Henry Hub at $2.70 Sits 6.3% Above Its 52-Week Low as the EIA Projects a Record 3,985 Bcf by October

Natural gas futures traded $2.70 per million British thermal units Tuesday, up 0.46% from the previous session, after Monday delivered a 2% decline to roughly $2.68 — the lowest settlement since August 7.

The recovery is marginal against the trend. Front-month gas is down 2.50% on the week, 5.51% over the past month, and 2.30% against the same point last year. Year to date the contract has lost 2.80%.

The 52-week range frames how far the market has fallen. The high is $5.62 and the low is $2.54. At $2.70, gas sits 51.9% below the annual peak and just 6.3% above the annual floor. That proximity to the low is the defining feature of this tape.

A prior session took the contract to approximately $2.65, near three-month lows, weighed by robust production and comfortable inventory levels. Every rally attempt through August has failed inside a 20-cent band.

The drivers are unambiguous and all point the same direction. Weather models moderated, pointing to less intense heat across much of the country in the coming weeks, which reduces gas-fired power generation demand for air conditioning and allows inventories to build faster. Production is running at record levels. Storage sits nearly 200 Bcf above the five-year average.

Nothing on the demand side is compensating.

The contrast with the rest of the energy complex is stark. Brent crude reached $90.97 and West Texas Intermediate traded $84.39 as the US-Iran memorandum expired and Strait of Hormuz transits collapsed to five vessels Saturday and zero Sunday. Crude carries a $6 war premium. Henry Hub carries none, because US gas is a domestic market insulated from Middle East logistics by geography and by the physical difficulty of moving molecules.

Sentiment readings show 80.77% of retail positioning on the long side against 19.23% short, with the aggregate signal reading neutral. That is a crowded long in a market making lower lows.

The August focus is shifting from the 2026 cooling season toward the 2026/2027 peak heating season, where demand and prices structurally reach their annual highs.

That transition is the only bullish argument currently available.

Lower 48 Production at a Record 111.6 Bcf/d

Average output in the Lower 48 states has reached 111.6 billion cubic feet per day so far in August, exceeding July's monthly record of 110.7 Bcf/d. An earlier reading in the month put the figure at 111.3 Bcf/d.

That is the single most important number in this market and it explains the entire price structure.

The progression through 2026 has been relentless. The Energy Information Administration estimated US dry gas production would average 109 Bcf/d for the full year, up about 1% from the prior year's pace. August is running 2.6 Bcf/d above that annual estimate, and each successive month has set a new record.

Supply growth of that magnitude in a market where demand is seasonally topping out produces exactly what the storage data shows: injections above consensus, inventories building faster than the five-year norm, and a front-month contract grinding toward its annual low.

The EIA's January forecast assumed supply growth would outpace demand growth by 0.5 Bcf/d across 2026, with demand rising less than 1% at plus 0.6 Bcf/d against supply increasing nearly 1% at plus 1.1 Bcf/d. The realized supply overshoot is larger than that model contemplated.

The counterweight is that production growth is moderating at the margin. Rig counts have been declining, and with Henry Hub near multi-month lows the economics of incremental dry gas drilling deteriorate. Producers responding to $2.70 gas by cutting activity is the mechanism that eventually rebalances the market, but the lag from rig count to production runs six to nine months.

That means the supply that will hit the market through the fourth quarter is already drilled and committed. Nothing a producer decides in August changes the balance before winter.

Associated gas complicates the picture further. With WTI at $84.39, oil-directed drilling in the Permian remains economic regardless of what gas prices do, and the associated gas that comes with those barrels enters the market as a byproduct that no price signal can discourage.

Record production at $2.70 gas and $84 oil is a structural condition, not a cyclical one.

Storage at 3,153 Bcf — 198 Bcf Above the Five-Year Average

Working gas in underground storage reached 3,153 Bcf as of Friday, August 7, according to EIA estimates. That is 198 Bcf above the five-year average of 2,955 Bcf — a surplus of 6.7% — and 25 Bcf, or 0.8%, below year-ago levels.

The surplus has been widening steadily rather than eroding. Inventories stood 183 Bcf above the five-year average on July 17, then 185 Bcf on July 24, then 195 Bcf on July 31, then 198 Bcf on August 7. Four consecutive weeks of an expanding cushion during the peak cooling season is the clearest evidence available that summer demand has not been sufficient to absorb record supply.

The year-over-year comparison offers the only counterpoint. Stocks below last year's level by 25 Bcf means the market entered this injection season tighter than it exited the prior one. The injection season began at approximately 1,829 Bcf, near the five-year average, after the most expensive New England winter on record drew inventories down hard.

Refilling from 1,829 Bcf required roughly 2,000 Bcf across 30 weeks — about 67 Bcf per week — to reach a comfortable pre-winter target above 3,800 Bcf. The system has delivered that and more.

The early-season pace was extraordinary. Injections ran 85 Bcf in the week ending May 8, 101 Bcf on May 15, and 92 Bcf on May 22. An 87 Bcf build in the week ending July 2 pushed the five-year surplus to 6.4% and drew the observation that inventory levels were already exceeding what summer demand could reasonably challenge.

Total working gas remains within the five-year historical range, which is the technical framing the EIA uses. The level is not extreme. The trajectory is.

Full detail is published in the EIA Weekly Natural Gas Storage Report, released every Thursday at 10:30 a.m. ET.

This Thursday's print covering the week ending August 14 is the nearest scheduled catalyst.

Four Straight Injections Above Consensus

The weekly flow data has been the mechanism transmitting bearishness into price, and the pattern has been consistent.

Energy firms injected 36 Bcf into storage in the week ending August 7, above market expectations of 31 Bcf. That compared with an injection of 49 Bcf during the same week a year ago and a five-year average increase of 33 Bcf for that calendar week.

The prior week ending July 31 delivered 33 Bcf against expectations for 31 Bcf, versus 13 Bcf a year earlier and a five-year average of 23 Bcf. That build ran 43% above the seasonal norm.

The exception was the week ending July 24, when firms added 28 Bcf against a 35 Bcf consensus — a genuine miss driven by South Central salt withdrawals of 14 Bcf and draws in the Mountain and Pacific regions as cooling demand peaked. That print briefly tightened the read and produced no sustained price response.

The week ending July 17 delivered 32 Bcf.

Three of the last four weekly injections have exceeded consensus, and two have exceeded the five-year average by wide margins. Weekly flow running above normal while the storage level already sits 6.7% above the five-year average is a market loosening from an already comfortable base.

The forward implication is what matters. If the flow versus normal comparison stays positive through September and October, the surplus widens further into the withdrawal season, and the market enters winter with a cushion that requires sustained cold to erode.

The reverse case is the salt cavern signal. The 6 Bcf salt withdrawal in the August 7 week and the 14 Bcf draw in the July 24 week both indicate short-term balancing needs. Salt storage is the most flexible component of the US system, and draws there often precede volatility because they signal that daily deliverability is being tested even while national totals look loose.

Regional imbalance is where late-summer risk concentrates. The East and Pacific regions show stress relative to last year, which raises basis volatility risk for Mid-Atlantic and Northeast buyers during heat events.

National totals mask that entirely.

The EIA Now Sees a Record 3,985 Bcf at End-October

The August Short-Term Energy Outlook forecasts US working natural gas inventories reaching a record 3,985 Bcf at the end of October 2026 — an increase of 19 Bcf compared with the July forecast and 5% above the five-year average.

A record end-of-season inventory is the most bearish possible setup heading into winter. Levels above 3.9 Tcf have historically correlated with sub-$3.00 pricing, and the agency is now projecting nearly 4.0 Tcf.

The revision direction is what matters. The July STEO already assumed a comfortable refill. August raised the estimate rather than lowering it, which means the agency's own model absorbed the record production and moderating weather and concluded the balance is looser than it previously thought.

Getting from 3,153 Bcf on August 7 to 3,985 Bcf by October 31 requires roughly 832 Bcf across twelve weeks — about 69 Bcf per week. That is well above the current 33 to 36 Bcf pace, which means the forecast assumes injections accelerate materially as cooling demand fades through September and October.

That acceleration is the normal seasonal pattern. Power burn falls as temperatures moderate, LNG feedgas stays roughly flat, and production continues, so more gas is available to go into the ground each week.

The risk to that path runs in one direction. A sustained late-summer heat event would suppress injections and narrow the surplus, and hurricane activity in the Gulf can disrupt production and LNG feedgas simultaneously. Neither is currently in the forecast.

The 2027 picture inverts entirely. The EIA projects supply growth falling behind demand growth by 1.6 Bcf/d in 2027, with demand rising 2.5 Bcf/d against supply at 0.9 Bcf/d, driven principally by LNG export capacity. That reverses the 0.5 Bcf/d supply surplus of 2026 and puts upward pressure on price.

The January outlook had annual average Henry Hub decreasing about 2% to just under $3.50 in 2026 before rising sharply to just under $4.60 in 2027 — a 33% increase.

The full outlook sits on the EIA Short-Term Energy Outlook natural gas page.

Henry Hub Forecast Cut 50 Cents to $2.87 for the Third Quarter

The EIA now expects the Henry Hub spot price to average $2.87 per MMBtu in the third quarter of 2026, down 50 cents compared with the prior month's forecast.

A 50-cent downward revision in a single monthly update is a substantial capitulation on the summer balance, and it puts the agency's own estimate just 17 cents above where the front-month contract currently trades.

That gap is the entire near-term valuation debate. Gas at $2.70 against an official $2.87 third-quarter average implies the market has already moved beyond the agency's revised view, which happens when weekly data runs consistently against the model.

The trajectory of official forecasts through 2026 tells the story of a market that kept surprising to the downside. The December 2025 outlook projected Henry Hub averaging $4.30 through winter 2025/26 and $4.01 for all of 2026 — a 13% increase on the prior year. The January outlook cut the 2026 annual figure to just under $3.50, a 2% decrease. A March framework put the annual average at $3.76 against $3.53 in 2025.

Now the third quarter alone is guided to $2.87.

Each revision has moved lower, and the pattern is driven by production consistently exceeding assumptions rather than by demand disappointing. Dry gas output was modeled at 109 Bcf/d for the year and is running at 111.6 Bcf/d in August.

The January data point is the reminder of how violently this market can reprice. Henry Hub averaged $7.72/MMBtu in January 2026 during the winter storm, then $3.62 in February. A 53% single-month collapse followed by a further grind to $2.70 by August is a full round trip inside eight months.

Realized prices in April ran near $2.90 against an EIA annual forecast of $3.80 at that time, and the market has been trading below the official view consistently since.

The next STEO release is September 9.

Weather Models Moderated and Took the Cooling Bid With Them

The proximate trigger for Monday's 2% decline was a shift in the weather forecast, and it is the demand variable that dominates August pricing.

Recent weather models have moderated, pointing to less intense heat across much of the country in the coming weeks. That reduces demand for gas-fired power generation, particularly for air conditioning, while allowing inventories to build at a faster pace.

Power burn is the swing consumer in summer. Roughly 40% of US electricity comes from natural gas, and cooling load in July and August represents the seasonal peak in gas demand outside of winter heating. Every degree-day removed from the forecast subtracts directly from that burn.

The July pattern showed how sensitive the market is. Gas traded to a two-month low in mid-July on forecasts of mild weather for big northern markets, then a seven-week low the following session, then recovered as heat returned to most states. The contract has been trading weather models rather than fundamentals for two months.

That sensitivity cuts both ways and is the primary upside risk to the bearish case. A late-August heat event across the Midwest and Northeast would suppress injections below the 33 Bcf five-year norm and narrow the 198 Bcf surplus quickly, and the market is positioned long enough that a genuine squeeze is possible from these levels.

The structural demand story is more durable. EIA forecasts US electricity generation by the power sector growing 2.4% in 2025 and another 1.7% in 2026, driven primarily by increasing demand from large customers including data centers. That load growth is not weather-dependent and does not reverse.

It is also not large enough to absorb 111.6 Bcf/d of production in a shoulder season.

The August transition is the market shifting attention from the 2026 cooling season toward the 2026/2027 peak heating season, where gas demand and prices structurally reach their annual highs. That rotation is why the curve carries a winter premium regardless of what the front month does.

Weather forecasts for the coming winter do not exist yet in any tradeable form.

LNG Feedgas at 17.3 Bcf/d and the Freeport Maintenance Overhang

Average gas flows to the nine major US LNG export facilities rose to 17.3 Bcf/d in August, compared with 17.2 Bcf/d in July. An earlier reading in the month had feedgas easing to 17.1 Bcf/d.

That flatline is a problem for the bull case. LNG exports are the structural demand growth story underpinning every constructive multi-year gas forecast, and they are contributing effectively nothing incremental this summer.

The EIA expects US LNG exports to average 16.5 Bcf/d in the third quarter of 2026, revised down 0.2 Bcf/d from the prior forecast. That is below the 17.3 Bcf/d currently flowing, which implies the agency expects feedgas to decline through the balance of the quarter.

Freeport LNG is the immediate constraint. Maintenance began July 10 and is expected to complete in late August, affecting 2.0 Bcf/d of nominal export capacity. Maintenance at Freeport and other Gulf Coast terminals reduced feedgas demand through June and July, leaving that gas available to the domestic market and contributing directly to the storage builds.

Freeport returning to full operation in late August adds 2.0 Bcf/d of demand at exactly the moment injections would otherwise accelerate. That is the single clearest near-term bullish catalyst on the calendar and it has not been priced.

The constraint beyond Freeport is capacity rather than demand. Even with Freeport fully operational, exports remain limited by slow growth in additional export capacity, despite US price spreads to Europe and Asia staying elevated on ongoing disruptions. The arbitrage exists and there is no terminal to move the molecules through.

The pipeline channel is growing modestly. Total US natural gas exports by pipeline are estimated at 9.6 Bcf/d in 2026, rising to 10.0 Bcf/d in 2027 from 9.5 Bcf/d in 2025. Energia Costa Azul shipped its first cargo July 8, bringing 0.4 Bcf/d of nominal capacity online on Mexico's Pacific coast, supplied from the Permian Basin.

LNG exports are forecast to grow 9%, or 1.3 Bcf/d, in 2026 and 11%, or 1.7 Bcf/d, in 2027, as Plaquemines LNG, Corpus Christi Stage 3 and Golden Pass ramp.

That growth arrives in 2027, not this quarter.

Hormuz Disrupted LNG Shipping While Henry Hub Fell

The geopolitical event dominating every other energy market has had almost no effect on US natural gas, and the disconnect is instructive.

LNG vessel traffic through the Strait of Hormuz slowed considerably after strikes on vessels resumed on July 7. International prices rose in July to levels last reached in early April as Qatari cargoes — roughly a fifth of global LNG supply — faced transit risk.

Brent crude reached $90.97 Tuesday. Only five commodity vessels transited Hormuz on Saturday and none on Sunday, against 31 the previous weekend. Two Abu Dhabi National Oil Company vessels were attacked late Thursday.

Henry Hub fell 2% on Monday and trades at $2.70.

The explanation is structural. US natural gas is a landlocked market bounded by pipeline geography and by finite liquefaction capacity. Global LNG prices can rise indefinitely and the domestic price only responds to the extent that additional gas can physically be exported. With feedgas capped near 17.3 Bcf/d and terminals in maintenance, the arbitrage cannot transmit.

That insulation is the reason Henry Hub trades at $2.70 while European and Asian benchmarks price a supply crisis. It is also the reason US gas is the cheapest energy commodity in the world on an energy-equivalent basis: $2.70/MMBtu against WTI at $84.39, which equates to roughly $14.55/MMBtu.

A 5.4-to-1 ratio between crude and gas on an energy basis is historically wide and creates substitution incentives in industrial and power applications wherever the switch is technically possible.

The forward implication is that every new liquefaction terminal narrows the insulation. As US export capacity grows through 2027 with Plaquemines, Corpus Christi Stage 3 and Golden Pass ramping, Henry Hub becomes progressively more correlated to international pricing, and the domestic discount compresses.

That is the 2027 story the EIA models as a 33% price increase.

For August 2026, the Middle East is somebody else's market.

The Salt Cavern Draws Nobody Is Pricing

Buried inside otherwise bearish storage reports is a signal that deserves more weight than the headline gets.

South Central salt storage withdrew 6 Bcf in the week ending August 7 and 14 Bcf in the week ending July 24. All regions except Pacific and South Central Salt posted increases in the August 7 week.

Salt caverns are the most flexible component of the US storage system. They cycle rapidly, serve peak daily deliverability, and are the facilities that balance the market when demand spikes faster than pipeline supply can respond. Draws there indicate short-term balancing needs even while aggregate inventories build.

Two salt withdrawals inside three weeks during a period when national storage grew 69 Bcf is a genuine divergence between the headline and the physical market.

The July 24 week is the clearer case. That report showed a 28 Bcf headline injection against a 35 Bcf consensus, with Mountain withdrawing 2 Bcf, Pacific withdrawing 7 Bcf, and South Central withdrawing 9 Bcf overall — salt alone drew 14 Bcf while South Central nonsalt stocks sat 6.0% below the prior year.

Draws in the West and South Central directly reflected high cooling demand. Those regions carried the summer load while the East and Midwest built.

The forward risk framing is straightforward. If intense heat persists into late August, the pattern of small injections or net regional withdrawals continues, the surplus erodes, and prices find support. If heat fades as the moderated models suggest, salt caverns refill alongside everything else.

The complication is that salt facilities must be refilled before winter regardless. A prolonged period of draws creates a deficit in the most deliverable portion of the system that becomes difficult to recover before the withdrawal season begins in November.

Regional imbalance rather than national totals is the real late-summer risk. The East and Pacific show stress relative to last year, and basis volatility can emerge quickly for Mid-Atlantic and Northeast buyers during heat events even with 3,153 Bcf in the ground nationally.

The front month does not price basis.

The Curve: Winter Premium From $2.70 to $5.10

The forward curve carries a substantial winter premium, and its shape is the clearest statement of what the market actually believes.

A March 2026 snapshot of the Henry Hub strip showed April near $3.03, July near $3.43, November near $3.86, December near $4.70 and January 2027 near $5.10. That structure points to softer spring pricing, firmer summer demand and a clear winter premium — the market pricing seasonality rather than a continuous shortage.

The front month at $2.70 against January 2027 at roughly $5.10 is an 89% premium for delivery five months forward.

That spread means two things. Storage economics are attractive: buying August gas at $2.70 and selling January at $5.10 covers carrying costs comfortably, which is precisely the incentive driving record injections. And the market does not expect current prices to persist through winter.

Seasonality dominates the gas curve more than most commodities. Winter delivery months structurally price above summer ones, so a contango reading in gas often reflects the calendar rather than a storage signal. Comparing a summer front month against a winter sixth month measures the seasons as much as the market.

That caveat matters when reading the shape as bullish. The winter premium exists every year regardless of the balance.

What is unusual is the depth of the front. Summer 2026 pricing below $3.00 with a January contract above $5.00 is a wider seasonal spread than normal, and it reflects the record end-of-October inventory the EIA projects colliding with a heating season that could still require sustained withdrawals.

Contract mechanics matter for anyone trading the front. NYMEX Henry Hub futures expire three business days before the first day of the delivery month — materially closer to delivery than WTI crude, which stops trading around ten days out. During any calendar month, the contract bearing that month's name has already stopped trading.

Implied volatility on Henry Hub options remains among the highest in the commodity complex, and the market is the third-largest physical commodity futures contract globally by liquidity.

The mid-range of the multi-year channel sits near $4.00.

From $7.72 in January to $2.70 in August

The 2026 price arc is one of the more violent round trips in this market's history and it frames how much room exists in either direction.

Henry Hub averaged $7.72/MMBtu in January 2026 during the winter storm that reshaped the outlook, then $3.62 in February. Front-month February futures rallied $1.94, or about 61%, across several sessions in late January, traded as high as $5.65 intraday on January 22, and settled that day at $5.04.

By spring the contract was below $3.00. By August it is at $2.70, with the 52-week low at $2.54 sitting 6.3% below spot.

The longer history establishes the boundaries. Henry Hub touched a pandemic low of $1.63/MMBtu in June 2020, spiked to a 14-year high of $9.85 in August 2022 on Russia-Ukraine supply fears, crashed below $2 in early 2023, recovered through the 2024 LNG export ramp, ran from below $2 in early 2024 to $7.72 in January 2026, and has round-tripped back below $3.

A market that has traded between $1.63 and $9.85 inside six years does not respect technical levels for long.

The immediate structure is defined by the 52-week low at $2.54. That level is the operative floor, and the distance from $2.70 to $2.54 is 16 cents, or 5.9%. Losing it opens the path toward $2.00 — a level widely viewed as unsustainable given LNG export dynamics, but reachable in a severe warm-winter scenario.

Overhead, $3.00 is the first psychological barrier and the level that would signal the summer lows are in. Above that, the mid-range of the multi-year channel near $4.00 represents the most likely destination heading into winter 2026/27, with the upper boundary near $5.00 reachable only under a significantly colder-than-normal winter.

Gas has broken above $3.00 on cold weather demand before and can do it again inside a single week.

Nothing in the current fundamental set supports it.

Data Center Load Growth and the 2027 Inversion

The structural bull case for natural gas does not depend on weather. It depends on the supply-demand balance inverting in 2027, and the EIA's own model says it does.

Forecast supply growth outpaces demand growth by 0.5 Bcf/d in 2026 but falls behind by 1.6 Bcf/d in 2027 — a 2.1 Bcf/d swing that puts sustained upward pressure on price. Demand rises 2.5 Bcf/d in 2027 against supply growth of 0.9 Bcf/d.

Two forces drive it. LNG exports grow 11%, or 1.7 Bcf/d, in 2027 as Plaquemines LNG and Corpus Christi Stage 3 reach full operations and Golden Pass LNG ramps. That capacity is under construction and its timeline is largely fixed.

The second is power demand. US electricity generation by the power sector is forecast to grow 2.4% in 2025 and 1.7% in 2026, driven primarily by increasing demand from large customers including data centers. Gas sets the marginal cost of electricity in wholesale power markets across PJM, ERCOT, NYISO, ISO-NE, MISO, CAISO and SPP, which means every incremental megawatt of AI infrastructure load translates into gas burn.

The AI capital expenditure numbers make that concrete. Amazon raised 2026 capital expenditure guidance to $220 billion from $200 billion. Hyperscaler datacenter construction requires firm dispatchable generation, and gas is the only technology that delivers it at scale on the timeline required.

That demand arrives regardless of the weather.

The supply response is where the bull case gets complicated. Producers facing $2.70 gas cut rigs, but associated gas from oil-directed Permian drilling continues flowing with WTI at $84.39. Production growth moderating is not the same as production falling.

The EIA's January framing put 2027 Henry Hub at just under $4.60, a 33% increase from the 2026 average, with reduced storage as the mechanism.

Getting from $2.70 to $4.60 requires the 3,985 Bcf end-October inventory to be drawn down hard by a genuine winter, followed by an injection season that cannot refill it against rising LNG demand.

That sequence is eighteen months of unbroken execution.

Natural Gas Price Forecast: $2.54 and $3.00 Decide the Range

The forecast reduces to two levels and one weekly number.

Upside case. Front-month gas at $2.70 must first reclaim $2.80, the level it traded before the August breakdown, then clear $2.90 and the psychological $3.00 handle. A sustained close above $3.00 would signal the summer low is established and open the path toward $3.20 and eventually the $3.43 area that the July strip carried. The required inputs are specific: Freeport LNG returning to full operation in late August restoring 2.0 Bcf/d of feedgas demand, a genuine late-August heat event pushing weekly injections below the 33 Bcf five-year norm, and production moderating from the record 111.6 Bcf/d as declining rig counts start to bite.

Base case target for the balance of August: $2.85. Bullish target on a heat event plus Freeport return: $3.00 to $3.20.

Downside case. Losing the 52-week low at $2.54 removes the only structural floor beneath the market and opens the $2.40 area, with $2.00 as the terminal reference in a severe warm-winter scenario. That requires weather models to stay moderated through September, weekly injections to hold above 40 Bcf as cooling demand fades, and storage to track toward the EIA's record 3,985 Bcf end-October projection.

Downside target on continued builds: $2.54 initially, $2.40 on a break.

The number that decides it is the weekly injection versus the five-year norm. Storage sits 198 Bcf above the five-year average at 3,153 Bcf, and three of the last four weekly builds have exceeded consensus. As long as injections run above the seasonal norm, the surplus widens and the front month grinds lower regardless of what the winter curve prices.

Verdict: this is a supply market, not a demand market. Lower 48 production at a record 111.6 Bcf/d against LNG feedgas flatlined at 17.3 Bcf/d and moderating weather produces exactly the price gas is delivering. The EIA cut its third-quarter Henry Hub forecast 50 cents to $2.87 and raised its end-October inventory projection to a record 3,985 Bcf in the same update — both moves against the bulls. Gas holds $2.54 while Freeport returns and the heating season approaches. It does not hold if September injections stay above 40 Bcf.

That's TradingNEWS