuz before the war.

That is the premium unwinding this week, and it explains why Monday's move was violent in Europe and merely bearish in America. TTF held an existential supply-security premium. Henry Hub held a speculative export-pull premium that never materialised in feedgas volumes.

For US gas the honest read is that Qatari disruption remains a genuine medium-term bullish input that could pull American cargoes into export channels at higher rates. It is a 2027 story, it depends on the duration of the outage, and it is not visible in this month's 17.2 Bcf per day.

The Level Map: $2.74 With the Range Ceiling at $2.985 Now Overhead

The technical picture deteriorated decisively Monday, and the sequence matters more than the levels.

Gas broke above range resistance near $2.985 on July 24, pulled back to retest that former ceiling as support around $2.925, and has now failed the retest and broken through the entire structure to $2.74. A failed retest after a breakout is the most bearish resolution available on that pattern, because it traps everyone who bought the breakout and everyone who bought the retest.

Immediate resistance now runs at $2.80, the level breached on Monday's slide, then $2.82, which marked the prior monthly low before the mid-month rebound. Above that sits the $2.925 retest zone, then the $2.985 range ceiling, then the $3.00 psychological handle. Reclaiming $3.00 requires a 9.5% advance from current levels and would need a genuine catalyst rather than a weather revision. Further out, $3.209 and $3.40 marked the resistance shelf that capped the June rally, with $3.40 having been flagged as the crucial technical level at the time.

Support is thinner and less well-defined because the market is at a three-month low. The May 8 low is the immediate reference. Below that, the chart opens toward $2.60 and then the $2.50 area, where longer-term consolidation formed earlier in the year.

The forward curve structure is the more useful signal. September rose 0.87% last week while August faded, and winter contracts gained ground on substantial forecast heat, downwardly trending production readings and a supportive storage print. That divergence says the market is willing to own gas for delivery into the 2027 tightening and unwilling to own it for delivery into the end of this cooling season. Monday broke that pattern by taking the whole curve lower, which is a more bearish development than a front-month decline alone.

Positioning data offers context on how active this market has become. Options average daily volume on the US benchmark surged over 27% year over year in the first quarter to 697,000 lots per day, the highest quarter on record. Liquidity is not the constraint here; direction is.

The Curve Says 2027 Is Tight, Which Is Why 2026 Is Oversupplied

The forward structure contains the entire logic of this market, and it is genuinely coherent rather than confused.

Federal projections have the annual average Henry Hub spot price decreasing about 2% to just under $3.50 per MMBtu in 2026, then rising sharply to just under $4.60 in 2027 — a 33% increase. The mechanism is explicit: supply growth outpaces demand growth by 0.5 Bcf per day this year, then falls behind by 1.6 Bcf per day next year. Demand including exports rises less than 1%, or 0.6 Bcf per day, in 2026 against supply growth of nearly 1%, or 1.1 Bcf per day. In 2027 that reverses hard, with demand growth of 2.5 Bcf per day against supply growth of 0.9 Bcf per day, drawing down storage and pressuring prices upward.

Layer the AI power demand on top and the 2027 case strengthens further. Hyperscaler data centres require gigawatt-scale baseload power, and gas is the practical near-term supply. Major technology companies are signing direct gas supply contracts and gas-fired generation deals on top of existing utility agreements. One thesis circulating this month argues gas becomes the primary bottleneck to the AI buildout, with Appalachian producers holding genuine leverage over hyperscalers and counterparty risk in gas being severely underestimated.

The bond market has already voted. Midstream investment-grade spreads tightened 15 to 25 basis points across 2024 to 2025, with gas-weighted names outperforming oil-weighted peers on exactly this thesis. Pipeline operators on the major Northeast-to-Southeast corridors are seeing tighter capacity and rising rates.

None of that helps the September contract. A market that is confidently long 2027 and structurally short discipline in 2026 produces precisely what the tape shows: a rig count frozen at 126, production at 111 Bcf per day, and a front month at $2.74.

The resolution comes through producer behaviour, and the test is imminent. Second-quarter earnings season is underway with spot below $3, and the specific thing analysts are watching is whether managements signal restraint. Guidance that leans into 2027 strength with higher volumes extends the 2026 surplus. Guidance that defers activity is the first genuine bullish catalyst this market has had since May.

Producers and Infrastructure Are Being Paid While the Commodity Is Not

The equity complex has completely decoupled from the front month, and the split is informative about where the market thinks value accrues.

Cheniere Energy (LNG), the largest US LNG exporter, raised full-year 2026 EBITDA guidance to $7.25 billion to $7.75 billion and carries more than 40 million tonnes per annum of new capacity in permitting. Shares are up 36% year to date. The company monetises the Henry Hub-to-TTF spread rather than the Henry Hub price, which is why a $2.74 print is a tailwind for its feedstock cost and a headwind for nothing.

Williams (WMB) moves roughly a third of US gas and is executing more than $7 billion of power-innovation capital, including a 682 MW behind-the-meter build and a pipeline dedicated to Ohio data centres. Shares are up 24% year to date at roughly 33 times earnings — a multiple that already reflects a great deal of good news and leaves limited headroom.

On the production side, EQT (EQT) declared a $0.165 cash dividend with an August 5 ex-date, and Appalachian peers including Coterra (CTRA) and Range are positioned into the structurally tighter physical market that 2027 projections imply. Antero beat first-quarter earnings by 51%, though it carries realised-price risk if the LNG spread compresses. Note that the operator formerly trading as Chesapeake now reports as Expand Energy following its merger — the ticker in the standing tag set needs updating.

Equipment and infrastructure caught the strongest bid Monday. Baker Hughes (BKR) rose 6.79% to $61.13 after raising its Horizon 2 industrial and energy technology orders target above $45 billion, citing power generation and LNG demand explicitly, and booking three second-quarter awards for a Louisiana LNG facility supporting over 6 million tonnes per annum of added capacity. It closed the Chart Industries acquisition on July 16, adding cryogenic and gas-handling technology.

The exception was Venture Global (VG), down 7.79% to $13.19 — a reminder that project-execution risk still gets punished regardless of the demand backdrop.

The pattern is consistent: capacity and chokepoints are being paid, the molecule is not.

Regional Cash Markets Have Come Apart at the Seams

Beneath the futures headline, the physical market is displaying dislocations that carry real information about pipeline constraints and where demand is actually landing.

The most dramatic is in the Pacific Northwest. Daily Northwest Sumas pricing rocketed from 93.0 cents per MMBtu on July 1 to $2.635 by July 21 — a 183% move in three weeks. Over the identical window, daily Emerson pricing drifted down to $1.335 from $1.790. The spread between those two points has completely inverted.

That inversion is a constraint signal, not a demand signal. Western heat is real and sustained, cash prices strengthened across the West as the physical market absorbed record cooling loads, and ERCOT has been breaking load records. But moving gas to where it is needed requires capacity on specific corridors, and when that capacity is full, regional prices detach from the national benchmark in both directions. Basis blows out where demand exceeds deliverability and collapses where supply is stranded.

Day-ahead physical pricing fell modestly across most of North America on one recent Thursday with Western Canada the notable exception — the same story from the opposite side. Henry Hub spot has been trading close to but not in lockstep with futures, and cash showed signs of softness even during periods when summer weather galvanised demand.

Two conclusions follow. First, the national storage surplus understates regional tightness in the West and overstates it elsewhere, which means a 6.4% headline surplus is a less reliable guide to marginal pricing than it was in prior cycles. Second, the pipeline bottleneck thesis underpinning midstream valuations is visible in the cash market right now rather than being a forward projection — Northwest Sumas at $2.635 while Emerson sits at $1.335 is what a constrained network looks like in real time.

For the front-month trade, this cuts bearishly. Regional heat that cannot be served nationally does not draw down national storage, and the futures contract settles against a Louisiana delivery point where the surplus is concentrated. Western load records are producing western basis, not Henry Hub strength — which is precisely why the hottest July in years has coincided with a 13.83% monthly decline.

Forecast: Bearish Below $2.985 With Thursday's Print the Only Near-Term Catalyst

The base case into month-end is continued weakness between $2.60 and $2.82, with rallies capped at the broken $2.925 retest zone. Assign roughly 55% weight, targeting a close between $2.65 and $2.80. The structure supports it: a 183 Bcf surplus, production at 111 Bcf per day, a rig count frozen at 126, feedgas stalled near 17.2 Bcf per day, and three weeks of cooling season remaining. Monday's failed retest and break across the whole curve is the cleanest technical confirmation available.

The bullish path requires two things in sequence. Thursday's storage report printing materially below normal — genuine evidence the surplus is finally eroding — followed by the strike pause breaking or Qatari outages extending in a way that lifts feedgas above 18 Bcf per day. That reclaims $2.80, then $2.925, and opens $2.985 with the $3.00 handle above. Assign 25%, targeting $3.00 — a 9.5% advance. A producer signalling genuine capital restraint on a second-quarter call would add to it independently.

The bearish path is another normal or above-normal build Thursday combined with the ceasefire holding. That confirms the surplus through the end of cooling season and takes out the May 8 low, opening $2.60 and then the $2.50 area. Assign 20%, targeting $2.55 — 7% lower. August contract settlement this week adds mechanical pressure as positions roll into September.

The trigger checklist, in order: Thursday's EIA injection against the 32 Bcf prior and the 183 Bcf surplus; LNG feedgas breaking above or below 17.5 Bcf per day; whether the central heat holds into August and spreads east; whether the strike pause survives given continued Houthi activity; and producer guidance on 2027 volumes across the earnings calls now underway.

Calendar: August contract expiry mid-week, the EIA storage report Thursday at 14:30 GMT, the FOMC decision Wednesday at 2 p.m. Eastern, and US second-quarter GDP plus June PCE Thursday morning. Producer results run through the next fortnight.

That's TradingNEWS