NG December ($3.06) Leads the Curve as LNG Feedgas Hits 21.2 Bcf/d — Range Holds Between $2.85 and $3.25

The November 2026 natural gas futures contract on the New York Mercantile Exchange expired on Wednesday at $2.776 per million British thermal units, up 7.9 cents, or roughly 3%, on its final session. December futures, which take over as the front month from Thursday, traded near $3.06/MMBtu at the roll, up from roughly $3.02 on Tuesday. The move capped a three-session squeeze that lifted the expiring contract 17.4 cents, or 6.7%, off Monday’s settlement of $2.602, its lowest close since April 28.

The roll itself changes the headline price. Because December carries winter heating demand that November does not, the front of the curve jumps by roughly 28 cents the moment December becomes prompt. That $0.284 gap between November’s $2.776 expiry and December’s $3.06 is a 10.2% contango premium, and it means continuous charts will show natural gas “jumping” above $3.00 even though no single contract rallied by that much on Wednesday.

The fundamental picture is split. On the bullish side, LNG feedgas surged 2.8 billion cubic feet per day to 21.2 Bcf/d, near record levels, and the weekly storage build is expected to come in slightly below the five-year average. On the bearish side, weather forecasts point to above-normal temperatures across the entire Lower 48 into mid-November, Henry Hub spot gas fell to $2.52 on Monday, its lowest since November 2024, and the 12-month futures strip hit a 26-month low of $2.84.

That split is the forecast. LNG exports set a floor under prices that did not exist two years ago. Mild weather caps any rally until forecasts turn colder. Storage near 3,720 Bcf, 34 Bcf above the five-year average, leaves the market comfortable with supply heading into the withdrawal season.

The longer context shows how far prices have fallen. Front-month natural gas hit $7.46 on January 28, 2026, during the peak of winter demand and the Middle East supply shock, and has since dropped 59% to $3.06. Prices are down 16.6% year to date from $3.618 and 19.35% lower than a year ago.

The forecast for the new December front month is a range between $2.85 and $3.25 through mid-November. A shift to colder weather in the 11-to-15-day forecasts, combined with feedgas holding above 21 Bcf/d, would open $3.30 and then the October high near $3.55. Persistent warmth and a larger-than-expected storage build would push December back toward $2.90 and $2.70.

A Three-Day Squeeze From $2.602 to $2.776 Ended the Expiring Contract’s Slide

November’s final week traced a classic expiry squeeze. The contract settled at $2.602 on Monday, October 26, its lowest close since April 28, after a steep sell-off the prior week driven by warming weather forecasts and recovering production. That close capped a stretch in which November had fallen from near $3.30 in mid-October.

Tuesday brought the first leg of the rebound. November rose 9.5 cents to settle at $2.697, bucking declines across the December 2026 through March 2027 winter strip. The contract remained in technically oversold territory for a fifth straight session, the longest such stretch since April, and the low close plus the approaching expiration prompted some short sellers to take profits.

Two catalysts supported the move. LNG feedgas jumped 2.8 Bcf/d to 21.2 Bcf/d, and weather forecasts revised modestly cooler, although temperatures were still expected to remain above average across much of the country. Activity outside the prompt contract was minimal: the 12-month strip lost a penny to $2.858, Calendar 2027 fell 2 cents to $2.99, and Calendars 2028 and 2029 were unchanged at $3.63 and $3.66.

Wednesday completed the squeeze. November pressed upward from the start of its final session as trading volumes thinned and demand drivers diverged. It traded up 8 cents at $2.78 in the morning and settled 7.9 cents higher at $2.776. Forecasts for more demand this week than previously expected and rising gas flows to LNG export plants in recent weeks supported the final push.

The short-term technical levels were tight. From Tuesday’s session, support sat at $2.673, the pivot at $2.71 and resistance at $2.777. November’s expiry at $2.776 landed one-tenth of a cent below that resistance, which shows the squeeze ran exactly as far as the short-covering would take it.

The expiry squeeze tells you little about direction. Short sellers in the November contract had to close positions or take delivery by the end of Wednesday, and many chose to buy back rather than deliver. That buying lifts the expiring contract regardless of fundamentals. The real test of sentiment is how December trades from Thursday, when it carries the full weight of front-month speculative positioning without the expiry distortion.

Henry Hub Spot Hit $2.52, Its Lowest Since November 2024

The physical market has been weaker than futures. Next-day gas at Henry Hub in Louisiana, the delivery point for NYMEX futures, fell to $2.52/MMBtu on Monday, October 26, its lowest since November 2024. Spot prices had been as high as $3.30 on October 15, which means the physical benchmark fell 78 cents, or 23.6%, in seven trading days.

The spot slide shows the daily balance. Spot prices reflect the cost of gas for immediate delivery, and they fall when supply exceeds same-day demand. Mild weather across the country cut heating and power-burn demand in the second half of October, while production recovered, which left more gas chasing fewer buyers. Henry Hub spot fell from $3.10 on October 20 to $3.01 on October 21, $2.95 on October 22, $2.78 on October 23 and $2.52 on October 26.

Tuesday’s rebound was sharp. Henry Hub spot recovered to $2.76 on October 27, up 24 cents, or 9.5%, as LNG feedgas jumped and weather forecasts cooled slightly. That bounce matched the futures squeeze and showed that physical buyers stepped in once prices fell below $2.60.

The gap between spot and futures is now wide. With Henry Hub spot at $2.76 and December futures near $3.06, the forward curve prices a 30-cent premium for gas delivered in December over gas delivered tomorrow. That premium reflects the market’s expectation of colder weather and higher demand in December than in late October. It also creates a risk: if December weather turns out as mild as current forecasts suggest, the premium will compress as the contract approaches delivery.

Regional spot markets showed strength in the East. Eastern natural gas prices roared back late last week, claiming the lion’s share of gains, as strong LNG feedgas demand, declining Canadian imports and below-average storage injections offered support. Transco market-zone basis came back under pressure on Friday, October 23, after recent tightening, a reminder that regional prices can swing sharply as pipeline flows adjust.

Lower Gulf Coast gas prices are helping industrial users. Dow is maintaining its Gulf Coast manufacturing advantage despite rising ethane costs, reporting strong petrochemical operating rates amid lower regional natural gas prices and growing industrial demand. Cheap gas is a direct input-cost advantage for chemical producers.

NOAA Sees Above-Normal Temperatures Across the Entire Lower 48

Weather is the dominant bearish driver. The National Oceanic and Atmospheric Administration’s 6-to-10-day outlook favors above-normal temperatures across the East and much of the northern tier, while the West is expected to remain closer to average. The 8-to-14-day outlook broadens the warmth, with above-average temperatures expected across the entire Lower 48.

That outlook covers the critical transition period. From October 28 to November 3, high-demand areas are expected to see near-to-warmer-than-normal temperatures, which keeps heating demand light. The first two weeks of November usually mark the start of heating season in the Midwest and Northeast, where most residential gas demand is concentrated. Above-normal temperatures through mid-November delay the seasonal ramp in consumption.

The forecasts only extend so far. NOAA’s outlook runs out to mid-November, while December futures price demand for the entire month of December. Historically, demand picks up sharply in December, and the market is betting that pattern will hold even if November is mild. That bet is what supports the roughly 28-cent premium of December over November.

Weather revisions have been the main source of daily volatility. The modestly cooler revisions on Tuesday and Wednesday helped trigger the expiry squeeze, even though the forecasts remained warmer than normal. Each run of the major weather models that adds or removes heating degree days moves futures by several cents. The market is primed to react sharply to any sign of a cold pattern emerging in the 11-to-15-day window.

Degree days for the week ending October 30 are expected to ease to 62.4, well below last year’s 90.4 for the same week, when an early cold snap cut the storage build to 33 Bcf. That comparison shows how mild this autumn has been relative to 2025, and it explains why storage injections are running close to normal rather than below.

The bearish trend in weather is clear. Warm forecasts are driving a downtrend in futures, and even the December contract’s gains on Wednesday are unlikely to change the main trend, although they could fuel a two-to-three-week counter-trend rally. A sustained rally would require a cold pattern to show up in the forecasts for the second half of November or early December.

LNG Feedgas Jumped 2.8 Bcf/d to 21.2 Bcf/d

LNG exports are the most important structural support for US natural gas. Feedgas to US LNG export plants jumped 2.8 Bcf/d to 21.2 Bcf/d this week, near record levels, as more export capacity came online and plants returned from maintenance. LNG hit new highs in recent days, and feedgas deliveries to the nine major export plants averaged 19.2 Bcf/d over the past two weeks.

That demand did not exist at this scale two years ago. US LNG exports have grown with new export terminals, and global buyers have leaned on US cargoes as the Middle East conflict disrupted supplies from Qatar and other Gulf producers. Every Bcf/d of feedgas is gas that leaves the domestic market, which tightens the US balance and sets a floor under Henry Hub prices.

The gap between US and global prices drives the flow. With Henry Hub near $2.76 spot and $3.06 for December, and global LNG prices far higher amid Middle East disruption, US exporters earn wide margins on every cargo. New US LNG export contracts are priced at roughly 119% of Henry Hub plus a liquefaction fee of $2.80 to $3.23/MMBtu, which means even at $3.06 Henry Hub, the delivered cost of US LNG stays well below Asian and European spot prices.

Maintenance is the main swing factor. Freeport LNG’s feedgas stayed sharply reduced on Wednesday, cutting US gas demand. Freeport is one of the largest export terminals on the Gulf Coast, and its outages have repeatedly caused sharp drops in feedgas and futures prices. When Freeport returns to full capacity, total feedgas could rise further from 21.2 Bcf/d.

The LNG floor explains why the sell-off stopped near $2.60. With 21 Bcf/d of demand that does not respond to US weather, the market cannot fall as far as it did in earlier years when mild weather met record production. Physical buyers for export absorb surplus gas that would otherwise depress prices.

The LNG ceiling is also visible. Feedgas can only rise as fast as export capacity allows. At 21.2 Bcf/d, the plants are running close to their limits, which means LNG can stop prices from falling but cannot by itself drive a sustained rally. That role belongs to weather.

Thursday’s Storage Report Is Expected to Show a 76 Bcf Build

The Energy Information Administration publishes its weekly storage report at 10:30 a.m. ET Thursday, October 29, covering the week ended October 23. Expectations call for a 76 Bcf injection, one Bcf below the 77 Bcf five-year average and one Bcf above last year’s 75 Bcf build. Estimates vary: one forecast calls for 68 Bcf, down 9 Bcf from the prior week, and a modeled supply-demand balance points to 71 Bcf.

A 76 Bcf injection would put working gas near 3,720 Bcf. That is roughly 34 Bcf above the five-year average and 151 Bcf below year-ago levels. The two comparisons tell different stories. Against the five-year average, storage is comfortable. Against last year, when an early cold snap and different production dynamics shaped the balance, it is lower.

The previous report set the tone. The EIA reported a 77 Bcf injection for the week ended October 16, below the 80 Bcf expected and up from 67 Bcf the prior week. Earlier in October, injections came in at 85 Bcf for the week ended October 2, above the 79 Bcf expected, and 67 Bcf for the week ended October 9, below the 76 Bcf expected. The pattern of misses in both directions shows how sensitive the weekly number is to small shifts in weather and flows.

The supply-demand balance tightened during the report week. The daily balance tightened by 2.4 Bcf/d, from 12.6 to 10.2 Bcf/d of implied injection, as LNG feedgas climbed and some power demand persisted in the South. A tighter balance means less gas available for storage, which supports the lower end of the injection estimates.

The South Central region carries the most weight. South Central storage stood at 1,125 Bcf in the latest data, up 28 Bcf, and that region holds the salt-dome facilities that respond fastest to price signals. Pacific storage stood at 297 Bcf, up 3 Bcf.

The market reaction depends on the surprise. An injection below 70 Bcf would signal a tighter balance than expected and support December above $3.10. An injection above 80 Bcf would confirm that mild weather and production are overwhelming LNG demand and push December toward $2.95. A print near 76 Bcf would be neutral, leaving weather forecasts to set the direction.

End-October Storage Is Forecast Near 3,850 Bcf, 2% Above Normal

The injection season is ending with comfortable inventories. The EIA’s October Short-Term Energy Outlook, completed on October 1, estimated that the United States held 3,523 Bcf of natural gas in storage at the end of September. The forecast sees inventories building by 328 Bcf during October, slightly less than average, to reach 3,850 Bcf at the end of October, which would put stocks 2% above the five-year average to start the heating season on November 1.

That forecast is now four weeks old. It does not incorporate the late-October weather or the rise in LNG feedgas. Modeled balances point to storage reaching roughly 3,790 Bcf by October 30, followed by a 53 Bcf injection for the week ending November 6 that would take inventories to around 3,843 Bcf. The modeled end-of-injection-season figure for October 31 is 3,802 Bcf, with a peak of 3,888 Bcf around November 17.

The difference between those forecasts is about 50 Bcf, small relative to total storage but meaningful at the margin. A peak near 3,888 Bcf in mid-November would still leave the market well supplied entering winter. Injections can continue into mid-November when weather stays mild, as it is forecast to this year, which pushes the seasonal peak later and higher.

Above-average inventories limit upward price pressure. The EIA’s outlook states that ample natural gas inventories, relative to the previous five-year average, limit upward price pressures in its forecast, with inventories remaining above the rolling five-year average in most months, as ongoing growth in production supplies increases in LNG exports and domestic demand.

Storage provides a buffer, but not an unlimited one. Prolonged periods of cold weather could increase withdrawals beyond forecast. A cold December or January that pulls 150 to 200 Bcf a week from storage would erode the surplus quickly, especially with LNG exports running at 21 Bcf/d and leaving less gas available for domestic heating.

The next EIA Short-Term Energy Outlook is due November 10. It will update the end-of-October storage estimate with actual data and revise the winter withdrawal forecast. A downward revision to end-of-season inventories would be a bullish signal for December and January futures.

The 12-Month Strip Hit a 26-Month Low of $2.84

The forward curve shows how little concern the market has about supply. The NYMEX 12-month strip, the average price of the next 12 monthly contracts, fell to a 26-month low of $2.84/MMBtu. It settled at $2.858 on Tuesday, down 1.1 cents, and the 24-month strip stood at $3.214. Calendar 2027 traded at $2.99, below $3.00.

A low strip signals that traders expect supply to meet demand comfortably through next year. Production growth, ample storage and expectations of moderate weather have pulled down prices for the entire curve, not just the front months. That is a broader bearish signal than a weak prompt month, because it reflects expectations for all of 2027.

The curve still prices winter premiums. December 2027 settled at $4.019 on Tuesday and January 2028 at $4.448, well above the 12-month strip. Those deferred winter contracts reflect the expectation that peak winter demand will be higher in future years as LNG export capacity grows further. Calendars 2028 and 2029 traded at $3.63 and $3.66.

The gap between the near-term and longer-dated curve creates a steep contango. December 2026 at $3.06 sits 96 cents below December 2027 at $4.02, a 31% premium for gas a year forward. That structure rewards storage operators who can buy cheap gas now and sell it forward, which encourages injections and keeps near-term prices under pressure.

The summer contracts are relatively firm. Deferred summer-strip April natural gas futures traded slightly higher on Wednesday, reflecting expectations that LNG demand will keep summer balances tighter than in past years.

The curve shape matters for the December forecast. A steep contango means December has to overcome the gravitational pull of the curve to rally. As December approaches delivery, its price will converge toward spot Henry Hub. If spot stays near $2.76, December has 30 cents of downside to close the gap. If weather turns cold and spot rallies, December can hold or extend its premium.

From $7.46 in January to $3.06: A 59% Collapse in Nine Months

Natural gas has fallen hard in 2026. Front-month futures reached $7.46/MMBtu on January 28, the year’s peak, during the first weeks of the Middle East conflict and a cold January. From that high, prices have dropped $4.40, or 59%, to $3.06. The 52-week low came at $2.523 on April 24, during the spring shoulder season.

The year-to-date decline stands at 16.6%, from $3.618 at the start of 2026 to $3.017 at Tuesday’s close. Prices are 19.35% lower than a year ago and 18.1% down on a separate year-over-year measure. Over the past month, they have risen 2.18%, because late September prices were already depressed.

October has been volatile. The month-to-date range for the continuous front month ran from a high of $3.283 to a low of $2.602, a span of 68 cents, or 22% of the low. The October average stood at $3.034. Earlier in the month, prices traded near October highs around $3.55 to $3.57 on certain contracts before the late-month slide.

The decline reflects production growth and mild weather. US natural gas production has continued to grow, supplying increases in LNG exports and domestic demand. Two mild shoulder seasons, in spring and autumn, allowed storage to refill without the price spikes that a hot summer or early cold snap would have caused.

The moving averages frame the trend. At Tuesday’s close of $3.017, the continuous front month sat below its 200-day average of $3.079 and above its 50-day average of $2.958. December’s move to $3.06 puts it between those two averages, just below the 200-day. A sustained break above $3.079 would be the first sign that the longer-term downtrend is losing momentum.

The January peak is a reminder of how fast natural gas can move. A cold winter combined with high LNG demand could push prices back toward $4 to $5 within weeks. The forward curve’s $4.02 price for December 2027 and $4.45 for January 2028 shows the market expects future winters to be tighter than this one. For December 2026, the market is betting on a mild start to winter.

Brent at $115 and the Middle East Keep Global Gas Tight While US Gas Stays Cheap

The contrast between US gas and global energy prices is extreme. Front-month Brent crude traded at $115.30 on Wednesday after a Houthi claim of a strike on Saudi Arabia’s Ras Tanura refinery, and December WTI traded at $101.79. With December natural gas at $3.06, the WTI-to-gas price ratio stands at 33 to 1, far above the long-run average near 10 to 1. On an energy-equivalent basis, US natural gas is among the cheapest fuels in the world.

The Middle East conflict has tightened global gas markets. Disruptions to Gulf shipping and the risk of attacks on Qatari export facilities have kept LNG prices in Asia and Europe elevated. More than 30 maritime incidents in the Strait of Hormuz in October, up from 14 in September, have raised insurance and freight costs for cargoes leaving the Gulf. Reports on Wednesday that Washington has told Gulf states to prepare for renewed strikes on Iran after the November 3 US midterms add to that risk.

US gas benefits indirectly. Global buyers have turned to US LNG as a reliable alternative to Gulf supply, which keeps US export terminals running at capacity. That demand is the reason feedgas reached 21.2 Bcf/d. But because export capacity is fixed in the short term, the global price premium cannot pass through to Henry Hub beyond what the terminals can ship.

That bottleneck explains the price gap. US natural gas cannot rise to global prices because there is no additional capacity to export it. Domestic production exceeds what the export terminals and domestic consumers can absorb at higher prices, which leaves Henry Hub priced on US weather and storage rather than global conditions.

Cheap gas is reshaping industrial demand. Gulf Coast chemical producers like Dow are running petrochemical plants at strong rates because gas, their primary feedstock and fuel, is cheap relative to oil-linked inputs used by competitors abroad. Growing industrial demand adds a further slow-moving support to the US balance.

The geopolitical risk cuts both ways for US gas. An escalation after November 3 that disrupted Qatari exports would raise global LNG prices further and strengthen demand for US cargoes, but with feedgas already near capacity, the effect on Henry Hub would be limited. A settlement that eased global gas prices would reduce the urgency of US LNG purchases but would not change the volume flowing through US terminals in the near term.

Producers, Exporters and the ETF Complex Trade the Weather

Equities tied to natural gas reflect the split in fundamentals. EQT (NYSE: EQT), the largest US natural gas producer, traded at $55.11 on Tuesday, up 0.47%, holding steady despite the sell-off in futures. Cheniere Energy (NYSE: LNG), the largest US LNG exporter, traded at $299.26, down 0.44%. Coterra Energy (NASDAQ: CTRA) fell 8.62% to $32.56 on Wednesday after its quarterly report, one of the biggest decliners in the energy sector.

The producer-exporter split mirrors the commodity. Producers like EQT earn more when Henry Hub rises and suffer when warm weather pushes prices down. Exporters like Cheniere earn on the spread between cheap US gas and expensive global LNG, which means low Henry Hub prices are good for their margins. A mild winter with high global prices is the best outcome for exporters and the worst for producers.

Production has been recovering. Mild weather and recovering production countered strong export demand earlier this week, and production growth is the main reason the EIA expects inventories to stay above the five-year average through most of its forecast period. Producers have kept output high despite falling prices, partly because associated gas from oil drilling rises when crude prices are above $100.

That associated-gas effect is significant this year. With WTI above $100, oil producers in the Permian Basin and other shale fields are drilling more wells, and each oil well produces gas as a by-product. That gas reaches the market regardless of Henry Hub prices, which adds supply that does not respond to the price signal. High oil prices are, in effect, a bearish factor for US natural gas.

The ETF complex offers leveraged exposure to the trend. The United States Natural Gas Fund (UNG) tracks front-month futures, and leveraged products like ProShares Ultra Bloomberg Natural Gas (BOIL) and ProShares UltraShort Bloomberg Natural Gas (KOLD) amplify daily moves. The steep contango in the curve penalizes long-only funds that roll from cheaper front months into more expensive deferred contracts, which erodes returns during periods like this one.

The roll from November to December is a specific cost for those funds. A fund rolling from $2.776 November into $3.06 December pays a roughly 10% premium, which means the fund needs December to rise more than 10% before delivery just to break even on the roll.

The Technical Map: December Between $2.958 and $3.079

December’s chart, now the front month, sits between two important moving averages. On the continuous front-month chart, the 50-day average stands at $2.958 and the 200-day at $3.079. December at $3.06 trades 1.9 cents below the 200-day and 10.2 cents above the 50-day. A close above $3.079 would put the front month above its 200-day average for the first time since the October sell-off began.

Support on the December contract starts at $3.00, the round number that has acted as a pivot through October. Below that, the 50-day average at $2.958 is the next level. A close below $2.958 would signal that the downtrend is resuming. Below that, the $2.85 area, where the 12-month strip sits near its 26-month low at $2.84, is the next support. The deeper target is $2.70, close to where November traded before its expiry squeeze.

Resistance begins at $3.079, the 200-day average. Above that, $3.10 marks the level where natural gas traded on October 26 before the latest decline, and $3.16 to $3.18 marks the short-term moving average cluster on the four-hour chart. The medium-term averages on that chart sit between $3.29 and $3.32, and the October highs near $3.55 to $3.57 are the major resistance.

The distances frame the risk. From $3.06, the downside to $2.958 is 10.2 cents, or 3.3%, and to $2.85 is 21 cents, or 6.9%. The upside to $3.30 is 24 cents, or 7.8%, and to $3.55 is 49 cents, or 16.0%.

The technical setup favors a counter-trend rally within a downtrend. The expiry squeeze, the oversold conditions that persisted for five sessions on November and the rebound in LNG feedgas could fuel a two-to-three-week bounce in December. That bounce would likely stall near $3.30 unless weather forecasts turn colder.

Volatility will stay high around Thursday’s storage report and each weather model update. Natural gas regularly moves 3% to 5% in a single session on weather revisions, and December’s first days as the front month typically see heavier volume as speculative positions roll into the contract.

Natural Gas Forecast: December $2.85–$3.25, $3.30 on Cold, $2.70 on Persistent Warmth

The forecast for natural gas futures turns on weather, with LNG demand as the floor and storage as the cushion. November expired at $2.776 after a three-day squeeze from $2.602, December takes over near $3.06 with a 28-cent winter premium, and Thursday’s storage report is expected to show a 76 Bcf build that would leave inventories near 3,720 Bcf, 34 Bcf above the five-year average.

The base case is a range between $2.85 and $3.25 for December through mid-November. NOAA’s warm 6-to-10 and 8-to-14-day outlooks hold, LNG feedgas stays near 21 Bcf/d, storage injections run close to the five-year average, and the market waits for the first signs of a cold pattern in late November or December. December oscillates between its 50-day average at $2.958 and resistance near $3.25.

The bullish case targets $3.30, then the October high near $3.55. It requires weather forecasts that shift colder in the 11-to-15-day window, a storage injection below 70 Bcf on Thursday that signals a tighter balance, LNG feedgas climbing above 21.2 Bcf/d as Freeport returns to full capacity, and a December close above the $3.079 200-day average. Escalation in the Middle East after November 3 that strengthened global LNG demand would add support.

The bearish case targets $2.85, then $2.70. It requires warmth that persists into late November, a storage injection above 80 Bcf, a peak in inventories near or above 3,888 Bcf in mid-November, and continued production growth from associated gas in oil basins. A close below the $2.958 50-day average would confirm the downtrend has resumed, and the steep contango would pull December toward spot Henry Hub near $2.76 as delivery approaches.

The verdict is neutral with a bearish tilt in the near term and a constructive bias into winter. The fundamentals that drove the October sell-off, mild weather, ample storage and recovering production, remain in place, and the 12-month strip at a 26-month low shows the market expects comfortable supply. But LNG feedgas at 21.2 Bcf/d has put a floor under prices that held at $2.60, and December’s winter premium is justified by historical demand patterns. December natural gas at $3.06 is a sell on rallies toward $3.25 to $3.30 while weather stays warm, a buy on dips toward $2.85 to $2.90 for a winter bounce, and a breakout above $3.30 on a cold forecast shift opens $3.55.

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