Gas Breaks $2.79 With Nothing Underneath: 110.6 Bcf/d of Production Against Europe Paying 7 Times the Price

Natural gas traded at $2.65 per MMBtu Friday, up 0.54% from Thursday's settlement, after tumbling to a 3.25-month nearest-futures low the prior session. The prompt-month contract entered Friday risking a seventh consecutive weekly loss. Over the past month the benchmark has fallen 17.36%, and it sits 11.23% below where it traded a year ago.

The Henry Hub last-day financial contract printed 2.654, down 1.56% across the prior 24 hours, on open interest of 29,940 contracts. The technical rating on that instrument reads sell.

Thursday's decline came on the storage report. The EIA reported a 33 Bcf net injection for the week ended July 31, landing on the heavier side of consensus at 30 to 31 Bcf, well above last year's 13 Bcf build for the comparable week and materially above the five-year average injection of 23 Bcf. Losses were contained only because weather models shifted warmer, with above-average temperatures expected across the Northeast and western United States through August 10 and mostly above-normal readings running through August 21.

Put the trajectory in context. Prices declined below $2.70 on July 30, reaching their lowest level in more than three months at that point. They have not recovered since. The short-term range has been $3.375 to $2.799, and a trade through the $2.799 minor bottom reaffirms the downtrend — with no nearby support underneath, prices could drift lower without a technical floor to catch them.

Six weeks of consecutive weekly losses in a commodity heading into peak cooling season is not a weather story. It is a supply story, and the numbers behind it are unambiguous: Lower 48 dry gas production averaging 110.6 Bcf/d in August against a record 110.7 Bcf/d in July, inventories 6.4% above the five-year seasonal average, and LNG feedgas demand falling rather than rising.

The dislocation that makes this genuinely interesting sits 4,000 miles east. Dutch TTF front-month closed at €59.44/MWh on July 31, up 30% from the end of June, and traded near €56.65/MWh on August 3. Convert that and Europe is paying roughly $19 to $20 per MMBtu for the same molecule the US market cannot get above $2.70.

That is a 7.3x spread. It exists because American gas cannot physically leave.

The Storage Surplus Nobody Can Work Off

Inventories are the number sellers return to after every heat forecast fades, and they have not tightened all summer.

US working gas inventories sit 6.4% above the five-year seasonal average. At the end of June the surplus stood at 6%. The absolute reference point: stocks reached 3,056 Bcf for the week ending July 17 — 183 Bcf above the five-year average — following a 32 Bcf injection that was smaller than the prior week's 41 Bcf build.

That smaller build was the closest thing bulls got to evidence that power burn was doing work. It did not hold. The week ended July 31 delivered 33 Bcf against a 23 Bcf five-year average — a 10 Bcf weekly surplus addition — and against last year's 13 Bcf build for the same week, meaning the year-over-year comparison worsened by 20 Bcf in a single week.

Run the seasonal math. With roughly twelve weeks of injection season remaining before the traditional November 1 turn, sustained builds 10 Bcf above the five-year average would add another 120 Bcf to the surplus. The official forecast puts inventories at 3,966 Bcf by the end of October, 5% above the five-year average — which implies the surplus narrows modestly through the autumn rather than clearing.

That is the entire bearish case in one number. A market entering winter with 3,966 Bcf and a 5% cushion does not price a winter premium in August.

The precedent for how quickly this can invert is instructive. Injections have historically tripled in size across a few weeks when eastern-half weather turns mild, and the corresponding price reaction has been muted in both directions once the surplus is established. Storage that is comfortably above average removes the market's sensitivity to individual weekly prints.

What would change it is a genuinely tight number after a hot stretch — the first real evidence that demand is cutting into the cushion. That has not arrived. The market got two consecutive opportunities in the July 17 and July 31 reports and both confirmed what sellers had been arguing.

Population-weighted cooling demand has been the swing variable, and it keeps disappointing. ERCOT has run heavy summer loads and the interior West stayed above normal into early August, but the Midwest, Great Lakes and Northeast keep receiving cooler breaks that pull national demand back below the level that would force short covering.

Production at 110.6 Bcf/d Is the Structural Problem

Supply is running at or near record levels and it has barely responded to a 17% monthly price decline.

Lower 48 dry gas output has averaged 110.6 Bcf/d so far in August, a slight easing from the record 110.7 Bcf/d set in July. That July figure matched the record monthly high established in December 2025 — meaning summer production is running at winter-peak levels. Output has been described as near 111 Bcf/d throughout the recent selloff.

Record production is the explicit driver in official forecasting. Inventories remain relatively high because record natural gas production, led by growth in the Permian region, is meeting rising demand. That is the mechanism: associated gas from oil-directed drilling in West Texas keeps arriving regardless of the Henry Hub price, because the economics are set by crude at $77.91 rather than by gas at $2.65.

The Permian basis tells you how oversupplied that region is. Waha daily prices have averaged $1.595/MMBtu since June 15 — a $1.06 discount to Henry Hub — and that figure is held above zero only because added pipeline takeaway capacity has been able to move gas out to demand centers. Waha has traded negative in prior periods when takeaway constrained.

Which brings the analysis to the single most bearish scheduled event on the calendar. Energy Transfer announced that the Hugh Brinson pipeline will operate at its full transportation capacity of 1.5 Bcf/d by September 1. That is 1.5 Bcf/d of additional Permian gas routed toward Henry Hub demand centers arriving precisely as summer cooling demand fades.

Do the arithmetic against the surplus. An incremental 1.5 Bcf/d sustained across the September and October injection weeks adds roughly 92 Bcf to storage over eight weeks — nearly matching the entire 120 Bcf surplus accumulation implied by current build rates. The pipeline does not create new molecules, but it converts stranded Permian supply that was clearing at $1.595 into deliverable gas competing at the national benchmark.

That is why the market has negative carryover from the announcement and why the seventh consecutive weekly loss is a supply event rather than a weather event.

Production discipline is not coming. Gas-directed rigs respond to gas prices, but the Permian's associated volumes respond to crude, and crude at $77.91 with Brent at $83.40 keeps that drilling economic.

LNG Feedgas Is Falling, and That Is the Bullish Case Breaking

The one demand channel that could absorb 110.6 Bcf/d of production is going the wrong direction.

Average flows to the nine major US LNG export plants have fallen to 16.9 Bcf/d so far in August from 17.2 Bcf/d in July, which itself was down from 17.4 Bcf/d in June. Feedgas has been described as near 18 Bcf/d at the strongest points, with one Monday reading 18.0 Bcf/d — the highest in five days at the time — but the monthly trend is consistently lower.

That is a 0.5 Bcf/d decline across two months at the exact moment global buyers are paying $19 to $20/MMBtu.

Export volumes confirm the physical constraint. July US LNG exports slipped to 10.48 million metric tons from 10.6 million in June while overseas prices were screaming for more supply. Summer maintenance at Freeport LNG and other facilities limited how much gas could physically leave the country.

Two specific bottlenecks account for most of it. Reduced operations at Freeport LNG in Texas, and Golden Pass running only a single operating liquefaction train. Golden Pass was expected to deliver first LNG sales near the end of 2025 and is part of a global LNG supply expansion projected at 9% growth in 2026 alongside Qatar's North Field East. A facility designed for multiple trains operating one is the difference between absorbing domestic supply and leaving it in storage.

The demand signal on the other side is unmistakable. Cheniere raised its full-year outlook on strong export demand. Global buyers want US cargoes. US LNG accounted for 58% of Europe's LNG imports in 2025, a figure likely to have risen further this year.

The domestic market does not care, because the gas is not leaving fast enough. Feedgas near 17 to 18 Bcf/d keeps a floor under Henry Hub but it is running below the spring peak and is not pulling enough out of the domestic system to offset what production is putting in.

That is the cleanest framing of the entire dislocation. Demand exists at $19. Supply exists at 110.6 Bcf/d. The liquefaction capacity connecting them is running under nameplate for maintenance reasons, and until that resolves, American gas is trapped in American storage.

Europe Is Paying $19 and Cannot Fill Storage

The other side of the trapped-gas equation is a European market in genuine distress that US supply cannot reach.

Dutch TTF front-month closed at €59.44/MWh on July 31, up 30% from the end of June. It dipped 3.7% to €58.43/MWh on cooler Northwest European weather, then firmed again, and traded near €56.65/MWh on August 3, down 4.03% on the session. At a MWh-to-MMBtu conversion of 3.412 and EUR/USD near 1.1570, €56.65/MWh translates to roughly $19.21/MMBtu, with the July 31 close near $20.15.

Henry Hub is at $2.65. That is a spread of more than $16.50/MMBtu — the widest transatlantic dislocation in years and a direct measure of how binding the liquefaction and shipping constraints have become.

The comparison with crude is the most revealing detail. In the week TTF held its level, Brent gave up more than 11%. Oil sold off on Hormuz reopening optimism while European gas did not. The market increasingly treats this conflict as an LNG shipping problem rather than a crude problem, and that distinction is why the two commodities have decoupled.

European storage is the reason the bid persists. EU inventories stood at roughly 55% as of July 28, about 11 percentage points below the prior year, with the injection rate running below the path required to hit the 80% target. Europe's LNG imports ran well below the prior year in July. One assessment put storage at 58% full heading into winter — well below normal for early August.

The starting point was worse. EU storage stood at 50 bcm, equivalent to 46% of capacity, on June 23 — 10.6 bcm below the same point a year earlier and 15 bcm below the five-year average. The shortfall accumulated across an injection season constrained by tight supply and competition from Asian buyers.

The European Commission has expressed confidence that substantial spare LNG import capacity plus the 80% storage target will be sufficient for winter demand. Market pricing disagrees. Europe faces intense competition from Asia for available cargoes, which keeps upward pressure on prices, and LNG supply risks remain elevated despite diplomatic signals easing oil.

For Henry Hub, this is the strongest medium-term bull argument that exists. It requires American liquefaction to come back online.

Hormuz, Qatari Cargoes, and the Shipping Constraint

The Strait of Hormuz has been the mechanism transmitting geopolitical risk into gas rather than just oil, and the transmission runs through Qatar.

Qatari LNG exports transit Hormuz. With the strait functionally closed since February 28, those cargoes have been unable to reach Asian and European buyers reliably, which redirected global demand toward Atlantic-basin supply and specifically toward US cargoes. The timing of Qatari LNG export recovery is one of the two variables that will shape the European gas balance across the second half of 2026, alongside the pace of injection-season recovery.

There has been movement. For the first time since an attack on a Qatari LNG tanker, a Qatari vessel has passed through the Strait of Hormuz again. Iran and Oman are nearing an agreement on a framework to resume commercial shipping through the waterway, though Tehran continues to push for a role overseeing traffic through the strategic passage.

The draft terms disclosed this week were stricter than the market had assumed — a proposed ban on US and Israeli vessels, compensation requirements for hostile-designated states, penalties equal to 20% of cargo value on violators, and full reopening contingent on lifting the US maritime blockade. An Iranian parliamentary committee is reviewing that draft. The temporary route under discussion is expected to operate for two to four months and explicitly does not constitute a full reopening.

For Henry Hub the sign is counterintuitive. A Hormuz reopening restores Qatari LNG to the global market, which reduces the premium on Atlantic cargoes, which compresses TTF from $19 toward the $9.81/MMBtu average that had been forecast for 2026 before the conflict. Lower European prices reduce the arbitrage pulling US cargoes east, which is bearish for US export demand and therefore bearish for Henry Hub.

So the US gas market is short the reopening. A continued closure keeps TTF at $19 to $20 and keeps every available US cargo bid aggressively — provided liquefaction capacity can load them.

That conditional is doing all the work. Global LNG supply is expanding 9% in 2026 driven by Golden Pass and Qatar North Field East. Golden Pass running one train is the bottleneck. When additional trains commission, the connection between $19 European gas and $2.65 American gas finally closes, and it closes in Henry Hub's favour.

Weather Is Above Normal and It Has Not Mattered

The most instructive thing about this selloff is that it has occurred despite consistently supportive temperature forecasts.

Forecasts point to mostly above-normal temperatures through August 21. Weather models shifted warmer on Thursday, with above-average readings expected across the Northeast and western United States through August 10. ERCOT is running heavy summer loads and the interior West has stayed above normal.

Prices fell anyway, printing a 3.25-month low and setting up a seventh consecutive weekly loss.

The reason is regional composition. National power burn is what determines gas demand, and the population centers that drive it — the Midwest, Great Lakes and Northeast — keep receiving cooler breaks that pull aggregate demand back from levels that would force short covering. Earlier in the cycle, updated forecasts calling for cooler temperatures across the central and eastern US directly weighed on prices by reducing expected air-conditioning demand. One forecast round had normal seasonal weather across the eastern US through August 17.

Texas heat and western heat support gas demand. They do not offset mild eastern weather, because the East is where the load is.

The calendar is the second constraint and it is now binding. The market is assessing a shrinking window for intense cooling demand. Mid-August marks the practical end of the period when heat can meaningfully draw down storage, and every day that passes without a genuine national heat event converts a potential summer squeeze into a larger autumn surplus.

That asymmetry is why weather rallies have failed all summer. A hot forecast produces a one- or two-day bounce, the subsequent storage report confirms the surplus, and the market goes right back to selling. That pattern has repeated enough times that the burden of proof has shifted entirely — bulls now need a tight print, not a warm forecast.

The wholesale power market reflects the same dynamic. Wholesale electricity prices are forecast lower this summer than last, primarily because of lower costs of natural gas delivered to power plants, averaging about $45 per megawatt-hour nationally with the largest declines in the western hubs and the Midcontinent region.

Cheap gas produces cheap power, which produces no upward feedback into gas demand beyond the substitution already priced.

The Official Forecast Sits 35% Above Spot

The gap between where gas trades and where the balance points is the largest analytical disagreement in the commodity.

The Henry Hub spot price is forecast to average close to $3.70/MMBtu in 2026 before declining below $3.50/MMBtu in 2027. The fourth-quarter 2026 forecast is $3.57/MMBtu, which would be 5% less than the same quarter last year.

Spot is $2.65. The Q4 forecast sits 34.7% above that. The 2026 annual average forecast of $3.70 sits 39.6% above it.

The annual average is achievable without any summer recovery because of what happened in January. The Henry Hub spot price rose $1.86/MMBtu in a single report week during that month, from $3.12 to $4.98, with the February 2026 NYMEX contract climbing from $3.120 to $4.875. A winter spike of that magnitude pulls the annual average up regardless of a $2.65 August.

The Q4 number is the one that matters for anyone holding a position. It requires a 92-cent recovery from spot across the fourth quarter, driven by storage draws beginning in November and by whatever LNG capacity has come online by then.

Note the forecast revision history, because it shows how the balance has shifted. In January the projection was for the 2026 average to decrease about 2% to just under $3.50, then rise sharply in 2027 to just under $4.60 as LNG feedgas demand growth outpaced supply growth and reduced storage. The July update raised 2026 to $3.70 and cut 2027 to below $3.50 — a complete inversion of the shape.

That revision says record production, led by the Permian, is now expected to keep pace with LNG demand growth rather than fall behind it. The structural tightening that was supposed to arrive in 2027 has been pushed out or removed.

Independent models are considerably more bearish than the official forecast on the near term, projecting $2.51 over five days, $2.46 over one month and $2.50 over three months. Those cluster 5% to 7% below spot.

The next official update lands August 11. Given six weeks of consecutive losses, a 6.4% storage surplus and feedgas declining, a downward revision to the Q3 and Q4 numbers is the likely outcome.

Technical Structure: $2.799 Broke and There Is Nothing Beneath

The chart is as clean as the fundamentals and it points the same direction.

The short-term range has been $3.375 to $2.799. The $2.799 minor bottom was the level that, if breached, would reaffirm the downtrend — and the market has traded through it, printing a 3.25-month nearest-futures low. The explicit warning was that there is no nearby support below $2.799, meaning prices could drift lower in the near term without a technical floor.

At $2.65 the contract is 5.3% below that broken level and 21.5% below the $3.375 range top.

Resistance on any bounce: $2.70, the level that gave way on July 30, then $2.799 as the recovered breakdown point, then $3.00 as the psychological line. Reclaiming $3.375 would require a 27.4% rally and is not a 2026 scenario absent a supply disruption.

Support is genuinely thin. Below $2.65 the references are $2.50, where near-term models cluster, then $2.46, then $2.30 as the boundary of the lower forecast distribution. A market with no structural support and six consecutive weekly losses tends to find its floor through capitulation rather than through a level.

Sentiment readings confirm the position. The Fear and Greed reading on the instrument sits at 23 — extreme fear — with green days running three of the last nine sessions, or 33%. The 14-day RSI at 60.89 reads neutral, which is the one indicator that does not confirm the bearish picture and suggests the selling has been orderly rather than panicked.

Open interest at 29,940 contracts on the last-day financial instrument has been described as declining, which indicates traders closing positions and a weakening trend rather than fresh short accumulation. That matters for the squeeze risk — a market that is short and crowded snaps back violently. A market where participants are simply leaving does not.

The contract structure has been sending a signal worth noting. September futures finished a recent week higher while August faded, which said the market saw something worth defending in the active contract even while it could not sustain a rally. That relative strength in the deferred months against prompt weakness is the curve pricing an eventual LNG-driven recovery.

Trade the range $2.46 to $2.80. Above $2.80 the technical case improves materially; below $2.46 the void opens.

The Basis Story: Waha at $1.595 and What It Signals

Regional pricing is where the oversupply becomes visceral.

Waha daily prices in the Permian have averaged $1.595/MMBtu since June 15, holding steady above zero only because added pipeline takeaway capacity has been able to move more gas to demand centers. That is a $1.06 discount to a Henry Hub benchmark that is itself at a 3.25-month low.

Waha at $1.595 is gas that has essentially no economic value at the wellhead. It is produced as a byproduct of oil drilling, and the operators producing it are indifferent to the price because their revenue comes from crude at $77.91. That indifference is what makes the supply inelastic and why 110.6 Bcf/d has not responded to a 17.36% monthly price decline.

The Hugh Brinson pipeline reaching full 1.5 Bcf/d capacity by September 1 will improve Waha basis by giving that gas a route to demand centers. It will simultaneously worsen Henry Hub, because the gas arriving at the benchmark hub was previously trapped and clearing at $1.595.

That is the mechanism worth understanding precisely: pipeline construction does not reduce national supply, it relocates the point at which oversupply is priced. Permian producers get a better netback. Henry Hub absorbs the volume.

The international basis makes the same point at a vastly larger scale. TTF at roughly $19.21/MMBtu against Henry Hub at $2.65 is a 625% premium. East Asian front-month LNG cargo prices and TTF have both run far above US levels through this cycle. Historical reference points from earlier in the year had East Asia at $10.73/MMBtu and TTF at $12.40/MMBtu weekly averages during the winter squeeze — and TTF is now well above both.

A functioning arbitrage would close a $16.50 spread almost instantly. It is not closing because liquefaction capacity is the binding constraint, not price signals. Freeport running reduced operations and Golden Pass on one train means the physical bridge between the cheapest gas in the world and the most expensive is narrower than the economics justify.

For anyone modeling this, the trade is not Henry Hub direction. It is the timing of when that bridge widens.

What Would Actually Turn This Market

Define the evidence in advance, because the headlines will not provide it.

Three markers matter. First, a tight storage print after a hot week. The market needs an injection meaningfully below the five-year average — call it under 15 Bcf during a warm reference period — as the first real evidence that demand is cutting into the 6.4% surplus. Two consecutive opportunities in the July 17 and July 31 reports both failed that test.

Second, LNG feedgas sustaining above 18 Bcf/d. That requires Freeport LNG completing maintenance and returning to full operations, and it requires Golden Pass commissioning additional liquefaction trains beyond the single unit currently running. Feedgas has been the strongest thing buyers have, and it is running at 16.9 Bcf/d — below the spring peak and below the level needed to offset 110.6 Bcf/d of production.

Third, production rolling over. Lower 48 output easing from 110.7 Bcf/d to 110.6 Bcf/d is not a decline, it is noise. A genuine turn would need output below 108 Bcf/d, which requires either gas-directed rig reductions responding to $2.65 or a slowdown in Permian associated volumes that crude at $77.91 makes unlikely.

None of the three has triggered.

What would accelerate the bearish case is equally specific: Hugh Brinson reaching full 1.5 Bcf/d on September 1 as scheduled, continued mild eastern weather through the end of the cooling window, and a Hormuz reopening that restores Qatari LNG and compresses TTF from $19 toward the pre-conflict $9.81 forecast, killing the export arbitrage.

The medium-term structural case is the counterweight and it is real. European storage at roughly 55% against an 80% target with the injection rate running behind. EU inventories 11 percentage points below prior year. Asian competition for cargoes intensifying. Global LNG supply expanding 9% in 2026 with Golden Pass and Qatar North Field East, meaning US liquefaction capacity is growing structurally even if it is offline for maintenance today.

When Golden Pass fully commissions, US feedgas capacity steps up permanently and 110.6 Bcf/d of production finally has an outlet at $19 rather than a storage cavern at $2.65.

That is a 2027 story. The official forecast has 2027 below $3.50, which suggests even that is contested.

Scenarios Into the August 11 Outlook and Winter

Base case, roughly 50% weight: gas holds $2.45 to $2.85 through the remainder of the cooling window. Storage builds continue running above the five-year average, keeping the surplus near 6%, and inventories reach roughly 3,966 Bcf by end-October at 5% above average. Feedgas stays near 17 Bcf/d as Freeport maintenance completes slowly. Hugh Brinson adds 1.5 Bcf/d on September 1. Prompt month finishes August between $2.55 and $2.80. Base target $2.70.

Bull case, roughly 30%: Freeport returns to full operations and Golden Pass commissions a second train, lifting feedgas above 19 Bcf/d. Hormuz talks collapse, keeping TTF above $19 and the export arbitrage wide open. A late-August heat event delivers a sub-15 Bcf injection, and the market reprices toward the $3.57 fourth-quarter forecast — a 34.7% move from spot. Extension to $3.375 at the top of the broken range.

Bear case, roughly 20%: eastern weather turns decisively mild through the end of August, production holds above 110 Bcf/d, and Hugh Brinson delivers on schedule. A Hormuz reopening restores Qatari cargoes and TTF falls from $19 toward $12 and then toward the $9.81 pre-conflict forecast, collapsing the export pull. Gas breaks $2.50, then $2.46, and tests $2.30. Storage exits October above 4,000 Bcf and the winter premium never builds.

The distribution favours the upside from $2.65 on pure arithmetic — 34.7% to the Q4 forecast versus 13.2% to the $2.30 downside boundary — but the flow evidence argues the other way. Six consecutive weekly losses into peak cooling season with above-normal temperature forecasts is a market telling you the fundamentals override the calendar.

The honest read is that the bull case requires liquefaction capacity that is currently offline, and the bear case requires only that nothing changes.

Levels and Verdict

Natural gas at $2.65/MMBtu has fallen 17.36% in a month, printed a 3.25-month low, broken the $2.799 support that had defined the short-term range, and is on track for a seventh consecutive weekly loss. The drivers are quantified and none of them are weather.

Production is running at 110.6 Bcf/d in August against a record 110.7 Bcf/d in July, which itself matched the all-time monthly high set in December 2025. Inventories sit 6.4% above the five-year average after a 33 Bcf injection for the week ended July 31 that beat consensus, exceeded last year's 13 Bcf build and ran 10 Bcf above the 23 Bcf five-year average. LNG feedgas to the nine major export plants has fallen to 16.9 Bcf/d from 17.2 Bcf/d in July and 17.4 Bcf/d in June. Hugh Brinson adds 1.5 Bcf/d of Permian gas on September 1.

The map: resistance at $2.70, then $2.799, then $3.00, with the $3.375 range top requiring a 27.4% rally. Support at $2.50, then $2.46, then $2.30. There is no structural support beneath the broken $2.799 level, which means downside moves can extend without a level to catch them. Watch open interest — 29,940 contracts and declining says participants are leaving, not shorting, which reduces squeeze risk.

The setup that makes this genuinely asymmetric is the transatlantic spread. TTF closed at €59.44/MWh on July 31, up 30% from end-June, and traded near €56.65/MWh — roughly $19.21/MMBtu against Henry Hub's $2.65. European storage sits near 55% against an 80% target, 11 points below prior year, with injections running behind schedule. US LNG supplied 58% of Europe's imports last year. The demand exists at seven times the domestic price.

It cannot be reached because Freeport is in maintenance and Golden Pass is running one train.

Verdict: sell strength above $2.80 with a stop above $2.90, targeting $2.55 and then $2.46. Buy weakness below $2.46 only with a stop below $2.35, targeting $2.70. The Q4 forecast at $3.57 sits 34.7% above spot and it is a liquefaction bet, not a weather bet.

Watch three things: a sub-15 Bcf injection print, feedgas above 19 Bcf/d, and Golden Pass train commissioning. Until one of them lands, the surplus wins and the cooling window is closing.

That's TradingNEWS