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Natural gas price transparency and key news, insights, and data for the North American energy markets
Updated: 1 week 20 hours ago

Natural Gas Forwards Steady as Market Waits for Summer Cooling Demand

Thu, 04/11/2024 - 13:54

With the market weighing mild shoulder season weather and bloated storage against weaker production, regional natural gas forward prices generally held steady at the front of the curve during the April 4-10 trading period.

Fixed prices at benchmark Henry Hub finished the period at $1.888/MMBtu for May delivery, up 4.3 cents week/week, according to NGI’s Forward Look. Numerous Lower 48 hubs similarly finished within a nickel of even.

There were some exceptions, notably in the Permian Basin, where the region’s oil-driven economics contributed to an inversion of natural gas prices for May delivery.

Permian Pain Point

Fixed prices at El Paso Permian, Waha and Transwestern all sold off sharply for May and across the peak summer contracts during the April 4-10 trading period, Forward Look data show.

Amid weak demand and pipeline constraints, daily spot prices in the Permian have averaged in the negatives more often than not since mid-March, NGI’s Daily Historical Data show.

[Want to visualize Henry Hub, Houston Ship Channel and Chicago Citygate prices? Check out NGI’s daily natural gas price snapshot now.]

Negative near-term pricing in the region has shown few signs of letting up recently; if anything, price pressures have increased. Between the April 4 and April 10 trade dates, Waha spot prices went from averaging minus-33.0 cents to minus-$2.015.

That market pressure spilled over into May fixed price forwards, pulling regional hubs into the negatives. For example, natural gas for May delivery at Waha ended the April 4-10 trading period at minus-18.6 cents, down 40.3 cents week/week.

According to the U.S. Energy Information Administration (EIA), the South Central region injected 18 Bcf into storage during the week ending April 5, with regional stockpiles ending at 1,014 Bcf, 36.3% higher than the five-year average.

Adding to the pressure on Permian natural gas prices, Kinder Morgan Inc.’s Gulf Coast Express Pipeline has planned maintenance for a compressor overhaul at multiple stations in effect until early May. More work is slated for mid-May, according to the operator.

Pricing points downstream of the Permian also came under downward pressure for May in recent trading. SoCal Border Avg. May fixed prices fell 8.7 cents week/week to $1.503.

Surplus Seen Lingering on Mild Temps

Recent forecasts suggested spring weather might do little to ameliorate the uncomfortably large storage cushion inherited following a mild winter.

Somewhat cooler conditions expected over the northern United States around April 19-24 could deliver “closer to seasonal demand” for natural gas, though models were struggling to pin down exactly how much cold will reach northern and eastern portions of the Lower 48, according to NatGasWeather.

“Also of consideration, much of the weather data favors a very nice U.S. pattern returning April 26-May 5 with highs of 50s to 80s for a swing back to very light national demand,” the firm said. 

According to EBW Analytics Group analyst Eli Rubin, the mild weather-driven demand on tap, by stalling the market’s efforts to bring down storage surpluses, could “open pockets of weakness” for natural gas prices.

“It remains possible that the storage surplus versus the five-year average will be higher at the end of April than at the end of March,” Rubin said. 

That said, the firm expects “fundamental upside to materialize into early summer,” according to the analyst.

The market may have to endure “an extended period of subdued prices this spring” first, Rubin said. “Eventually, however, the market may rally” as a combination of weaker production, stronger liquefied natural gas demand and summer cooling demand helps “soak up excess inventories to put Nymex futures on a sustainable path higher.”

EIA reported a larger-than-expected 24 Bcf injection for the week ended April 5 that kept the Lower 48 surplus versus the five-year average unchanged at 633 Bcf.

The result appeared to amplify market concerns over the excess molecules in storage at this point in the season. The May Nymex contract plunged double-digits Thursday.

“The current surplus to the five-year means that any pressure from regulators to fill storage to mandatory levels for the coming winter will be absent for quite some time,” analysts at Gelber & Associates said. The “sizable” build from the latest EIA print speaks to “the sheer amount of cheap gas in the market.”

The post Natural Gas Forwards Steady as Market Waits for Summer Cooling Demand appeared first on Natural Gas Intelligence

Natural Gas Forwards Entering Shoulder Season in Search of Recovery

Thu, 04/04/2024 - 13:52

Regional natural gas forward prices advanced during the March 28-April 3 trading period as the start of the spring injection season found market bulls searching for signs of green shoots after a bitter winter.

May fixed prices at Henry Hub rallied 12.1 cents to $1.845/MMBtu, setting the pace for similar front-month gains across much of the Lower 48, NGI’s Forward Look data show.

Working Down The Storage Glut

With the winter that wasn’t officially in the books, the market can shift its attention to the injection season. 

Pricing dynamics across the curve reflect a market caught between an exceptionally mild winter and rosier expectations for demand heading into 2025. At $1.60-plus, the May/December spread at the start of April was as high as it’s been in at least a decade, recent Forward Look data show.

Fixed prices for December 2024 delivery at Henry Hub rallied 8.6 cents during the March 28-April 3 trading period to average $3.479.

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As of March 29, Lower 48 storage stood at 2,259 Bcf, still 633 Bcf above the five-year average, according to the U.S. Energy Information Administration (EIA). The last time storage was this high exiting the withdrawal season was in 2016, EIA data show. 

Analysts at Mobius Risk Group recently pegged end-of-withdrawal storage at around 2.26 Tcf, which would leave the market “just under 1.8 Tcf of spare capacity to manage” between now and the end of October.

It’s still “far too early” to have any certainty around where inventories may sit at the end of injections, the analysts noted.

Estimates for the end-October exit level have begun to “show a wider variance, as well as a trend lower as production levels have sharply declined,” the Mobius analysts said. “Just a few short months ago, the majority of estimates would have ranged from 4-4.3 Tcf, and we now see a significant number” of estimates below 4 Tcf.

The Mobius analysts pointed to the cumulative storage build for the month of April as “the key number to focus on” as the injection season gets underway.

“How the market comes out of the gates in the injection season will be critical” given the current excess inventories, they said. If the storage surplus doesn’t trend lower at a sufficient rate, it could mean “an elongated production-curtailing price environment.”

EBW Analytics Group analyst Eli Rubin similarly pointed to bringing down the inventory surplus as the prime focus for the market in the coming months.

“The overriding market narrative this spring will be the pace of reductions” in excess storage, both in the United States and Canada, Rubin said. “Near-term progress may falter into late April and May, however – raising risks of a relapse lower for natural gas.

“Further, if prices rise, the market will adjust by reducing demand via gas-to-coal switching and quickly returning withheld supply – quelling upside potential.”

Weather-driven demand may not offer much help in keeping April inventory injections lean.

Recent long-range forecasting pointed to light demand nationally amid “exceptionally comfortable” conditions for the Lower 48 heading into the back half of April, according to NatGasWeather.

Weather patterns starting in the upcoming week and continuing through April 20 appeared likely to see storage surpluses “stall or increase slightly” absent colder trends, the firm said.

“However, as soon as more bullish weather patterns work in concert with tighter production, surpluses will decrease in time,” NatGasWeather said. “The primary question remains when. Our modeling suggests gradual surplus reductions over the next two months, then with the opportunity to accelerate at a faster pace June through September as a hotter-than-normal summer impacts much of the U.S.”

West Texas Discounts

Meanwhile, for Permian Basin hubs, forward prices at the front of the curve did not see the same uplift during the March 28-April 3 period compared to the rest of the Lower 48.

Amid a combination of weak demand and pipeline constraints, negative spot prices have become routine for locations like Waha, El Paso Permian and Transwestern recently.

Front month fixed prices at the two hubs managed to stay in positive territory but came under downward pressure in recent trading, Forward Look data show.

Waha gave up 2.0 cents week/week to end at 21.7 cents, with May basis at the hub widening to minus-$1.624.

Permian natural gas markets could see more of the same “throughout the spring,” RBN Energy LLC analyst Lindsay Schneider said in a recent blog post.

“As we head into the shoulder months and gas demand…continues to sag, the pressure on Waha prices will continue,” Schneider said. “And that means that maintenance events – even small disruptions – could send Waha prices well below zero.”

The post Natural Gas Forwards Entering Shoulder Season in Search of Recovery appeared first on Natural Gas Intelligence

Natural Gas Forwards Continue to Struggle as Market Wrestles with Storage Glut

Thu, 03/28/2024 - 13:07

As an outsized storage surplus continued to hang over the outlook, regional natural gas forward prices shed value during the March 21-27 trading period, NGI’s Forward Look data show.

Front month fixed prices at benchmark Henry Hub fell 12.7 cents for the period to end at $1.577/MMBtu. However, the benchmark also saw double-digit losses for the May and June contracts.

Fixed prices for June 2024 delivery at Henry dipped below $2.000 during the period to $1.959, Forward Look data show.

[Mexico Matters: Cross-border energy trade between the U.S. and Mexico reached $82 billion last year. Understand this burgeoning trade flow — the projects, politics and natural gas prices — with NGI’s Mexico Gas Price Index. Know more.]

April Futures Swoon

The April Nymex futures contract finished its last day of trading during the March 21-27 period, rolling off the board with a whimper Tuesday at only $1.575. According to historical data obtained by NGI, that ranks among the lowest monthly settlement prices for natural gas futures on record going back decades.

A few months into the pandemic, the July 2020 contract settled at $1.495. Other than that, all other monthly final settlement prices lower than April 2024 occurred in the early to mid-1990s, historical data show. 

The last April contract to finish lower than April 2024 was April 1995, when the contract closed at $1.566. Based on the Consumer Price Index, the April 1995 contract would be valued at around $3.20 in today’s dollars.

The historically weak finish for April Nymex futures followed a stretch of meager pricing at Henry Hub in the physical market, EBW Analytics Group analyst Eli Rubin noted.

According to NGI’s Daily Gas Price Index, daily average spot prices at Henry Hub fell as low as $1.240 in March and fell below the $1.500 mark on numerous occasions.

It has been a winter to forget for natural gas bulls, one that has left the market with a lofty storage surplus to whittle down in the coming months. 

According to U.S. Energy Information Administration data, total Lower 48 storage stood at 2,296 Bcf as of March 22, 669 Bcf above the prior five-year average. The agency reported a 36 Bcf withdrawal for the week ended March 22, shrinking the year-on-five-year surplus for the first time since January.

“Market inroads reversing the storage surplus versus the five-year average could help stem bearish risks in the immediate term,” according to Rubin. “Still, weather-driven demand could fall 12-14 Bcf/d over the next three storage weeks, while a lack of demand or capacity for injections…may maintain near-term downside price risks.”

Permian Constrained, For Now

Consistent with recent natural gas spot pricing in the Permian Basin, El Paso Permian, Transwestern and Waha fixed prices for April delivery exited the March 21-27 trading period in the negatives. 

April fixed prices at El Paso Permian, for example, dropped 13.4 cents week/week to end at minus-0.9 cents, Forward Look data show.

Still, pricing further along the curve foreshadowed strengthening basis differentials for the region later this year. 

A $1.691 discount to Henry Hub at Waha for April 2024 in recent Forward Look prices compares to a negative differential of just 59.9 cents for December 2024.

East Daley Analytics analysts recently called 2024 a “mullet year” for the Permian Basin, in reference to the classic haircut. In other words, 2024 is poised to feature a “party in the back” as “new natural gas infrastructure unlocks growth late in the year.”

Flows of associated natural gas out of the prolific Permian remain subject to constraints until the Matterhorn Express Pipeline is ready to enter service. This could keep “supply growth in check” until the second half of 2024, the East Daley analysts said.

Springtime pipeline maintenance appears to be only adding to the pressure on Permian producers trying to get their gas downstream.

The El Paso Natural Gas Pipeline (EPNG) on Tuesday said it was extending the duration of “anomaly repairs” on its Line 2000 downstream of the Casa Grande C Compressor Station, with work now expected to last through May. 

Operational capacity through EPNG’s GILA and CASA C constraints, both in Arizona, will continue to be reduced, the operator said.

“The high water table near the Gila River is making access to the anomaly difficult,” EPNG told shippers in a notice on its electronic bulletin board. “Temporary groundwater wells are being installed to reduce the influx of groundwater into the excavation area and facilitate safe access for the repair crew to complete the anomaly repair.”

Still, recent forward pricing downstream of the EPNG constraints in Southern California suggests limited buying pressure for the next few months. SoCal Citygate May fixed prices tumbled 26.6 cents to $2.105 during the March 21-27 trading period. SoCal Border Avg. May fixed prices exited the period at $1.509, down 18.7 cents, Forward Look data show.

The post Natural Gas Forwards Continue to Struggle as Market Wrestles with Storage Glut appeared first on Natural Gas Intelligence

Permian Natural Gas Forward Prices Plummet; Other Markets Seeing Basis Improvement

Thu, 03/21/2024 - 12:27

Natural gas forward prices pushed modestly higher at the front of the curve during the March 14-20 trading period, particularly in the Northeast and Appalachia, data from NGI’s Forward Look show.

Meanwhile, spring contracts at hubs near the congested Permian Basin struggled under the weight of weak near-term fundamentals.

Fixed prices for April delivery at benchmark Henry Hub added 4.1 cents week/week to exit the period at $1.704/MMBtu. Modest front month fixed price gains were the norm for most of the Lower 48.

West Texas Woes

With the market awash in supply exiting an exceptionally mild winter, and amid reports of downstream pipeline constraints, associated gas from the oily Permian has struggled to find takers recently. Regional spot prices illustrate the lack of demand for Permian gas.

Waha, for instance, posted a negative daily spot price average throughout the March 14-20 trading period, according to NGI’s Daily Gas Price Index. NGI recorded spot trades as low as minus-$2.350 at the hub during the period.

Forward contracts felt the gravity of the negative spot market trades, and April fixed prices fell to near zero during the period, Forward Look data show.

Waha prices for April delivery tumbled to just 8.0 cents, a 27.2-cent discount week/week. El Paso Permian front month fixed prices dropped 24.9 cents to exit the period at 12.5 cents.

The South Central saw a net 21 Bcf injection into storage for the week ended March 15, leaving regional stockpiles at a 41.7% surplus to five-year average levels, according to U.S. Energy Information Administration (EIA) data.

Permian producers have seen a number of pipeline projects come online in the past few years to provide incremental takeaway capacity for their associated gas volumes, RBN Energy LLC’s Housley Carr said in a recent blog post.

However, “continued crude oil production growth through the early 2020s has once again put gas production and egress capacity on a knife’s edge,” Carr said. 

Recent expansions for the Permian Highway Pipeline and the Whistler Pipeline have “provided a little breathing room,” while the 2.5 Bcf/d Matterhorn Express Pipeline should “give a lot more when it comes online in the second half of this year,” according to Carr.

Nymex Futures Mixed

Front month Nymex futures experienced ups and downs during the March 14-20 trading period as the market contemplated some moderate late season cooling that still paled in comparison to lost demand from an exceptionally mild winter overall.

The market has found itself dealing with excess storage following “blowtorch February and March weather conditions,” EBW Analytics Group analyst Eli Rubin noted. 

In the coming weeks, the surplus versus the five-year average “may finally begin to peak and retreat to allow bulls to at least gain traction,” Rubin said. “Still, we caution that the pathway toward a more manageable storage surplus may be long and slow, with a prolonged period of weakness favored at the front of the Nymex forward curve to sustain power sector coal-to-gas switching and keep excess natural gas supply off the market.”

Appalachia Basis Strength

Recent Nymex futures pricing reflects “inventory congestion risks,” but “numerous basis markets have been on the mend of late,” analysts at Mobius Risk Group observed in a recent note.

Forward Look data bear out this trend of regional basis strengthening, particularly for Appalachian hubs.

Basis pricing at Eastern Gas South has rallied around 40-60 cents for April 2024 through October 2024 since the start of winter. October 2024 pricing has swung 63.3 cents higher winter-to-date, from minus-$1.659 to minus-$1.026.

Broadly, this parallels regional production trends. According to Bloomberg data, Appalachian dry gas production peaked above 36 Bcf/d in late 2023. Volumes had fallen off to around 33.2 Bcf/d as of recent estimates Thursday.

This comes as numerous regional operators have signaled plans to curtail output this year in response to weak prices.

SoCal Basis Premiums Fade

Meanwhile, unlike other markets, Western Lower 48 hubs have seen premiums that were “largely in place following last year’s inverse inventory dynamic” fade over the course of the winter, the Mobius analysts noted. They pointed in particular to pricing at the Southern California border.

According to Forward Look data, SoCal Border Avg. basis for April was trading at a 40.8-cent premium to Henry Hub at the start of November. April basis there has since flipped to a 3.4-cent discount versus the national benchmark.

As of the week ended March 15, Pacific region storage totaled 216 Bcf, 50% higher than the five-year average and 200% above year-earlier levels. Around this time a year ago, Pacific region storage sat at 72 Bcf, a steep deficit to the 163 Bcf 2018-2022 average, EIA data show.

“In addition to elevated inventory levels in the West…there is also the potential for stronger hydro electric generation this spring versus what was anticipated just a few months ago,” the Mobius analysts said.

The post Permian Natural Gas Forward Prices Plummet; Other Markets Seeing Basis Improvement appeared first on Natural Gas Intelligence

Selling Weighted to Front of Natural Gas Forward Curves on Weak Near-Term Fundamentals 

Thu, 03/14/2024 - 13:39

Against a backdrop of soft near-term fundamentals, exceptionally weak spot market pricing and plummeting Nymex futures, regional natural gas forwards came under widespread bearish pressure during the March 7-13 trading period, NGI’s Forward Look data show.

For a market still threading the needle between near-term oversupply and anticipated future demand growth, selling was weighted toward the front of the curve. Henry Hub April fixed prices shed 20-plus cents week/week for April, May and June 2024 delivery, Forward Look data show.

Front month fixed prices for the benchmark dropped 27.4 cents for the period to $1.663/MMBtu.

[Mexico Matters: Cross-border energy trade between the U.S. and Mexico reached $82 billion last year. Understand this burgeoning trade flow — the projects, politics and natural gas prices — with NGI’s Mexico Gas Price Index. Know more.]

‘Incredibly Weak’ Physical Market

A near total absence of winter heating demand has left storage inventories brimming with excess molecules as the shoulder season nears, and this has driven physical prices to historic lows.

Day-ahead trading at Henry Hub during the March 7-13 period illustrated the bearish pressures of the near-term supply glut even as daily production volumes appear to have pulled back in recent weeks. 

On Wednesday (March 13 trade date), Henry Hub spot prices dropped as low as $1.190. Spot prices at the hub previously bottomed out at $1.200 in October 2020, Daily GPI historical data show. 

This comes as the Henry Hub March bidweek price of $1.610 is the lowest on record going back to at least 2014 when adjusting for inflation, according to an analysis of Bidweek historical data.

The previous Bidweek low at Henry Hub of $1.495, set in July 2020, would adjust to $1.791 based on the February 2024 Consumer Price Index, NGI calculations show.

‘Soaring Surpluses’

After briefly probing above the $2.000 mark, Nymex futures retreated throughout the March 7-13 trading period. The selling showed markets “succumbing to soaring surpluses and incredibly weak Henry Hub physical market pricing,” according to EBW Analytics Group analyst Eli Rubin.

Storage surpluses are set to climb to “staggering” levels, and “working down unmanageable excesses will define the 2024 injection season,” Rubin said.

Still, pricing along the curve illustrates the tension between current bearish dynamics and “growing bullish optimism” as the market looks ahead to later in the injection season, according to the analyst.

“At the front of the strip, the market must contend with bulging storage surpluses, meager shoulder season demand, LNG maintenance and — particularly during early April — a lack of injection behavior from local distribution companies until later in the spring,” Rubin said. However, rising demand this summer could help to “reshape a bullish narrative moving forward.”

Appalachian Basis Narrows

Meanwhile, Appalachian basis differentials continued to narrow during the March 7-13 trading period. The regional price outlook has strengthened notably following a wave of producer announcements signaling curtailments.

Eastern Gas South basis strengthened across the 2024 curve week/week, including a 12.7-cent gain for July 2024, which ended the period at minus-55.7 cents, Forward Look data show.

Differentials also narrowed for the remaining 2024 contracts at hubs like Texas Eastern M-2, 30 Receipt; Transco-Leidy Line; and Tennessee Zn 4 Marcellus.

The most recent regional operator to join the chorus of producers announcing cuts was CNX Resources Corp. The company on Tuesday said it plans to cut around 30 Bcfe from its 2024 production. CNX said it would “delay completions on three upcoming Marcellus Shale pads consisting of 11 wells to avoid bringing incremental volumes into the current oversupplied market.”

An analysis of 11 gas-weighted exploration and production (E&P) companies shows them guiding for a 13% decrease in capital spending in 2024, according to Oil & Gas Financial Analytics LLC director Tom Biracree.

These gas-weighted producers “as a group are guiding to a 1% decrease in gas output at 1.59 billion boe,” Biracree wrote in a blog post for RBN Energy LLC.

Weather Needed

Daily production estimates from Wood Mackenzie as of Thursday showed domestic output at 100.8 Bcf/d, well off the recent 30-day average of 103.0 Bcf/d and roughly flat to year-earlier levels. Recent production estimates from Bloomberg had production dipping below 100 Bcf/d.

Expanding storage surpluses have created a “quite bearish” background state for natural gas markets, though fading production volumes and the prospect of a hot summer represent “bullish undercurrents,” according to NatGasWeather.

Still, without more weather-driven demand, “the recent plunge in production won’t be able to fully cash in,” NatGasWeather said.

Signs of a cooler Lower 48 pattern for the back half of March appeared unlikely to do much to repair the damage done by mild winter weather to date.

“There’s still cooler air expected into the U.S.” from Monday through March 24, and this is “better than it’s been much of the past six weeks,” NatGasWeather said. However, the pattern remained “far from bullish due to only modest bouts of subfreezing air into the northern U.S.” and “quite nice” temperatures “most elsewhere.”

The post Selling Weighted to Front of Natural Gas Forward Curves on Weak Near-Term Fundamentals  appeared first on Natural Gas Intelligence

Appalachian Natural Gas Forward Curve Responds to EQT Cuts

Thu, 03/07/2024 - 13:36

Regional natural gas forwards generally pushed higher at the front of the curve during the Feb. 29-March 6 trading period as ebbing production strengthened the price outlook for a market dealing with excess supply exiting winter, NGI’s Forward Look data show.

Fixed prices for April delivery at benchmark Henry Hub added 4.0 cents for the period to finish at $1.937, and aside from some selling in the Western Lower 48, most locations finished in positive territory week/week at the front of the curve.

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EQT And Appy Basis

The work week kicked off with an announcement from the largest U.S. natural gas producer, EQT Corp., that it is curtailing 1.0 Bcf/d of production through March.

The move by EQT helped explain a notable drop in Northeast volumes in recent production estimates, and it brought incremental bullishness for spring and summer basis in Appalachia, according to Forward Look data.

EQT’s curtailments appear to have started around Feb. 24 and have been focused in the Southwest Pennsylvania portion of the Marcellus Shale, East Daley Analytics analyst Jack Weixel said during a recent discussion on energy chat platform Enelyst.

“EQT employed a similar strategy in 2020, shutting in about 1.4 Bcf/d when Appalachian prices fell below $1.50,” Weixel said. “The producer brought back supply three months later, only to reduce volumes once again in September 2023. EQT restarted full production heading into the winter after prices recovered above $1.50.”

A number of Appalachian hubs, including Eastern Gas South, Millennium East Pool and Texas Eastern M-2, 30 Receipt, saw negative basis differentials narrow for the upcoming injection season during the Feb. 29-March 6 trading period.

For example, Texas Eastern M-2, 30 Receipt June 2024 basis rallied 9.0 cents for the period, ending at minus-55.9 cents, Forward Look data show.

The trend is even more noticeable when going back to pre-EQT-curtailment trading. 

Texas Eastern M-2, 30 Receipt has strengthened by double digits across the 2024 injection season since Feb. 22. October 2024 basis at the hub has rallied 14.6 cents since then, narrowing the discount to Henry to minus-$1.196.

Over the same span, May 2024 basis at the location has shaved off 14.0 cents to close to within 52.4 cents of the national benchmark, according to Forward Look.

Chesapeake’s ‘Novel Strategy’

Of course, EQT is only one among a slew of exploration and production (E&P) companies to recently signal natural gas production cuts in response to weak prices. 

Chesapeake Energy Corp., another major U.S. natural gas producer, set the tone late last month when it announced activity reductions in the Marcellus and Haynesville shales while guiding for substantially lower output in 2024.

Oil and Gas Financial Analytics LLC director Tom Biracree, in a recent blog for RBN Energy LLC, described Chesapeake’s plans as a “novel strategy that will slash production by 25% but leave the E&P ready to quickly ramp up its output as soon as demand and prices warrant.”

Cutting back on investment and output in the face of recent historically weak commodity prices is not necessarily a simple decision for producers, according to Biracree.

“For smaller producers who need to make payroll, scaling back operations may be impractical,” Biracree said. “For larger producers, strategic capital allocation decisions are complicated by the anticipated dramatic gas demand growth in 2025 to 2028,” including from new LNG export capacity hitting the market.

Looking specifically at Chesapeake, the operator appears to be aiming to align supply with demand by prioritizing the buildout of a “substantial inventory” of “wells that have been drilled and completed up to the final step of turning them in line,” according to Biracree.

Along with plans for a modest increase in drilled but uncompleted wells, Chesapeake’s anticipated inventory of 80 wells ready to turn to sales by the fourth quarter should allow the operator to “quickly respond to price signals,” the analyst added.

Pacific Selling

Meanwhile, California hubs conspicuously deviated from the broader, modestly positive, movement of regional forwards trading around the Lower 48 during the Feb. 29-March 6 period.

Fixed prices came down sharply at the front of the curve at SoCal Citygate, with April, May and June each giving back 40-plus cents week/week, Forward Look data show.

SoCal Citygate fell to $2.643 for the period, off 47.7 cents but still at a hefty mark-up to Henry Hub.

Premium pricing at PG&E Citygate also fell week/week, with April fixed prices dropping 17.2 cents to $2.828.

In contrast to the year-earlier period, storage inventories in the Mountain and Pacific regions are exiting the 2023/24 heating season at an ample surplus to historical levels, according to U.S. Energy Information Administration (EIA) data.

A year ago, following price spikes during the 2022/23 winter, Mountain and Pacific region storage exited the season below historical norms, particularly the Pacific, EIA data show.

Fast forward to the week ended Mar. 1, and Mountain region storage sat at 169 Bcf, a 77.9% surplus to the five-year average and 79.8% above year-earlier levels. At 219 Bcf, the Pacific sat at a 43.1% surplus to the five-year and at a whopping 154.7% surplus versus a year ago, according to EIA.

For the week ended March 1, the Mountain and Pacific regions accounted for 74% of the total U.S. year/year inventory surplus “despite those regions containing only 19% of the nation’s storage capacity,” Wood Mackenzie analyst Eric McGuire observed in a recent note.

The post Appalachian Natural Gas Forward Curve Responds to EQT Cuts appeared first on Natural Gas Intelligence

Natural Gas Forward Curves Strengthening for 2024 Amid Signs of Weaker Production

Thu, 02/29/2024 - 13:55

Regional natural gas forward curves offered hints of a market climbing out of the doldrums for the upcoming injection season, even as many hubs held flattish week/week for April delivery, NGI’s Forward Look data show.

Fixed prices at Henry Hub for April delivery added 2.2 cents for the Feb. 22-28 trading period to reach $1.897/MMBtu, according to Forward Look.

Contracts further along the 2024 strip showed a bit more life. The national benchmark rallied 13.0 cents for August to exit at $2.627. June through December 2024 all picked up around a dime or more week/week.

[Mexico Matters: Cross-border energy trade between the U.S. and Mexico reached $82 billion last year. Understand this burgeoning trade flow — the projects, politics and natural gas prices — with NGI’s Mexico Gas Price Index. Know more.]

Lower 48 storage has drifted above the five-year maximum on persistently underperforming heating demand. Nymex futures have flirted with historic lows this winter, sending a strong signal to producers to curtail output.

And there have been signs that producers are listening, including a notable dip in dry gas production based on recent estimates.

Wood Mackenzie samples as of Thursday showed production totaling 101.9 Bcf/d. The recent seven-day average totaled 103.0 Bcf/d, versus a recent 30-day average of 104.6 Bcf/d, according to the firm.

Amid this softening in production figures, a number of Northeast, Appalachian and Mid-Atlantic hubs outgained the national benchmark for various contracts along the 2024 strip and into early 2025, Forward Look data show.

Cove Point August 2024 basis, for example, strengthened by 8.5 cents week/week to flip from a 5.5-cent discount to plus-3.0 cents. Eastern Gas South basis added 8.6 cents for September 2024, finishing $1.091 back of Henry. Tennessee Zn 4 Marcellus basis for October 2024 narrowed to minus-$1.289, a 10.2-cent gain, Forward Look data show.

Production In Spotlight

Nymex futures as of Thursday had similarly shown some strengthening in contracts along the 2024 strip. Forecasts suggested the window of opportunity for late winter weather to have an impact was rapidly closing, leaving the market to focus instead on the upcoming injection season.

The ICE End of Draw Index Future recently closed at 2,200 Bcf, which would comfortably top the 2019-2023 five-year maximum for Lower 48 storage exiting the withdrawal season.

“Although bulging storage surpluses at the front of the curve may weigh on near-term pricing, the market may increasingly take its cues from the production trajectory,” EBW Analytics Group analyst Eli Rubin said. “Producers already announced plans to release rigs and frac crews over the next six weeks — and evidence of lower upstream activity may help support upside.”

Heading into the shoulder season, already huge storage surpluses could further swell on weak power burns and potential LNG maintenance, according to Rubin.

“While power sector demand for natural gas has moved structurally higher in recent years…consumption gains are largest during the summer and winter,” Rubin said. “During the shoulder season, power sector demand gains are relatively muted — particularly if wind generation rebounds toward seasonal levels.”

Longer-Term View On Supply

While recent pricing dynamics reflect a market asking producers to pump the brakes, there remains significant growth on the horizon as new liquefied natural gas export capacity comes online.

Projecting changes in overall Lower 48 supply and demand balances out to 2035, RBN Energy LLC recently modeled an incremental 18.9 Bcf/d of production over this span, which would raise domestic output to 121 Bcf/d on average.

“Although the increase pales in comparison to the 66% jump in gas production from 2011 to 2023, we are still looking at a healthy amount of incremental gas,” RBN analyst John Abeln wrote in a recent blog post. “The growth trajectory is strongest over the next six or seven years, slowing to less than 1% year-on-year after 2030.”

In RBN’s forecast, which assumes an average crude oil price of $70/bbl, more than half of that production growth would come from the oil-focused Permian Basin. The other regions driving natural gas production growth in RBN’s forecast, which also assumes an average natural gas price of $4, are the Haynesville and Eagle Ford shales. 

According to Forward Look prices, the recent average of Henry Hub contracts out to February 2034 was $3.525.

The Permian, Haynesville and Eagle Ford “would account for more than 80% of the total production bump, as the gas supply picture farther from the Gulf doesn’t net nearly as much growth, especially with Appalachian production constrained by a lack of takeaway capacity,” Abeln said.

As for the new demand sources that would soak up this growing supply, LNG exports unsurprisingly remained a key part of the outlook. 

RBN’s projections would see LNG feed gas demand nearly double by 2035, but this excludes further upside from projects not already under construction or with a final investment decision. 

This also assumes power sector gas demand, a subject of wide-ranging uncertainty, “plateaus rather than declines” over the period, according to Abeln. “A decline in power usage,” such as that predicted by the U.S. Energy Information Administration, “would free up an extra 15 Bcf/d that would need to find a home and could flow toward exports.”

The post Natural Gas Forward Curves Strengthening for 2024 Amid Signs of Weaker Production appeared first on Natural Gas Intelligence

Sparked by Chesapeake Cuts, Natural Gas Forwards Rally Across 2024 Strip 

Thu, 02/22/2024 - 13:32

A wave of bullish optimism, tied to the production cuts announced recently by Chesapeake Energy Corp., also lifted regional natural gas forwards higher during the Feb. 15-21 trading period, NGI’s Forward Look data show.

For numerous Lower 48 trading locations, the most pronounced week/week fixed price gains occurred further along the strip during the 2024 injection season. 

Chesapeake in its 4Q2024 earnings results signaled its intent to curtail activity in both the Haynesville and Marcellus shales in 2024. The latest Forward Look price trends imply a shift in the market’s thinking around balances through the remainder of the year tied to the producer’s announcement.

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Benchmark Henry Hub saw the largest fixed price gains for June through October of this year. July 2024 at the hub rallied 25.8 cents week/week to exit at $2.427/MMBtu.

Numerous other hubs followed Henry’s example by posting healthy increases across the middle months of the 2024 strip.

A few New England hubs, meanwhile, felt the pain of mild winter weather. Discounts for March delivery in the region came as forecasts made it increasingly difficult to envision impressive late-winter cold materializing to justify higher premiums.

Algonquin Citygate March basis plunged 34.3 cents for the period, ending at a 65.4-cent premium to Henry Hub.

Maxar’s Weather Desk as of Thursday was calling for exceptionally warm conditions to sprawl across key demand markets over the middle and eastern sections of the Lower 48 into early March.

The forecaster’s latest 11- to 15-day outlook, covering March 3-7, trended even warmer from the Interior West to the Midwest.

Warmer than normal temperatures expected over the eastern two-thirds of the Lower 48 for this timeframe would include “much aboves favoring the Midwest and East throughout the period,” Maxar said. “Temperatures also lean on the warmer side of normal in the South but less anomalously so in a stormy pattern.”

Market’s Production Response

How the market will resolve what could be a sizable storage overhang exiting winter remains a key question heading into the 2024 injection season. Considering the reaction to Chesapeake’s planned cuts, which saw the March Nymex contract rally 19.7 cents Wednesday, the market appeared eager to see producers pull back.

“In our view, notwithstanding 5.5 Bcf/d of price-induced coal-to-gas switching in the power sector, the natural gas market will ultimately require help from lower production to help balance oversupply,” EBW Analytics Group analyst Eli Rubin said in a recent note. 

A slowdown in upstream activity as indicated by the current round of earnings results “may take months to materialize,” according to Rubin. 

In the meantime, producers “may quietly narrow supply during the low-demand shoulder season,” and pipeline maintenance could also serve to curb volumes, the analyst said.

A delayed in-service date for the Mountain Valley Pipeline (MVP) is “helpful from a macro perspective but far from curative,” according to Rubin.

Appalachian Basis Weakens

Appalachian basis differentials widened somewhat during the Feb. 15-21 period, which brought news of another delay for the 2 million Dth/d MVP, now slated for completion by the end of June.

Eastern Gas South basis shed around 5-10 cents week/week across the 2024 strip and into early 2025. For April 2024, the hub finished at minus-53.2 cents, down 6.8 cents.

Still, basis differentials at points downstream in the Mid-Atlantic also came under downward pressure for the period. Transco Zone 5 April basis fell 8.5 cents to plus-13.6 cents, Forward Look data show.

As MVP inches closer to the finish line, it is perhaps worth revisiting the potential market impact as the long-delayed Appalachian takeaway pipeline finally enters service.

Analyst Sheetal Nasta in a blog post for RBN Energy LLC late last year outlined how congestion on Transco (aka the Transcontinental Gas Pipe Line) could impact the initial uplift to regional takeaway capacity afforded by MVP’s in-service.

According to Nasta, the “big questions” surrounding the pipeline’s startup are “when it will be able to flow its full 2 Bcf/d capacity and how much it will end up increasing overall Northeast takeaway capacity.”

The MVP mainline terminates at Transco’s Station 165 in Pittsylvania County, VA, the analyst noted.

“From there, MVP deliveries into Transco will depend on takeaway capacity from Station 165 in order to access premium-priced markets within Transco’s Zones 4 and 5,” Nasta said. “…Transco is the only major long-haul system supplying gas to the Atlantic corridor, and it is more or less fully contracted with firm commitments.”

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Widespread Discounts for Natural Gas Forwards as Mild Weather Crushes Prices

Thu, 02/15/2024 - 14:07

Slammed by a lack of winter weather set against a robust supply backdrop, regional natural gas forwards fell sharply across the Lower 48 during the Feb. 8-14 trading period, NGI’s Forward Look data show.

Henry Hub fixed prices for March delivery took a 35.6-cent nosedive week/week to exit the period at $1.620/MMBtu. The benchmark saw double-digit losses across the 2024 strip over the past week, showing bearish sentiment spilling past the winter months that have been hampered by underperforming weather-driven demand.

New England premiums were hit particularly hard, not just for March 2024 but also for Winter 2024/25.

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Algonquin Citygate January 2025 basis plunged $1.905 week/week to end at plus-$6.747, Forward Look data show.

The updated 11- to 15-day outlook on Thursday from Maxar’s Weather Desk showed unseasonably mild temperatures blanketing the eastern two-thirds of the Lower 48 to close out February.

“In consideration to the primary biases of the winter thus far, the risk is that this period is warmer in the Midwest, perhaps including strong aboves,” Maxar said.

As for the latest six- to 10-day projections, the forecaster noted warmer trends for the Plains, Midwest and Northeast.

“Aboves and much aboves are widespread from the Interior West to Midwest early, peaking strongly above normal on day seven with highs reaching the mid-60s in St. Louis and approaching 80 degrees in Dallas and Houston,” Maxar said. 

Meanwhile, a few Appalachian hubs saw basis differentials narrow modestly versus a heavily discounted Henry Hub during the Feb. 8-14 period.

Eastern Gas South March picked up 8.1 cents to finish 40.7 cents back of Henry, with similar gains for most contracts out to early 2025. Still, October 2024 fixed prices at the hub ended the period at just $1.134.

Producers Responding?

With the market paying close attention, recent earnings reports offered some clues as to how natural gas-focused producers intend to navigate what’s shaping up to be a challenging commodity price environment in 2024.

Haynesville Shale operator Comstock Resources Inc. revealed plans to cut back from seven to five drilling rigs.

“Being a pure-play natural gas company in a sub-$2 natural gas market calls for decisive actions to weather the volatility, and at the same time continue positioning Comstock to benefit from the longer-term growth in natural gas demand in the foreseeable future,” CEO Jay Allison told analysts Wednesday during a fourth quarter earnings call. “America will need to deliver an additional 10 Bcf/d to the LNG facilities currently under construction in the next few years.”

Meanwhile, management at Appalachian producer EQT Corp. pushed back on oversupply concerns, while also alluding to the opportunities presented by potentially higher pricing in 2025.

EQT CEO Toby Rice identified “two factors that we think about that would cause us to curtail. One is preserving the ability to not lose money…and the other one is we are looking in 2025, where you see $1 higher pricing, and that’s going to be further incentive for us to pinch back and deliver those molecules into a higher priced market.”

EQT CFO Jeremy Knop added that the company’s capital expenditures budget in 2024 will “have no real impact on our production this year. It really has an impact on production next year. We are just not under the same pressure that most of our peers are. So that allows us to be a little stickier and plan for the long term and not be as reactive.”

Recent Forward Look data continued to show significantly stronger pricing at Appalachian hubs like Eastern Gas South for 2025 versus the remaining 2024 contracts.

Eastern Gas South fixed prices exited the Feb. 8-14 trading period at $2.312 for July 2025, versus just $1.422 for July 2024.

Still, early 2025 contracts at Appalachian hubs have come under notable downward pressure year-to-date, similar to declines observed at Henry Hub, Forward Look data show.

Further To Fall?

Absent a production response, prices could have further room to fall in the months ahead, according to EBW Analytics Group analyst Eli Rubin.

“In the unlikely event producers fail to trim production in response to lower prices,” prices for the 2024 injection season could see “another 10% of downside even from currently depressed levels,” Rubin said in a recent note.

Faced with regional price weakness, “unhedged producers may increasingly reduce the pace of completions,” according to Rubin. “Any notable announcements from producers about withholding production due to low prices could balance an oversupplied market, help the Nymex curve reach bottom and potentially trigger a notable relief rally” over the next 30 to 45 days.

Mobius Risk Group analysts recently highlighted declines for 2025 prices that they said could indicate increased producer hedging activity.

Producers may be attempting to “bring higher-valued portions of the curve forward to soften the blow of very low near-term prices,” the Mobius analysts said.

The post Widespread Discounts for Natural Gas Forwards as Mild Weather Crushes Prices appeared first on Natural Gas Intelligence

Natural Gas Forwards Remain Under Pressure as February Warmth Erases Demand

Thu, 02/08/2024 - 13:51

Exceptional warmth near-term and an enduring supply buffer kept the pressure on regional natural gas forward prices during the Feb. 1-7 trading period, according to NGI’s Forward Look.

March fixed prices at benchmark Henry Hub dropped 13.6 cents to end at $1.976/MMBtu, setting the pace for coast-to-coast discounts at the front of the curve. 

With only a handful of exceptions, Lower 48 hubs shed value across the 2024 strip, illustrating the prevailing bearish sentiment as weather-driven demand has largely missed the mark this heating season.

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Recent forecasts suggested a reprieve from exceptionally bearish weather could arrive mid-month. However, whether the pattern shift would serve up enough demand to rescue flagging prices remained an open question.

“The pattern will transition away from the anomalously warm conditions of the near term, but with the Midwest retaining above and much above normal coverage into the early half of the six- to 10-day period,” Maxar’s Weather Desk said in an updated forecast Thursday. “Otherwise, expectations are for a cooling pattern, with the emergence of below normal temperatures at times in the South and late along the East Coast.”

The updated 11- to 15-day outlook showed warmer trends for the Midwest but continued to advertise below normal conditions across the South and the East Coast, according to the forecaster.

However, Maxar noted that “the split flow typical of the strong El Niño continues to limit the intensity of cold in this forecast.”

Northeast Basis Strengthens

Even as prices generally drifted lower overall, Mid-Atlantic and Northeast locations saw incremental basis strengthening along the curve, including for 2025, Forward Look data for the Feb. 1-7 trading period show.

Cove Point basis, for example, surged 26.8 cents higher for January 2025, ending at plus-$2.058, with the hub also posting basis gains across the 2025 strip.

Tenn Zone 6 200L added 17.8 cents for January 2025 to reach plus-$8.858.

Farther upstream in Appalachia, basis ticked higher for 2024 contracts and for the 2025 injection season.

Millennium East Pool finished at an 88.3-cent discount to Henry Hub for July 2025, a 10.0-cent gain week/week. Eastern Gas South also picked up 10.0 cents for July 2025 to end at a 94.5-cent discount to the Henry.

In the nearer term, Eastern Gas South March 2024 basis narrowed by 6.6 cents to minus-48.8 cents, according to Forward Look.

Analysts at ClearView Energy Partners LLC recently said their modeling points to a narrowing differential between Eastern Gas South and Henry Hub year/year in 2024.

“We anticipate Appalachian gas pipeline takeaway capacity rising around 2.8 Bcf/d this year, well ahead of dry gas production growth in the region year/year,” the ClearView analysts said.

ClearView’s modeling suggests a “relatively strong correlation” between spare takeaway capacity out of Appalachia and Eastern Gas South basis differentials.

The startup of the 2 million Dth/d Mountain Valley Pipeline (MVP) accounts for most of the anticipated increase in Appalachian takeaway capacity in 2024, according to the firm.

Still, apparent constraints downstream of the project, as noted recently by the International Energy Agency (IEA), could affect capacity usage rates, the ClearView analysts said.

The IEA in its Gas Market Report for 1Q2024 said it sees the downstream constraints “weakening the debottlenecking effect on Appalachian production.”

Meanwhile, the Permian Basin and the Haynesville Shale should continue to lead production growth in the United States, according to IEA.

“However, the delay in bringing online the first train of the Golden Pass liquefaction project from 2024 to 2025 is set to soften production growth in southern basins close to the coast,” the agency said. “Overall, U.S. dry gas production growth is set to slow to below 2% in 2024.”

Will Producers Respond To Sub-$2?

With the front of the curve recently dipping below $2, the market is pressuring producers to pull back, Tudor, Pickering, Holt & Co. (TPH) analyst Jake Roberts said in a note.

“While we’ve yet to hear any desire to curtail volumes from coverage, that dynamic may become topical through earnings at current spot prices,” Roberts said. “In our view, producers should likely be looking at activity reductions across all of 2024 given the current strip outlook.”

TPH had been leaning toward “completion deferrals as the first salvo from the industry,” but given the extent of recent downward pressure on prices, “it could be we need to see more structural cuts from rig programs in 2024 to better balance the market as a setup to a constructive 2025,” Roberts said.

After an unseasonably light 75 Bcf withdrawal for the week ended Feb. 2, Lower 48 storage stood at 2,584 Bcf, with the surplus to the five-year average ballooning from 130 Bcf back up to 248 Bcf.

EBW Analytics Group analyst Eli Rubin said in a recent note the firm was modeling an October 2024 peak of 4,100 Bcf in storage.

“Although this continues to suggest bearish fundamental pressure ahead, the roughly 200 Bcf of projected oversupply is approaching the range where a severe late-winter cold spell” or producers cutting back on 2024 production guidance “could help draw the market into balance,” Rubin said.

Recent sub-$2 pricing is “forcing producers to at least reconsider the 2024 production cadence,” though “a late-winter cold stretch could prompt a modest short-covering rally at the front of the curve,” according to Rubin.

The post Natural Gas Forwards Remain Under Pressure as February Warmth Erases Demand appeared first on Natural Gas Intelligence

Natural Gas Forwards Weighed Down by Supply as Bulls Look for Colder Pattern Shift

Thu, 02/01/2024 - 14:01

Regional natural gas forward prices came under bearish pressure across the curve during the Jan. 25-31 trading period as recovering production volumes and blowtorch winter temperatures foreshadowed excess supply heading into the upcoming injection season.

Henry Hub fixed prices shed 16.0 cents for March delivery, ending the period at $2.112/MMBtu, NGI’s Forward Look data show. In turn, numerous Lower 48 hubs posted March fixed price discounts of around 15-20 cents week/week.

Mixed Near-Month Moves

Price action for the period was a bit more mixed for February delivery. 

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February fixed prices at a handful of East Coast demand hubs saw heftier discounts amid recent balmy temperatures regionally.

Cove Point tumbled to $4.460 for February, down 46.4 cents for the period. Tenn Zone 6 200L shed 60.4 cents to exit at $7.445 for February.

Meanwhile, a number of western Lower 48 hubs strengthened for February delivery during the Jan. 25-31 time frame, even as contracts further along the curve sold off, Forward Look data show.

Opal February fixed prices advanced to $5.080, up 46.1 cents for the period, though March tumbled 38.2 cents to $2.358.

SoCal Citygate picked up 30.6 cents for February to end at $5.334, though March through September came under heavy downward pressure at the Southern California hub.

Prices there surged a week earlier amid indications of maintenance-related pipeline constraints impacting the Southern California Gas (SoCalGas) system for the upcoming injection season. Even after selling off over the past week, recent SoCal Citygate prices remained stronger along the curve versus levels observed around mid-January, Forward Look data show.

A weeklong maintenance event beginning last Friday (Jan. 26) was limiting SoCalGas receipts at the El Paso-Ehrenberg location by around 170,000 MMBtu/d versus the 30-day average, according to Wood Mackenzie analyst Kevin Ong.

“As a result of this maintenance, gas has been rerouted through other receipt points on the system,” Ong said. “The Kern River/Mojave-Wheeler Ridge receipt point with Kern River Gas Transmission experienced the largest day/day increase, with nominations increasing by 185,000 MMBtu when the maintenance began.

“Receipts also increased at Kern River-Kramer Junction and Transwestern-Needles by 41,000 MMBtu and 40,000 MMBtu, respectively.”

Blowtorch February

Despite some impressive weekly storage withdrawals associated with a mid-January Arctic blast, forecasts have advertised exceptional warmth through the first half of February. 

This comes as recent estimates showed Lower 48 production fully recovering from weather-related disruptions. Adding to the bearish pressure on prices, an extended outage at one of the trains at the Freeport LNG terminal in Texas figures to hamper export demand until it is resolved.

In other words, the year-on-five-year-average storage surplus, slashed to 130 Bcf as of Jan. 26, appears poised to quickly grow once again.

“At just over the $2 mark, the Nymex curve is trading as if we are going to run out of places to put the gas before winter is over,” analysts at Mobius Risk Group said in a recent note. 

While prices could rally off such low levels at this point in the season, weather would have to cooperate, according to the firm.

Anomalously warm temperatures in the outlook have slashed weather-driven demand expectations, “and risks of a plus-2 Tcf end-of-March inventory level will increase with each passing day until there is a pattern shift,” the Mobius analysts said.

Pattern Shift Coming?

There have been glimmers of such a cooler pattern shift developing into the back half of February.

Recent weather model runs Thursday continued to show “near the warmest pattern of the past 50 years” through Feb. 13, according to NatGasWeather.

However, the data also “continued to hold prospects of a better/colder U.S. pattern Feb. 14-17 as a warm ridge sets up over western North America, providing a path for colder air over central Canada to flow into the Midwest and East,” the firm said.

EBW Analytics Group analyst Eli Rubin said the firm sees a fundamentally oversupplied market heading into the injection season. 

Still, colder temperatures developing later this month or into early March “could help avert — or at least minimize or postpone — the most dire bearish price risks,” Rubin said.

It’s also possible that speculators will be reluctant to short natural gas with prices hovering near $2 at this point in the season, when a potential cold shot could “send prices flying higher at any point,” the analyst added.

The market could wait for clearer visibility into the end of winter heating, when it can shift focus to the spring shoulder season, before a bottom develops, according to Rubin.

“Our most likely October 2024 storage target calls for 4,300 Bcf,” based on recent Nymex pricing. This suggests “a 350-400 Bcf overhang for the market to clear over the next nine months,” Rubin said. The Nymex spring contracts could “slide below $2 over the next 30-45 days in an attempt to shake out production growth and bring an oversupplied market outlook into balance.”

The post Natural Gas Forwards Weighed Down by Supply as Bulls Look for Colder Pattern Shift appeared first on Natural Gas Intelligence

Natural Gas Forwards Retreat on Warm Early February, Though Basis Strengthens Out West

Thu, 01/25/2024 - 13:57

Facing bearish weather headwinds into early February, regional natural gas forward prices generally drifted lower during the Jan. 18-24 trading period, NGI’s Forward Look data show.

Amid a return to the unseasonably mild temperatures that dominated forecast maps prior to a mid-January Arctic cold blast, fixed prices at numerous hubs impacted by the deep freeze saw notable declines. Losses were especially pronounced at the front of the curve in many instances.

In the Midwest, Chicago Citygate fixed prices tumbled 60.6 cents for February to end the Jan. 18-24 period at $3.159/MMBtu. Over in the Midcontinent, Northern Border Ventura plunged $1.056 to finish at $4.009 for February.

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In New England, Tenn Zone 6 200L February fixed prices dropped $1.034 for the period to $8.049. 

Near-month losses at a number of locations outpaced the declines at benchmark Henry Hub, which shed 22.8 cents for February to fall to $2.663.

Several Northeast demand hubs, including Tenn Zone 6, Algonquin Citygate and Transco Zone 6 NY, also saw notable weakening in basis differentials for winter 2024/25 contracts, Forward Look data show.

The mid-January deep freeze across much of the Lower 48 made a sizable dent in the Lower 48 storage buffer, but impacts from the extreme cold were set to be “completely offset by one of the warmest patterns of the past 50 years,” NatGasWeather said in an updated discussion of the 15-day temperature outlook Thursday.

The most recent weather data maintained “an exceptionally warm/red/bearish setup” through Feb. 8, “especially so over the northern and eastern U.S.,” NatGasWeather said. Temperatures were expected to climb to 15-30 degrees above normal, “and with very little coverage of subfreezing highs, a rarity for late January into February.”

Forecasts advertised colder weather systems impacting western portions of the country early next month, but these were likely to “struggle advancing into the important eastern half of the U.S. as a stubborn warm ridge holds strong,” according to the firm.

Western Basis Mark-Up

Despite the broader downward pressure on Lower 48 natural gas prices, basis strengthening was the prevailing theme in the Western Lower 48 for the Jan. 18-24 period, led by hefty mark-ups across the strip at the perennially constrained SoCal Citygate.

Basis differentials at the Southern California hub jumped by around $1 or more for each month throughout the upcoming injection season.

Week/week gains were largest for August, with basis surging to plus-$4.940, a $1.908 swing higher.

An updated system maintenance outlook for February posted to the Southern California Gas (SoCalGas) electronic bulletin board listed a number of planned maintenance events that could restrict capacity on the operator’s system in the coming months.

This included a hydrotest on Line 4000 that would reduce capacity on the SoCalGas Northern Zone by 555 MMcf/d between April 1 and Oct. 30, according to the document.

The Southern California market has been no stranger to infrastructure constraints driving up premiums. The bid under 2024 basis differentials during the Jan. 18-24 period suggested traders were bracing for history to repeat itself once again.

Basis differentials also strengthened at a number of other western Lower 48 hubs during the period, particularly for peak summer 2024 contracts and for winter 2024/25.

Opal basis rallied 48.8 cents for August to end at an 83.3-cent premium to Henry Hub. August basis at Northwest Sumas surged 46.2 cents to plus-83.2 cents.

Too Early To Write Off Winter

After plummeting on the blowtorch-warm late January and early February temperature outlook, Nymex futures showed signs of finding a bottom earlier in the week, bouncing off of lows in the $2.300 vicinity. 

Prices pulled back on Thursday following a 320 Bcf withdrawal from the latest U.S. Energy Information Administration (EIA) storage report. The print, accounting for the widespread impacts of the recent Arctic blast, ranked as one of only three withdrawals 300 Bcf or greater in magnitude on record going back to 2010. 

Still, the withdrawal figure failed to offer any surprises when compared to the market’s lofty pre-report expectations.

The soon-to-expire February Nymex contract fell 7.0 cents Thursday to settle at $2.571. March settled at $2.180, off 8.2 cents.

Recent forecasts suggested a “resolutely bearish” weather outlook, but it’s still too soon to write off winter, according to EBW Analytics Group analyst Eli Rubin.

The month of February has delivered disruptive winter weather events in recent years, and next month could serve up “another massive February cold event” that could reshape the supply/demand outlook, the analyst said.

“While underlying fundamentals appear oversupplied — the market is likely to carry both a hefty storage surplus and record production into the 2024 injection season — winter weather can quickly pare down anticipated storage risks,” Rubin said. “Just as calling the end of winter in mid-December would have missed the early January Nymex charge higher, suggesting the end of winter in mid-to-late January may similarly prove premature.”

The post Natural Gas Forwards Retreat on Warm Early February, Though Basis Strengthens Out West appeared first on Natural Gas Intelligence

Old Man Winter’s Disappointing Encore Sees Natural Gas Forward Prices Retreat

Thu, 01/18/2024 - 13:46

Natural gas forwards pulled back during the Jan. 11-17 trading period as impacts to both supply and demand from recent Arctic weather began to subside and as a much milder late January pattern came into sharper focus.

After surging in the week-earlier period, fixed prices from coast-to-coast fell back down, NGI’s Forward Look data show.

Despite production freeze-offs and robust heating demand amid the most impressive spell of winter weather for the Lower 48 season-to-date, forecasts teased a downright balmy late January period that ultimately deflated prices.

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Absent a frigid enough encore to the recent bout of winter, Henry Hub February prices sank 16.4 cents week/week, falling back below the $3/MMBtu mark to $2.891.

Late January Warmth

Forecast maps from Maxar’s Weather Desk as of Thursday painted the Lower 48 with the red, orange and yellow hues of unseasonably warm temperatures starting early next week and lasting into the start of February.

“The near term chill quickly gives way to a warmer pattern in the six- to 10-day period, as Pacific flow is enhanced downstream over the Gulf of Alaska amid a lack of Arctic blocking,” the forecaster said. “Above normal temperatures are widespread in coverage as a result, including much and strong aboves for most of the period in the Midwest and during the second half in the East. At the mid-period peaks, lows are in the 30s and highs in the 40s in Chicago, while New York City has lows in the low 40s and highs in the low 50s.”

The 11- to 15-day period was expected to carry over the widespread above normal temperatures seen for days six through 10, according to Maxar.

The warmest conditions were expected early in the period, “with much and strong aboves from the Midwest to the East Coast,” the forecaster said. “Temperatures moderate in these areas during the second half, particularly along the East Coast where readings return to normal as a trough settles into eastern Canada.”

Regional hubs that had rallied a week earlier ahead of the encroaching Arctic cold posted steeper discounts compared to the national benchmark.

In the Midwest, Chicago Citygate basis for February fell to plus-89.5 cents, down 26.0 cents week/week. In the Midcontinent, Northern Natural Demarc tumbled 53.9 cents to end at plus-$1.250 for February.

Mid-Atlantic and Northeast prices also came down sharply during the period to narrow regional premiums to Henry Hub.

Algonquin Citygate February basis finished at plus-$6.019, a 96.7-cent swing lower. Cove Point February basis dropped to plus-$3.773, a discount of 63.5 cents for the period, Forward Look data show.

Still, Forward Look data as of Thursday showed notable month-to-date fixed price gains across the strip for much of the Lower 48, suggesting the colder start to 2024 has produced a bullish shift in market sentiment following the mild finish to 2023.

Chicago Citygate February fixed prices, for example, were trading at $2.720 in early January and had rallied more than 38% month-to-date as of Thursday, even after accounting for the discounts of the past week, Forward Look data show.

Further, a number of hubs have popped for winter 2024/25 contracts thus far in the new year, including Algonquin Citygate, where January 2025 fixed prices were up 84.8 cents (7%) month-to-date. Cove Point January 2025 prices were up 66.1 cents versus levels at the start of the month, a 12% increase, according to Forward Look data.

Weather-Driven Gains Short-Lived

Much like snow after the thaw sets in, the impact on Nymex futures from the recent January cold had largely evaporated by Thursday; the February Nymex contract was trading in line with pre-winter storm levels, settling at $2.697, down 17.3 cents on the day.

Ultimately, even with recent freeze-offs, the Arctic cold seemingly failed to rewrite the fundamental narrative dominating natural gas earlier this winter, a story centered around oversupply concerns following a fall production surge.

A triple-digit withdrawal in the latest U.S. Energy Information Administration (EIA) storage report Thursday showed cold making a dent in the year-on-five-year inventory buffer during the week ended Jan. 12. Even so, stockpiles remained at a 320 Bcf surplus to the five-year average.

At 3,182 Bcf, Lower 48 inventories exited the week above the five-year maximum of 3,089 Bcf, EIA data show.

The subsequent EIA report “is expected to bring heavy withdrawals given the cold temperatures felt this week,” Gelber & Associates analysts said Thursday. Recent forecasts “show that the remaining winter is unlikely to see temperatures any colder than those brought by this most recent cold shot.”

Daily production remained well off the recent 30-day average at 97.9 Bcf/d as of Thursday in Wood Mackenzie’s dataset, suggesting ongoing weather-related disruptions.

EBW Analytics Group estimated that freeze-offs impacted as much as 12 Bcf/d during the Arctic blast. 

The duration of weather-related production declines remained a key factor to monitor for natural gas markets moving forward, EBW analyst Eli Rubin said in a recent note.

“Perhaps the most pressing near-term question for the natural gas outlook is the pace of the supply recovery…Supply had already begun to dip 2.0 Bcf/d ahead of the brunt of cold, while the strong early-winter supply surge had already appeared poised to reverse lower into mid-winter,” Rubin said. “Our current assessment has production exiting March 0.75 Bcf/d below December levels. If supply fails to fully recover from winter freeze-offs, the fundamental outlook may appear less bearish than our current most-likely market assessment.”

Arctic cold could return in February, and production impacts could endure, developments that would “help rebalance the market” moving forward, according to the analyst.

Still, “long-term fundamentals remain considerably oversupplied to bias natural gas market risks distinctly lower,” Rubin said.

The post Old Man Winter’s Disappointing Encore Sees Natural Gas Forward Prices Retreat appeared first on Natural Gas Intelligence

Old Man Winter Finally Wakes Up as Natural Gas Forward Prices Surge

Thu, 01/11/2024 - 13:39

With a mid-January arctic blast lining up to drive strong heating demand and disrupt production volumes, regional natural gas forwards raced higher during the Jan. 4-10 trading period, NGI’s Forward Look data show.

Markets across the country braced for freezing and even subzero temperatures, with frigid temperatures and severe weather already developing ahead of the extended Martin Luther King Jr. Day weekend. 

In sharp contrast to mild conditions season-to-date, forecasts called for icy low temperatures to grip the Lower 48 into the week ahead, with Old Man Winter apparently keen to make up for lost time.

Pronounced fixed price front month gains sprawled across the North American market, with price strength weighted toward the eastern two-thirds of the Lower 48. Henry Hub rallied 37.3 cents for February delivery to end the period at $3.055/MMBtu, Forward Look data show.

[Market Dynamics: Listen in as NGI digs into the myriad pieces that make up the winter supply/demand puzzle and how they may impact prices through the heating season and beyond. Tune into the Hub & Flow podcast now.]

‘Brutal’ Cold Inbound

An “extremely active” weather pattern across the Lower 48 to close out the week included potential blizzard conditions from eastern Nebraska to central Michigan, the National Weather Service (NWS) said Thursday.

Areas in the Deep South and Southeast were expected to experience severe weather to close out the week, including “damaging wind gusts,” according to the NWS.

“A much colder arctic air mass will continue settling south and east in the wake of this storm across the Plains, Midwest and into the Ohio Valley,” the forecaster warned. “Temperatures will be brutal compared to the relatively mild conditions that have been experienced for much of the winter season up to this point in time.

“Afternoon high temperatures will likely fail to reach zero degrees across much of Montana and into North Dakota” to close out the work week, with the Central Plains, Iowa and Minnesota expected to see highs only reach the single digits or teens, the NWS added. “This arctic air mass will be lengthy in duration and persist well beyond the end of the week.”

Demand hubs across multiple regions posted outsized gains to drive up basis differentials during the Jan. 4-10 period, including in the often-congested Northeast, where Tenn Zone 6 200L finished at plus-$7.193 for February, up 69.0 cents. 

Elsewhere, Texas Eastern M-3, Delivery February basis jumped to plus-$2.364, up 80.3 cents. In the Mid-Atlantic, Transco Zone 5 surged $1.232 to end at a $4.606 premium to Henry.

Hubs in the Lower 48’s middle third, set to experience some of the most intensely frigid conditions forecast with the arriving wintry weather, also posted large basis gains for the period.

Northern Natural Ventura jumped to plus-$2.484 for February, up $1.122. Chicago Citygate basis rallied 70.9 cents to reach plus-$1.155 for February. NGPL Midcontinent basis exited the period at a 55.0-cent markup for February, a 43.6-cent swing higher, Forward Look data show.

With the extreme cold poised to sweep across much of the Lower 48 in the days ahead, natural gas markets were “on edge” as of Thursday, Wood Mackenzie analyst Kara Ozgen said.

Ozgen cited a slew of notices and alerts from pipeline operators bracing for the cold, including operational flow orders.

Based on forecasts, “it’s undoubtedly expected to be an impactful cold shot that will affect the whole U.S. at one point or another,” the analyst said. 

Futures to Revert Lower?

Even with the full impacts of this month’s winter blast yet to transpire, a sharp sell-off Wednesday for Nymex futures suggested traders were already looking ahead to a potential late-January warm-up.

The February contract rallied to as high as $3.231 Thursday after the magnitude of the latest storage withdrawal reported by the U.S. Energy Information Administration (EIA) surprised to the high side. However, the front month failed to sustain those gains, pulling back to eventually settle at $3.097, up 5.8 cents day/day.

Looking at weather-driven gains for Nymex futures earlier in the week, “the backdrop of strongly bullish technicals and unraveling of a sizable speculator short position amplified the move higher,” EBW Analytics Group analyst Eli Rubin said in a recent note. “Although substantial volatility is likely short term, gains appear overextended on a longer timeframe.”

Rubin observed that “even Winter Storm Uri” in February 2021 “ultimately failed to sustain storm-induced price increases. Despite half of the winter still to go, a robust supply picture suggests a reversion lower in Nymex futures over the next 90 days.”

How inventories are impacted by winter weather over the next few weeks could determine if prices end up “retesting supply-curtailing $2.00 levels” or soar above $3, according to analysts at Mobius Risk Group.

Prior to Thursday’s EIA report, the firm looked at degree days and storage withdrawals season-to-date and estimated an implied 2.5 Bcf/d undersupply year/year.

Looking ahead, Mobius estimated 130 more heating degree days (HDD) over the next two weeks versus year-earlier levels, which would contrast with a tally of 200 fewer population-weighted HDD winter-to-date.

“In a brief two-week period, we are poised to erase approximately two-thirds of the bearish year/year weather anomaly,” the Mobius analysts said.

The post Old Man Winter Finally Wakes Up as Natural Gas Forward Prices Surge appeared first on Natural Gas Intelligence

Natural Gas Forwards Rally as New Year Promising Long-Awaited Cold

Thu, 01/04/2024 - 13:08

A new year brought a new outlook to regional natural gas forwards markets during the Dec. 28-Jan. 3 period, NGI’s Forward Look data show.

Coming off a balmy December, forecasts during the period teased the arrival of markedly more winter-like conditions through this month, and traders responded by locking in double digit near month fixed price gains across the Lower 48.

February fixed prices at benchmark Henry Hub jumped 22.4 cents for the period to reach $2.682/MMBtu.

[Market Dynamics: Listen in as NGI digs into the myriad pieces that make up the winter supply/demand puzzle and how they may impact prices through the heating season and beyond. Tune into the Hub & Flow podcast now.]

Has Winter Finally Arrived?

Forward gains were especially pronounced in the western Lower 48, where traders have shown sensitivity to upside risks in the wake of price spikes during the 2022/23 winter. 

Basis premiums at hubs including Northwest Sumas, Malin, Opal, PG&E Citygate and SoCal Citygate all swelled notably for February and March during the Dec. 28-Jan. 3 period.

Northwest Sumas February basis more than doubled week/week, surging from plus-$1.399 to plus-$2.922, Forward Look data show.

Still, winter basis premiums across the West, as with many other Lower 48 hubs, remained sharply lower winter-to-date. For reference, Northwest Sumas February basis was trading at plus-$4.908 at the start of November, Forward Look historical data show.

Recent forecast maps suggested the western half of the Lower 48 could see widespread coverage of colder-leaning temperatures heading into mid-January. 

Maxar’s Weather Desk, in its updated six- to 10-day forecast on Thursday, for Tuesday through Jan. 13, showed warmer-leaning temperatures blanketing the East for the period.

“Alternatively, below to much below normal temperatures are steady in the West and expand in coverage to the Plains and Midwest at the end of the period,” Maxar said.

Farther out in the 11- to 15-day period, covering Jan. 14-18, Maxar observed a cooler-trending outlook for the eastern half of the country.

“While the models have lacked consistency in the position of a ridge near Alaska, it is still a colder signal directing much to strongly below normal temperatures from Western Canada toward the Midwest, with the coldest of the forecast for the Midwest being from early to mid-period,” the forecaster said. “Below normal temperatures expand to the East Coast during the second half, when slight aboves return to the Southwest.”

Gains at a number of Midwest and Midcontinent hubs also outpaced the increase at Henry. Chicago Citygate February basis rallied to plus-44.6 cents, a 17.5-cent gain for the period. Northern Natural Ventura surged 37.7 cents to plus-$1.362 for February.

On the other hand, the colder January outlook still did not tease the kind of impressive chills needed to sustain basis mark-ups in the Northeast. Transco Zone 6 NY February basis sold off 33.6 cents to end at plus-$2.408.

NatGasWeather on Thursday cautioned that models could continue to see large changes in either direction from one run to the next, particularly in the outlook for mid-January.

The Jan. 14-20 time frame could prove pivotal “as frosty air holds over Southwest Canada, providing opportunity to release into the western and central U.S.,” NatGasWeather said. However, colder temperatures could “continue struggling to advance far enough into the East to fully intimidate.”

A Brighter Outlook for Bulls?

Nymex futures rallied for the Dec. 28-Jan. 3 period as markets responded to the prospect of more robust January weather-driven demand. Traders shrugged off a bearish miss from the latest U.S. Energy Information Administration storage report Thursday to send the February contract surging to a $2.821 settle, up 15.3 cents day/day.

The near-term outlook for natural gas prices has been “brightening” on a combination of “colder mid-January risks, ebbing production” and the prospect of shrinking storage surpluses, according to EBW Analytics Group analyst Eli Rubin.

Comparing storage withdrawals against gas-weighted heating degree days, the supply/demand balance in December was “already modestly tight on a weather-normalized basis amid elevated coal-to-gas switching,” Rubin said. “If cold weather further erodes surpluses, higher prices are likely.

“Still, we caution that the long-term outlook is substantially oversupplied, with both sizable outstanding inventory surpluses and associated gas supply growth later in the storage cycle — weighing heavily on Nymex pricing,” Rubin added.

Supply and demand estimates from Wood Mackenzie Thursday had production dropping to 104.6 Bcf/d, lagging both the prior seven-day average (105.3 Bcf/d) and the 30-day average (106.1 Bcf/d).

Feed gas demand for liquefied natural gas climbed to 14.7 Bcf/d in the firm’s daily estimate, versus a recent seven-day average of 14.4 Bcf/d.

Looking at the power sector, low natural gas prices could contribute to continued weakness in coal-fired generation, which underperformed in 2023, according to Wood Mackenzie analyst Colette Breshears.

“After a couple of years of depleted stockpiles and supply line constraints, North American coal generation units find themselves over-contracted and oversupplied with coal, with some deferring additional deliveries until space is available,” Breshears said. “Despite this current oversupply, high gas storage levels and continued high gas production are expected to keep gas-fired generation very competitive to outperforming.”

Coal-fired generation in 2023 came in “at levels well below average, suggesting that coal-to-gas and coal-to-renewables switching was already persistent,” the analyst added.

The post Natural Gas Forwards Rally as New Year Promising Long-Awaited Cold appeared first on Natural Gas Intelligence

Northeast, West Coast Premiums Continue to Fade as Other Natural Gas Forward Hubs Advance

Thu, 12/28/2023 - 14:19

For much of the Lower 48, regional natural gas prices gained during the Dec. 21-27 trading period amid hopes for a chillier new year, though winter basis premiums continued to fade, NGI’s Forward Look data show.

January fixed prices at Henry Hub rallied 17.7 cents to exit the period at $2.629/MMBtu. February finished at $2.458, up 9.9 cents.

Continuing themes from the week-earlier period, winter basis premiums came down sharply for hubs in the West and the Northeast, even as fixed prices advanced for much of the rest of the Lower 48.

Northeast Premiums Fade

January basis at Transco Zone 6 NY fell 32.5 cents to end at plus-$2.159. Farther upstream, Texas Eastern M-3, Delivery tumbled 32.0 cents for January, ending at plus-$1.394.

Updated forecasting from Maxar’s Weather Desk Thursday showed warmer-leaning temperatures blanketing the Lower 48’s northeastern quadrant well into the new year.

The latest 11- to 15-day outlook shifted slightly warmer day/day for the eastern half of the country, with colder adjustments for the western half, the forecaster said. For the six- to 10-day period, Maxar called for “unsettled” conditions over the southern Lower 48.

“The storm track favors the Southern Tier, with the first low pressure tracking along the Gulf Coast from early to mid-period and the second from California on days seven to eight to the Gulf Coast late,” Maxar said. “Temperatures are coolest in the wake of these lows, falling slightly below normal.

“Alternatively, the period is forecast to be drier than normal across the Northern Half, and this region is forecast with above normal temperatures.”

Mid-Atlantic Hubs Climb

While Northeast demand hubs shed value for the period, it was a different story nearby in the Mid-Atlantic. The cooler-leaning temperatures farther south, alongside signs of pipeline congestion, saw basis premiums climb at Transco Zone 5 and Cove Point for January.

Transco (aka Transcontinental Gas Pipe Line) put an operational flow order (OFO) into effect for Zones 4, 5 and 6 during the Dec. 21-27 trading period because of “limited flexibility to manage imbalances” on its system. A subsequent OFO was scheduled to go into effect Friday and last until further notice.

One factor potentially impacting pricing dynamics along the East Coast this winter has been the partial startup of Transco’s Regional Energy Access expansion, which has helped to narrow the spread between Transco-Leidy Line and Transco Zone 6 non-NY.

Recent winter forward price trends reflect this dynamic, with Transco Zone 6 non-NY premiums under heavy downward pressure for January and February during the Dec. 21-27 period. By contrast, Transco-Leidy Line basis held steady week/week at a roughly 40-50 cent discount to Henry Hub.

West Coast Cushion

Over on the West Coast, Malin January basis sank to plus-$1.063, down 41.2 cents week/week. Farther south, SoCal Citygate dropped 42.5 cents to finish at plus-$1.570 for January.

Spot prices in the sometimes volatile Southern California market have been subdued for the current winter, especially when compared to price spikes observed in December 2022.

SoCal Citygate day-ahead trades largely failed to crack the $3 mark during the Dec. 21-27 period, Daily GPI historical data show. 

At this time a year ago, the hub saw spot trades soar above $50. However, this winter, the region has clearly thus far not experienced the same confluence of factors that drove sustained price spikes and depleted regional storage inventories a year ago. 

According to the U.S. Energy Information Administration (EIA), Pacific region storage stood at 280 Bcf as of Dec. 22, an 18.6% cushion versus the five-year average. In the year-earlier period, Pacific stocks totaled just 168 Bcf, according to the agency.

Futures Foothold

Nymex futures continued to gain a foothold following a second straight bullish-leaning result in the latest EIA Lower 48 storage statistics. 

The February Nymex contract rallied 12.0 cents to settle at $2.557 Thursday. That mirrored a 12.5-cent front-month rally a week earlier after EIA’s print for the period ended Dec. 15 also landed on the bullish side of expectations.

The reported 87 Bcf withdrawal from domestic inventories for the week ended Dec. 22 implied 1.9 Bcf/d of tightness versus the prior five-year average when compared to degree days and normal seasonality, according to Wood Mackenzie analyst Eric McGuire.

“For the second week in a row, EIA reported a withdrawal of 87 Bcf,” McGuire said. “While temps were slightly milder week/week, the corresponding loss of heating demand was completely offset by higher power burns, slightly higher LNG exports and a small week/week decline in production.”

The post Northeast, West Coast Premiums Continue to Fade as Other Natural Gas Forward Hubs Advance appeared first on Natural Gas Intelligence

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