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Updated: 1 week 4 days ago

Natural Gas Forwards Extend Slide as Warm January Pushes Storage Above Historical Levels

Thu, 01/19/2023 - 13:30

With mild weather continuing unabated across large swaths of the United States during the Jan. 12-17 period, natural gas forward prices tumbled, according to NGI’s Forward Look.

The largest price declines were seen on the West Coast, where a much needed break from the torrential downpours was set to occur. AccuWeather said the pause in major rain and mountain snow events should last through the end of January.

While storms may continue to roll across the northern Pacific in the coming weeks, a zone of high pressure is forecast to build at most levels of the atmosphere along the U.S. West Coast. This setup could force the storms to swing to the north and away from tropical moisture before plunging southward over the interior Southwest, rather than along the California coast.

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The changing weather pattern would allow the ground to dry out and streams to recede gradually, according to AccuWeather. However, the runoff would continue to fill area lakes and reservoirs over the next couple of weeks.

This should be a boon to hydroelectric power generation, which has struggled over the past couple of years because of the drought. With less natural gas likely needed for power generation, forward prices cratered.

PG&E Citygate February prices plunged $7.940 through the period to reach $17.817, Forward Look data showed. The summer strip (April-October) averaged $1.010 lower at $5.450, while the winter 2023-2024 strip (November-March) averaged $1.300 lower at $7.111.

In Southern California, February prices at the SoCal Border Avg. dropped $7.670 from Jan. 12-17 to reach $18.017, while the summer strip dropped 96.0 cents to $4.320. Winter prices were down $1.140 to $6.755.

While weather has moderated in the West, supply constraints may hold the key to returning prices in the region to a trading range that better aligns with the rest of the country.

Kinder Morgan Inc. said repairs on Line 2000 of the El Paso Natural Gas Pipeline system should be completed by the end of January. However, the Pipeline and Hazardous Materials Safety Administration would need to approve the restart, which could take time. The pipeline has been shut since August 2021 following a deadly explosion near Coolidge, AZ.

There are maintenance events underway on other pipelines in the region, which also have restricted gas flows out of the Permian Basin.

That said, hefty price drops extended into the Desert Southwest and Rockies as well. Opal February prices fell $7.940 through the period to reach $15.761, according to Forward Look. Opal summer prices were down 35.0 cents to $3.060, while prices for the next winter were down $1.070 to $5.883.

By comparison, benchmark Henry Hub prices for February fell 38.0 cents to $3.331, Forward Look data showed. Notably, this is on par with the summer strip. Further out the curve, winter 2023-2024 prices dropped 16.0 cents to $4.246.

Is Winter Really Over Already?

Though it’s still too early to call off winter, the blowtorch warmth experienced thus far in January, along with the mild start to the season, has been a bearish influence over the market. After deficits of more than 300 Bcf late last summer, the market had grown jittery about supply this winter. Freeport LNG initially was expected to return to service before the end of the year, and the strong pull on natural gas was seen potentially leading to a shortfall if demand proved higher than normal. Futures prices shot up accordingly, reaching $10 in the late summer.

Since then, however, a string of above-average storage injections in the fall along with mostly modest draws this winter – and a rare January injection to boot – have squashed any supply fears. What’s more, there’s ongoing uncertainty that Freeport would begin shipping liquefied natural gas by the end of January, a timeline it continues to target.

On Thursday, the Energy Information Administration (EIA) delivered more bearish data. The EIA reported an 82 Bcf withdrawal for the week ending Jan. 13, which landed on the deeper end of a wide range of estimates ahead of the report but still rather “wimpy” overall, according to NatGasWeather.

Estimates submitted to Reuters ranged from declines of 53 Bcf to 81 Bcf, with a median of 73 Bcf. Bloomberg’s poll found analysts looking for a median pull of 75 Bcf. Withdrawal estimates spanned from 61 Bcf to 85 Bcf. A Wall Street Journal survey landed at an average draw of 72 Bcf.

Historically speaking, the draw was far short of last year’s 203 Bcf withdrawal for the similar period and the 156 Bcf five-year average. As such, the 2,820 Bcf of total working gas in storage stood only 19 Bcf below year-earlier levels and 34 Bcf above the five-year average, according to EIA.

Broken down by region, the East and Midwest each reported a 38 Bcf draw, while the Mountain region pulled out 6 Bcf. Pacific stocks slipped by 3 Bcf.

The South Central region, meanwhile, reported back-to-back net injections. This time, the 2 Bcf net addition included a 12 Bcf increase in salt storage and a 10 Bcf draw from nonsalts, EIA said.

With uncertainty over how cold or how far reaching an end-of-month cold front may be, futures traders took the storage news as confirmation of continued loose supply/demand balances. They expect yet another modest historically light draw in the next EIA report as well.

Early estimates pointed to a draw in the 60-80 Bcf range, which would compare with the year-earlier pull of 217 Bcf and the five-year average of 185 Bcf. As such, analysts appeared to be bumping up their estimates for the end of October. Some reached above 4.0 Tcf.

“The market seems to be pricing that in,” said Enelyst’s Het Shah, managing director of the online energy chat.

Meanwhile, there should be some colder weather moving into the Lower 48 in the final week of January. However, various weather models are not aligned on how cold it may be. The midday Global Forecast System (GFS) was a little colder trending Jan. 25-26 but decently warmer for Jan. 27-29, according to NatGasWeather. The GFS was still colder than the European Centre (EC) for Jan. 26-Feb. 2 by numerous heating degree days, but the gap had closed slightly.

The latest longer-range European forecast released Thursday afternoon also failed to inspire bulls for the first two weeks of February, NatGasWeather said. Instead, it favored a relatively warm ridge over the southern and eastern United States. The 15-day EC run that ended before the longer-range EC also was rather warm over the East for early February. 

“If this were to prove true and the Feb. 3-16 period failed to trend back colder over the eastern half of the U.S., this period would be a bearish lean,” NatGasWeather said.

EBW Analytics Group LLC said a key issue in the coming cold pattern is that the bulk of anomalous cold is focused on the central United States. The eastern third of the Lower 48 is expected to increase gas consumption only slightly.

That said, the February contract remains technically oversold, according to EBW. The fundamental turn colder, coinciding with a technically oversold market, is often a recipe for a short-term bounce, increasing the risks of a near-term push higher for February.

“The litmus test for the market, however, will be if the outlook continues to turn colder and drive the risk of widespread production freeze-offs,” EBW energy analyst Eli Rubin said. “At present, it appears that modest freeze-offs may be contained to the Bakken and Rockies, but any further cold expansion…could send risks, and natural gas prices, notably higher.”

The February Nymex gas futures contract settled Thursday at $3.275, off 3.5 cents from Wednesday’s close. March futures climbed 1.3 cents to $3.124.

The post Natural Gas Forwards Extend Slide as Warm January Pushes Storage Above Historical Levels appeared first on Natural Gas Intelligence

West Coast Natural Gas Forwards Rebound Amid Seemingly Endless Deluge; Northeast Slips Further

Thu, 01/12/2023 - 14:21

A divergence in natural gas prices occurred along the forward curve from Jan. 5 through 12, with a relentless stretch of winter weather leading to a recovery in West Coast prices, while springlike conditions on the East Coast sent prices lower there. 

February fixed prices ultimately averaged 65.0 cents higher through the period, while the summer strip (April-October) picked up 6.0 cents and the winter 2023-2024 held steady, NGI’s Forward Look data showed.

A week after finally backing off recent highs, West Coast markets bounced back as the brutal winter conditions that started in December were set to continue for the foreseeable future. The National Weather Service (NWS) said the region continued to be stuck in a storm pattern, with two low pressure systems seen impacting the coast through the weekend.

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Both systems would be accompanied by ample moisture and produce widespread precipitation. The most impactful precipitation is to remain focused along the coasts of Northern California and the Pacific Northwest through late Friday. Precipitation then would expand south on Saturday and east on Sunday.

“Northern California has been hammered with heavy precipitation events over the past couple weeks, and any additional rainfall could pose a threat of flash flooding,” NWS forecasters said.

This weekend, snow was expected in the higher elevations of the West, and heavy mountain snow was possible in parts of the Sierra Nevada and Cascades. Heavy mountain snow also could be possible for the higher peaks of the central and southern Rockies.

Though temperatures are not all that extreme for winter – with highs in the 50s and 60s – the volatile weather pattern this winter has fueled volatility across the West. Aging infrastructure, regular pipeline maintenance that has restricted gas flows, a years-long drought and other issues have all come to a head and led to unprecedented price spikes in the region.

After slipping last week, prices recovered during the Jan. 5-12 period.

Malin February fixed prices climbed $5.010 to reach $18.725/MMBtu, while the summer strip picked up a far more modest 15.0 cents to average $3.620, Forward Look data showed.

The 15-cent climb for the summer months appears to take into account the heavy rains that should lead to a much-improved hydroelectric supply outlook and thus, the potential for storage inventories in the region to be replenished.

Lake Oroville, for example, has a capacity of about 3.5 million acre-feet. Before the series of atmospheric rivers, it was storing less than 1 million acre-feet of water. Since the beginning of December and the arrival of the storms, water levels have risen to more than 1.7 million acre-feet, according to the California Department of Water Resources. Three more forecast storms are expected to raise levels more by 400,000-500,000 acre-feet. 

Low water levels at Lake Oroville in 2021 forced the Edward Hyatt Power Plant to shut down for the first time since it opened in 1967.

Malin winter strip prices commanded a steeper 55.0-cent climb to $6.740, while the Calendar 2024 strip moved up 25.0 cents to $4.720, according to Forward Look.

In Northern California, PG&E Citygate February rose $5.050 through the period to $20.416, and the summer climbed 21.0 cents to $6.250. Winter prices averaged 65.0 cents higher at $8.023, and the Calendar 2024 strip averaged 27.0 cents higher at $6.130.

The hefty premiums for the upcoming winter are a direct reflection of the chaos that has ensued across the West Coast this season. The continued drag on natural gas when spare pipeline space is hard to come by has stoked huge price swings on a daily basis.

On the supply side, it also has resulted in a massive drawdown of storage inventories that never quite recovered from a 51 Bcf reclassification to cushion gas by Pacific Gas & Electric Corp. in the summer of 2021.

On Thursday, the Energy Information Administration (EIA) said Pacific region inventories slipped by 5 Bcf to 160 Bcf. While this is a modest improvement to historical levels, the market has a long way to go before reaching the 206 Bcf year-earlier level and the 235 Bcf five-year average.

Northeast Continues To Slide

The East region also made some noise in the latest EIA storage report. Against a backdrop of mild weather, it added 9 Bcf to stocks. At 700 Bcf, inventories as of Jan. 6 were less than 5% below year-ago levels and only 2 Bcf below the five-year average, according to EIA.

The increase in storage – a rare January occurrence and in the East no less – was largely expected by the market, but was significant nonetheless, according to Enelyst’s Het Shah, managing director of the online energy chat.

“At this point, is winter over?” he asked. “We have sufficient gas to get us through.”

With mostly moderate temperatures expected in the region for the next 12 days or so, inventories are likely to remain elevated as withdrawals should fall short of historicals for this time of year.

The modest winter demand in January and improvement in storage likely drove losses across the Northeast forward curves over the Jan. 5-12 period, particularly in New England.

Algonquin Citygates February fixed prices fell $1.510 during this time to reach $16.012, while the summer strip slipped only 2.0 cents to $3.380, according to Forward Look. Prices for the upcoming winter were down $1.910 to $14.385, while the Calendar 2024 strip averaged 56.0 cents at $8.140.

Smaller losses were seen along the Transcontinental Gas Pipe Line Co. system, though there was a huge disconnect between NY and non-NY prices for February. The prompt month at Transco Zone 6 non-NY slid 5.0 cents to $10.139, while Transco Zone 6 NY fell 2.0 cents to $2.960, Forward Look data showed.

Elsewhere across the Lower 48, February fixed prices ranged mostly from $3.00-6.00 amid the continued span of mild weather. NatGasWeather said Thursday the much warmer-than-normal pattern would continue the next 11 days, keeping heating degree days on a national level well below normal. A minor bump in demand was forecast Friday-Sunday as a weather system tracks into the Southeast, but the overall mild pattern would remain intact.

The ongoing warmth should continue to bode well for storage. In addition to the East, inventories have improved dramatically in the South Central region as well. Stocks there rose a net 27 Bcf for the week ending Jan. 6, which resulted in a nearly 5% surplus to the five-year average.

Total working gas in storage stood at 2,902 Bcf, which is 140 Bcf below year-earlier levels and 40 Bcf below the five-year average.

Notably, Thursday’s longer-range European model showed colder temperatures finally returning in the last full week of January, particularly across the northern United States. Even more, the data shows the cold air sticking around through at least Feb. 15.

“We must give bulls the benefit of the doubt they could have something cooking as long as the weather data doesn’t trend notably warmer for Jan. 24-31, making each new weather model run important ahead of the weekend break,” NatGasWeather said.

The prospects for heightened demand because of the cold was enough to boost Nymex futures on Thursday, albeit only slightly. The February contract settled at $3.695, up 2.4 cents from Wednesday’s close.

The post West Coast Natural Gas Forwards Rebound Amid Seemingly Endless Deluge; Northeast Slips Further appeared first on Natural Gas Intelligence

West Coast Leads Losses for Natural Gas Forwards Prices as Warm January Takes Center Stage

Thu, 01/05/2023 - 12:59

Natural gas forward prices continued to plummet during the trading period from Dec. 29-Jan. 4, this time taking West Coast markets along for the ride lower, NGI’s Forward Look showed.

After bucking the down trend that began the final week of 2022, West Coast markets led the price declines across the Lower 48 even as a bomb cyclone pummeled the region.

February fixed prices tumbled an average of $1.070 across the country, while March dropped 46.0 cents on average, according to Forward Look. Smaller losses were seen for the summer (April-October) and winter 2023-2024 (November-March) strips.

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West Coast markets saw prices fall much further, however. 

SoCal Citygate February basis plunged $2.020 through the period to finish at a $15.145 premium over benchmark Henry Hub, Forward Look data showed. With a more moderate outlook for March, basis for next month stood $4.835 above Henry Hub.

Further out the forward curve, fixed prices for the summer at the SoCal Citygate averaged $6.460 as of Wednesday, while the winter 2023-2024 strip averaged $8.392.

In Northern California, PG&E Citygate February basis was down 71.0 cents through the period to finish at plus $12.810, Forward Look data showed. March basis moved 20.0 cents higher, though, ending at plus $3.941. Summer prices fell 15.0 cents to average $6.290, while the winter strip slipped 7.0 cents to $7.404.

The general softening along the forward curve occurred despite a continuation of brutal winter weather that has lent a hand in the unprecedented price volatility that’s played out throughout the West this winter.

AccuWeather said a bomb cyclone would unleash an increasing risk for life-threatening flooding, damaging winds and power outages through Thursday. The system is then forecast to weaken, but not before dumping excessive amounts of rain throughout California, in particular.

An atmospheric river, or massive plume of moisture that originated from the tropical Pacific Ocean about 2,500 miles away at midweek, is forecast to continue to fuel the heavy precipitation, according to AccuWeather. Such a weather setup could lead to excessive rainfall and flooding, as well as snow where the atmosphere is cold enough. In this particular case, the event can be classified as a Pineapple Express, since the plume of moisture originated from near Hawaii, AccuWeather said.

“This will be a dangerous and high-impact storm for California, capable of producing life-threatening conditions and significant disruption which may last several days,” said AccuWeather chief meteorologist Jon Porter. “Not only will this storm be intense tapping into a substantial atmospheric river, but it is also arriving just days after the previous storm brought heavy rainfall and created significant flooding, increasing the impacts and risks that can occur.”

Notably, despite the ongoing wet weather pattern in place on the West Coast, prices in both the cash and forward markets have softened from recent highs. Even as some production remained offline because of freeze-offs in the Rockies, prices throughout the region followed the general trend.

Northwest Sumas February fixed prices fell $2.310 through the period to reach $15.666, and March dropped 45.0 cents to $5.654, according to Forward Look. The summer strip was down 21.0 cents to average $3.440, while the upcoming winter picked up a modest 4.0 cents to average $7.660.

Gas supplies also may be leveling off after deteriorating sharply in recent weeks.

On Thursday, the Energy Information Administration (EIA) reported that gas supplies in the Pacific region went unchanged for the week ending Dec. 30. This left stocks at 165 Bcf, which is still about 25% below year-earlier levels and around 33% below the five-year average.

In discussing the EIA’s weekly inventory report, Enelyst’s Het Shah, managing director of the online energy chat, said the holidays may have impacted demand in an otherwise frigid cold period.

The EIA reported a net 221 Bcf withdrawal for the period, lighter than the median of most major polls.

Prior to the report, projections submitted to Reuters ranged from withdrawals of 153 Bcf to 269 Bcf, with a median pull of 237 Bcf. A Bloomberg survey landed at a median pull of 240 Bcf. The Wall Street Journal’s poll found draw estimates from 156 Bcf to 265 Bcf and an average of a 228 Bcf pull. NGI modeled a 237 Bcf decrease. 

EIA recorded a pull of 46 Bcf during the same week a year earlier and a five-year average of 98 Bcf.

The 221 Bcf draw “just doesn’t add up,” Shah said. It’s “definitely an extremely loose number.”

Broken down by region, the South Central led with a decrease of 96 Bcf, which included a 53 Bcf decline in salt facilities and a 43 Bcf draw from nonsalts, according to EIA. The Midwest and East followed with pulls of 60 Bcf and 56 Bcf, respectively. Mountain region inventories fell by 9 Bcf.

Total working gas in storage fell to 2,891 Bcf, which is 308 Bcf below year-earlier levels and 208 Bcf below the five-year average, EIA said.

What’s Next For Storage?

With mild weather set to remain in place throughout most of January based on the latest weather models, analysts are rightfully looking ahead to the next EIA report. Since Thursday’s government data proved to be exceptionally bearish, Enelyst participants said they were going back to the drawing board on next week’s estimate. Early estimates to The Desk, provided before the latest EIA report, showed a range of withdrawals from 32-52 Bcf. On Thursday, most analysts were estimating much lighter withdrawals between 10 Bcf and 20 Bcf. One analyst was looking for a 5 Bcf injection.

For the comparable week last year, EIA posted a decrease of 179 Bcf. The five-year average is 151 Bcf.

After exceptional cold during the last week of the year, and amidst the even more exceptional warmth of the current storage week, Mobius Risk Group said the market is considering the odds of climbing to an end-of-March inventory level considerably above the 1.7 Tcf mark.

“If such a level is reached, the summer 2022 storage injection of approximately 2.2 Tcf becomes very important both from an absolute standpoint, and even more when weighing the potential for a larger injection during the summer 2023 injection season,” Mobius analyst Zane Curry said.

“Simple math shows that 1.7 plus 2.2 equals 3.9 Tcf, or 100 Bcf less than a level which historically creates material downside risk and steep contango,” Curry explained. “The potential for tracking toward a 4 Tcf end-of-October, or greater, is the rationale market bears are pinning their expectations to.”

For Mobius, weather is key for the balance of winter. If the current heatwave continues for another couple of weeks, the odds of testing 4 Tcf will significantly increase, according to the firm. Conversely, a shift back to a colder-than-normal balance of winter will put a wrench in market bears’ expectations, as this could push season ending inventory back below 1.5 Tcf.

“Since even the weather forecasters have a difficult time predicting the unpredictable, it will be an interesting ride for the balance of January,” Curry said.

The February Nymex gas futures contract settled Thursday at $3.720, off 45.2 cents from Wednesday’s close.

The post West Coast Leads Losses for Natural Gas Forwards Prices as Warm January Takes Center Stage appeared first on Natural Gas Intelligence

Outside of Elevated West, Natural Gas Forwards Moderate on ‘Balmy’ January Temps

Thu, 12/29/2022 - 13:35

With constrained markets along the West Coast the notable exception, natural gas forwards tumbled during the Dec. 22-28 trading period as winter upside price risks faded on forecasts showing a mild start to 2023.

Fixed prices for February delivery at Henry Hub shed 55.3 cents to end the period at $4.698/MMBtu, and numerous hubs throughout the eastern two-thirds of the Lower 48 posted week/week losses of around 50 cents or more, NGI Forward Look data show.

In the Midwest, February fixed prices at Chicago Citygate gave up 73.0 cents to end at $5.525, while in the Northeast, Transco Zone 6 NY fell 55.3 cents to $12.678.

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Meanwhile, elevated prices have been the pervading theme for western markets this winter, and that continued during the Dec. 22-28 trading period.

February fixed prices in Southern California surged above the $20 mark, with SoCal Citygate picking up $4.853 to end at $21.853. PG&E Citygate jumped $2.683 to $17.678.

Demand on the SoCal and PG&E systems recently “plummeted” versus conditions observed on Dec. 22, Wood Mackenzie analyst Quinn Schulz said in a note to clients Wednesday.

However, physical prices remained sharply elevated “as depleted inventories begin to seek some recovery,” Schulz said. “Total inventory for SoCal sank to past five-year minimum levels on Dec. 16, and adjusted PG&E inventory reached its own past five-year minimum on Dec. 20.”

SoCal inventories stood at 61 Bcf as of Dec. 28, or 11 Bcf below the five-year average, with PG&E stockpiles at around 79 Bcf on Dec. 27, about 42 Bcf below the five-year, according to the analyst.

Combined Pacific region storage stood at 165 Bcf as of Dec. 23, a 35.8% deficit to the five-year average, according to the Energy Information Administration.

Winter Risks Fading

Undercutting the bullish impact of a wave of intimidating Arctic chills that swept through the Lower 48 over the Christmas holiday, a decisively bearish temperature outlook heading into early January put downward pressure on Nymex futures during the Dec. 22-28 period.

The January Nymex contract rolled off the board at $4.709 Wednesday after a 57.3 cent swoon. In its first day as the prompt month, February gave up another 12.6 cents to settle at $4.559.

February ended the day well shy of a key resistance level identified by ICAP Technical Analysis as necessary for bulls to stem the tide.

“Would need to see the bulls promptly send natural gas surging back above $5.031 to have any shot at avoiding further downside,” ICAP analyst Brian LaRose said in a recent note to clients. “And if the bulls are unable to stage an intervention? Peg $4.342, $4.220-4.093 and $3.924-3.800-3.746 as the steps lower from here.”

Weather data as of midday Thursday continued to advertise a “much warmer than normal U.S. pattern” through Jan. 9, according to NatGasWeather.

“In fact, this period is one of the warmest starts to January on record,” with heating degree days set to drop to well below normal levels nationally, the firm said. “The latest midday data again held warmer trends for Jan. 10-13 as cold air over Canada fails to advance as aggressively into the U.S. As such, the Jan. 10-13 period remains to the bearish side instead of closer to seasonal/neutral.”

While it remained a possibility that the weather data had “trended too warm” for the 15-day projection period, NatGasWeather said it would require “considerable colder trends” to bring an end to “bearish weather headwinds.”

The evaporation of value for the January contract heading into expiration “resets the table” for Nymex futures, and signs point to further declines from here, according to EBW Analytics Group analyst Eli Rubin.

“Further out on the forward curve, the April 2023 contract finally slipped from backwardation into contango versus May as winter risks ebbed,” Rubin said in a note to clients Thursday. “Notwithstanding the precipitous declines, however, the March contract retains a 21 cent premium to April — a premium that is likely to narrow or vanish completely in the next two months.

“With the April contract slumping to under $4.00 for the first time since March — and continued downward pressure likely amid an ample storage outlook and a balmy start to January — it would not be surprising to see March fall another 50-75 cents over the next 30-45 days.”

The post Outside of Elevated West, Natural Gas Forwards Moderate on ‘Balmy’ January Temps appeared first on Natural Gas Intelligence

Spiking Western Natural Gas Forward Prices Countered by Discounts Farther East 

Thu, 12/22/2022 - 12:46

Winter volatility saw Western natural gas forward hubs post huge gains during the Dec. 15-21 trading period, while expectations for a very mild start to 2023 drove deep discounts elsewhere in the Lower 48, NGI’s Forward Look data show.

With intense Arctic cold diving from the Northwest into the heart of the Lower 48, spot market prices surged Wednesday, with gains particularly pronounced in the Rockies and California regions, Daily GPI data show. Day-ahead prices skyrocketed $25-plus day/day at most western U.S. hubs.

Western markets have been no stranger to price spikes this season; the West Coast bore the brunt of wintry weather during an otherwise mild start to December for the Lower 48, one of a number of factors that have contributed to elevated physical market prices out West this month.

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What’s more, Pacific region storage inventories remain markedly below historical norms for this time of year, according to Energy Information Administration data.

The Pacific withdrew 17 Bcf for the week ended Dec. 16, leaving regional inventories more than 30% off the five-year average for this time of year.

Regional forwards trading during the Dec. 15-21 period reflected the heightened volatility for the West. Northwest Sumas fixed price January trading surged $11.252 week/week to end at $27.839/MMBtu. PG&E Citygate jumped $13.652 to $28.089.

Echoes of Uri?

Meanwhile, natural gas traders at other hubs were looking beyond a Christmas cold blast to a far more temperate start to 2023.

January fixed prices at Henry Hub tumbled $1.093 to end the period at $5.347, and numerous other hubs across the eastern two-thirds of the country posted similar declines.

In the Midwest, Chicago Citygate fixed prices for January shed $1.135 to end the period at $6.539.

Elevated New England and Mid-Atlantic hubs posted steeper losses, with Cove Point giving back $4.123 to end at $13.485. Algonquin Citygate shed $6.266 to $27.175. 

Price action indicated market confidence that it had already priced in the upside risks posed by an intense stretch of Arctic cold poised to send much of the Lower 48 into a deep freeze for the holidays.

“Santa is delivering an early harsh freeze to the United States this week, with cold expected to peak nationwide on Dec. 24,” Wood Mackenzie analyst Colette Breshears told clients in a note Thursday.

The anticipated wintry conditions had prompted more than 65 pipelines across North America to issue various notices, watches and advisories, Breshears said.

In echoes of February 2021’s Winter Storm Uri, the holiday weather will see intense cold extend far south into the Lower 48, including into Texas, raising concerns about a potential repeat of the problems the earlier storm exposed with the state’s electric grid.

The Electric Reliability Council of Texas (ERCOT) was projecting adequate generating capacity to meet demand, including some cushion in the event that “winterization procedures at some plants fail to prevent operating problems,” Breshears said. On the other hand, “it is still entirely possible we could see some degree of load shedding. However, the lack of snow/ice in this storm and the relatively quick deep freeze duration continue to be critical factors when making comparisons to Uri.”

Winter Risks Fading

Nymex futures dove sharply lower during the Dec. 15-21 trading period as forecasts advertised a turn toward milder Lower 48 conditions post-Christmas and into the new year. The January contract extended those losses on Thursday, with the front month giving up 33.3 cents to settle a hair under the $5 mark at $4.999.

The latest six- to 10-day outlook from Maxar’s Weather Desk Thursday showed a pattern change taking place, with below-normal conditions over the eastern half of the Lower 48 giving way to “broadly warmer than normal themes.”

The pattern points to a “deepening trough over the northern and eastern Pacific, which acts to redirect the flow into North America from a warmer Pacific source region,” the forecaster said. “Above and much above normal temperatures are early in the West, expanding to Central at mid-period and encompassing all in the Eastern Half late.”

Maxar’s updated 11- to 15-day projections extended warmer trends for the eastern Lower 48.

“Temperatures are forecast to be much above normal here for most of the period and may approach strong above normal levels at times,” according to the forecaster.

The warming temperature outlook as the calendar flips to 2023 “severely impedes” risks of the kind of bullish outcome needed to sustain higher Nymex pricing, according to EBW Analytics Group.

“Nymex winter risk premiums have been disproportionately elevated by the risk of prices screaming higher well above $10 in a bullish scenario with price-inelastic supply and demand fundamentals,” EBW analyst Eli Rubin said in a recent note. The recent drop in weather-driven demand expectations “lacerates already-small odds of a sufficiently bullish event in the 100 days remaining of the traditional withdrawal season.”

The post Spiking Western Natural Gas Forward Prices Countered by Discounts Farther East  appeared first on Natural Gas Intelligence

Natural Gas Forward Prices Rise in the East, Fall in the West as Market Braces for Cold

Thu, 12/15/2022 - 13:11

Natural gas forward gains were widespread during the Dec. 8-14 period as forecasts showed Arctic chills sweeping through the eastern two-thirds of the Lower 48 heading into the back half of December. Meanwhile, already-elevated western hubs saw prices moderate, according to NGI’s Forward Look.

As the market locked onto the coming cold blast and a looming spike in heating demand, Henry Hub fixed price forwards rallied 70.7 cents during the Dec. 8-14 period to finish at $6.440/MMBtu. That set the tone for fixed price gains for most Lower 48 hubs during the week.

The notable exceptions were out West, where fixed prices remained elevated but declined sharply week/week. Malin January fixed prices tumbled $5.622 to $13.287 during the period.

Nymex futures, meanwhile, generally strengthened during the period, buoyed by the prospect of a turn toward much chillier temperatures following underwhelming weather-driven demand to open December. The January Nymex contract rallied 54.0 cents Thursday to settle at $6.970.

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Western Basis Moderates

In terms of regional basis shifts, the biggest swings occurred in the western Lower 48 during the Dec. 8-14 period, Forward Look data showed. In California, PG&E Citygate January basis shed $5.999 to end at plus-$8.007. SoCal Citygate front month basis dropped $5.037 to end at a $10.259 premium to Henry Hub.

Elevated physical pricing in California this month reflects “a poorly-timed spike in demand, alongside upstream supply worries as we head into the thick of the winter season,” Wood Mackenzie analyst Quinn Schulz told clients in a recent note.

Recent draws have left inventories on both the PG&E and Southern California Gas systems lagging the prior five-year average, the analyst said.

“Recent upstream constraints also help to further tighten the region,” Schulz said. “The first and most long-term constraint is a barrage of maintenance events” on the North Mainline of the El Paso Natural Gas (EPNG) system. “These events have collectively cut westbound flows by 277 MMcf/d since Nov. 28 and will last until the end of December.

“…Given these circumstances, unanswered questions about the return-to-service date for EPNG’s Line 2000 are further dampening confidence in California’s winter supply.”

The Energy Information Administration (EIA) Pacific region withdrew 14 Bcf from storage for the week ending Dec. 9, leaving stockpiles in the region at 203 Bcf. That’s a 26.4% deficit to the five-year average of 276 Bcf, EIA data show.

Meanwhile, basis strengthening was widespread along the East Coast during the Dec. 8-14 period as traders assessed the impacts of what’s shaping up to be a frigid stretch for the eastern Lower 48 heading into the Christmas holiday.

The latest six- to 10-day forecast (next Tuesday through Dec. 24) from Maxar’s Weather Desk Thursday showed an “Arctic air mass settling” into the central Lower 48 “during the early half before expanding further south and eastward from mid to late period. Temperatures are strongly below normal in association.”

The 11- to 15-day period (Dec. 25-29) was expected to carry over “widespread much and strong belows in the Eastern Half. Belows wane over the course of the period as aboves expand in the West,” according to the forecaster.

Transco Zone 5 January basis surged $2.730 higher week/week, ending at a $11.121 premium to Henry Hub. Cove Point jumped $2.730 to plus-$11.178. 

Farther north in New England, hubs maintained or added to already hefty January premiums. Tenn Zone 6 200L finished at plus-$27.018, a 79.3-cent gain week/week, Forward Look data showed.

‘Rather Intimidating’ Cold

The latest EIA report Thursday revealed a lighter-than-average net 50 Bcf withdrawal from U.S. natural gas storage for the week ending Dec. 9, though traders are likely to be more interested in how inventories fare with late December cold.

“The market has appeared reticent following recent high-profile forecast busts,” EBW Analytics Group LLC analyst Eli Rubin told clients. “If the cold blast delivers, however, 225 Bcf-plus weekly storage draws could send January shooting higher.”

Still, in the bigger picture, a cold blast to close out 2022 is unlikely to usher in pressing storage adequacy concerns, according to the analyst.

“On a seasonal basis, the winter storage trajectory appears sufficient, and downward pressure on Nymex futures could resume as soon as the market can see through the upcoming cold blast to warmer temperatures ahead,” Rubin said.

Midday weather data from the American model trended colder Thursday, including by suggesting frigid temperatures would be “slower to erode or moderate” during the Dec. 27-30 time frame, according to NatGasWeather.

“Most importantly, the midday data remained impressively cold this weekend through next week as several frigid shots sweep across the U.S.,” the firm said. “…The first in a series of frigid blasts will sweep across the U.S. this weekend” with lows ranging from below zero to the 20s over the northern Lower 48 and in the teens to 30s farther south, enough to drive “strong national demand.”

Subsequent “reinforcing Arctic blasts” set to arrive next week appeared “rather intimidating” in the latest forecasts, NatGasWeather added. They are expected to deliver extremely frigid conditions for the Midwest and Plains before the cold would spread farther south and to the east.

Freeport Restarts When?

Meanwhile, as residential/commercial demand is set to rise sharply into late December, the timing of the Freeport LNG terminal’s return to service remains a “critical fundamental piece of the demand equation,” according to Rystad analyst Ade Allen.

Recent news of a lengthy request for information from federal regulators directed at the Freeport LNG terminal “has added to speculation that the timeline could potentially shift again,” the analyst added.

Even so, “the current short-term weather forecast is strong enough to offset the lack of exports and provide buoyancy to the overall winter demand picture,” according to Allen.

The post Natural Gas Forward Prices Rise in the East, Fall in the West as Market Braces for Cold appeared first on Natural Gas Intelligence

Western Natural Gas Forwards Soar on Cold, Pipeline Constraints Despite Discounts Elsewhere

Thu, 12/08/2022 - 14:24

Soaring premiums along the West Coast and deep discounts for the rest of the Lower 48 produced a week of varied price action for regional natural gas forwards during the Dec. 1-7 trading period, NGI’s Forward Look data show.

Amid reports of a curtailment in volumes flowing through Gas Transmission Northwest’s (GTN) Kingsgate location along the U.S./Canadian border, Pacific Northwest prices raced higher during the period. Northwest Sumas January fixed prices jumped $5.991 to $20.586/MMBtu, while Malin surged $6.122 to $18.909.

Points farther south saw gains of a similar magnitude, including at PG&E Citygate, where January fixed prices picked up $5.923 to reach $19.729.

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Earlier in the week, Wood Mackenzie notified clients of maintenance on GTN’s system scheduled between Tuesday (Dec. 6) and Thursday (Dec. 8) that had the potential to impact up to around 300,000 MMBtu/d of volumes flowing through Kingsgate. 

The tighter conditions on the GTN system coincided with supportive regional forecasts. Updated maps from Maxar’s Weather Desk as of Thursday showed below and much below normal temperatures blanketing large swaths of the western Lower 48 throughout the 15-day projection period. 

The forecaster predicted a “steady” round of unseasonable chills for the West during the six- to 10-day (Tuesday through Dec. 17). For the 11- to 15-day (Dec. 18-22), the forecast featured “a widespread coverage of below normal temperatures, being most anomalous from the West to the North-Central, with much to strong belows.”

Potentially adding to the upward price pressures out West, the Pacific region is operating at a sizable storage deficit versus the five-year average. The latest Energy Information Administration (EIA) data Thursday put Pacific stockpiles at 217 Bcf, a 23.6% deficit versus the five-year average.

Mountain region stocks stood at 193 Bcf as of Dec. 2, or off 5.9% versus the five-year, the latest EIA data show.

In fixed price terms, the rest of the Lower 48 saw little of the bullishness displayed by Western hubs during the Dec. 1-7 period. Henry Hub January fixed prices tumbled $1.212 week/week to $5.733. 

Futures Bottoming?

Disappointing weather-driven demand to open December helped drive heavy selling for Nymex futures for much of the Dec. 1-7 period. Prices dipped below $5.50 — about a $2 discount versus pre-Thanksgiving levels — before bouncing higher with a 25.4-cent rally in Wednesday’s session. 

Wednesday’s bounce still left ICAP Technical Analysis analysts unconvinced that the market had truly found a bottom.

ICAP analyst Brian LaRose in a note to clients questioned whether Wednesday’s price action represented “more serious bottoming action” or if it was merely a “relief rally for a minor, short-term overextended condition.”

To confirm January prices have carved out a more durable bottom, bulls need to ”promptly start chipping away at the ratio retracements associated with the $7.604/8.177 highs and get back above the 22 day moving averages,” LaRose said. “Forced to treat any near-term congestion/strength as a pause in an ongoing down trend otherwise.”

The January contract continued to build on the midweek momentum in Thursday’s trading, rallying another 23.9 cents to settle at $5.962.

After weather largely failed to deliver from a natural gas demand standpoint in the first half of December, recent forecasting as of Thursday teased a more promising temperature outlook heading into the last two weeks of 2022.

“Arctic air over Western Canada is expected to advance aggressively” across the Lower 48 late next week through Dec. 22, delivering frigid low temperatures, including in the 20s and 30s over southern portions of the country, according to NatGasWeather.

A colder pattern could potentially extend into the final week of 2022, the firm said. 

“It will need to if a sustained weather-driven rally is to be expected. But for now, the weather data remains cold enough Dec 16-22 for a bullish interpretation,” NatGasWeather added.

Still, recent weather model performance raised doubts over the extent of upcoming cold, as forecasts had previously teased a much chillier outlook for the first half of December before ultimately trending warmer, according to the firm.

“As such, we need to be careful the weather data doesn’t flip back warmer in coming runs since it would likely result in a violent negative reaction if it were to do so,” NatGasWeather said.

Meanwhile, in another potential wrinkle for domestic natural gas markets tethered to global dynamics by LNG exports, winter demand in Europe has shown signs of heating up to start the month of December, according to Rystad Energy.

“European temperatures have continued to decline in the first week of December,” driving up weekly storage withdrawals and pushing the continent’s liquefied natural gas imports to “record high levels,” according to Rystad analyst Zongqiang Luo.

As of Monday, the UK’s NBP (aka National Balancing Point) benchmark was trading around 40% above early November levels, the analyst said. 

“Gas-fired generation is responsible for about 40% of the UK’s power output,” Luo said. “Gas use in the power sector has been on the rise due to low wind speeds across the UK this year and a recent drop in temperatures, which is pushing up power demand. The UK has surpassed Italy in having the most expensive power in Europe, with prices up 121% week/week.”

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Natural Gas Forwards Mixed as Weather Maps Fail to Impress Overall

Thu, 12/01/2022 - 14:22

Reflecting a spectrum of blue and orange temperature projections on weather maps at this early juncture in the season, natural gas forwards trading was mixed during the Nov. 23-Dec. 1 trading period. Strong gains for western markets countered declines throughout much of the eastern two-thirds of the Lower 48, NGI’s Forward Look data show.

Fixed price January prices increased sharply at hubs along the West Coast and in the Pacific Northwest. PG&E Citygate surged $2.677 week/week to reach $13.806/MMBtu. January fixed prices at Northwest Sumas rallied $3.427 to $14.595.

This comes as the Energy Information Administration’s (EIA) latest inventory data showed storage in the Pacific and Mountain regions notably lagging historical norms. Pacific region storage stood at 226 Bcf as of Nov. 25, a 21.5% deficit to the prior five-year average. Mountain region stockpiles stood at 197 Bcf, or 5.3% below the five-year average.

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Recent forecasting from Maxar’s Weather Desk generally pointed to chillier conditions along much of the West Coast and the northern Lower 48 through the first half of December, with more seasonal to warmer-than-normal temperatures elsewhere.

For next week, the forecaster called for a “boundary between unseasonably cold air to the North and above to much above normal temperatures in the South.” The Lower 48’s Northern Tier was expected to continue seeing below-normal temperatures for the Dec. 10-14 timeframe, according to Maxar.

On the East Coast, a few New England and Mid-Atlantic hubs saw gains during the period, adding to already hefty premiums. Algonquin Citygate January basis rose 56.5 cents to end at plus-$29.528, while Cove Point front month basis jumped 52.3 cents to plus-$10.978.

Meanwhile, numerous locations saw fixed price discounts of around 40-60 cents week/week, paced by a 46.6-cent decline in January Henry Hub prices, which ended the period at $6.945.

Risk Premiums ‘Unwarranted’?

January Nymex futures conceded ground throughout the Nov. 23-Dec. 1 period after rallying into the Thanksgiving holiday. The December contract sold off 31.2 cents into expiry in Monday’s session. January tumbled 30.5 cents on Wednesday before dropping another 19.2 cents on Thursday to settle at $6.738.

Futures receded as forecasts for the first half of December failed to offer the kind of widespread cold needed to inspire bullish sentiment.

The latest weather data from the American model was warmer-trending Thursday, showing less cold air advancing from Canada into the United States from next Wednesday through Dec. 10, according to NatGasWeather.

Recent data from the European model, meanwhile, offered a colder outlook for the second week of December, the firm said.

“It’s worth noting the weather models” at one point “teased a frosty U.S. pattern” for the first week of December “only to back off considerably,” NatGasWeather said. “…The Dec. 8-15 pattern is likely viewed as just cold enough by most major players, but for full-fledged bullish weather sentiment, more ominous and persistent cold will be required.”

There are potential bullish catalysts on the horizon, including a possibly frigid back half of December and an anticipated return to service for the Freeport LNG terminal, according to EBW Analytics Group.

Still, “risk premiums may prove unwarranted on a seasonal basis absent substantial cold,” EBW analyst Eli Rubin told clients in a recent note. “Natural gas pricing remains dominated by the chances for a low-likelihood, high-impact event of extreme cold weather sweeping the country in mid-winter.

“With natural gas on the price-inelastic portion of the demand curve, prices could run steeply higher in a bullish scenario,” Rubin added. “This setup, while unlikely, is contributing to enduring Nymex winter risk premiums and the reluctance of traders to short natural gas — enabling prices to trade above our assessment of fundamental fair value.”

At this point in the season, U.S. storage inventories appear adequate, but there’s no room for complacency given weather, which is the “ultimate unknown factor,” Rystad Energy analyst Ade Allen said in a recent note.

Alongside rising residential/commercial demand with the onset of winter heating, “the other big demand factor is the restart of Freeport LNG,” Allen said. “Recent communication from the operator points toward a restart in December, but market hawks remain skeptical. Facility construction and rehabilitation have been slowed by regulatory hurdles that make estimating a restart timeline nearly impossible.”

Rystad’s estimates put the Texas export facility on track for a partial restart by mid-January, with 85% utilization (2.0 Bcf/d) by the end of January, according to the analyst. Full utilization of 2.38 Bcf/d would follow by March 2023 under the firm’s modeling, Allen said.

“Should this restart timeline be verified, it would provide bullish sentiment and an upward trajectory for prices in the first quarter, a period that historically has been prone to supply disruptions due to winter weather impacts,” the analyst added.

Stronger Basis For Permian 

Among the notable regional basis shifts during the Nov. 23-Dec. 1 period, production hubs in West Texas appeared to see a boost from the stronger pricing downstream in the western Lower 48.

Waha January basis picked up 28.2 cents week/week to finish at a 67.3-cent discount to Henry Hub. El Paso Permian ended at minus-63.3 cents, a 28.7-cent swing higher.

Elsewhere, winter basis differentials also improved in Western Canada.

NOVA/AECO C added 23.4 cents for January, though the hub continued to trade at a sizable $2.182 discount to Henry, Forward Look data show.

The post Natural Gas Forwards Mixed as Weather Maps Fail to Impress Overall appeared first on Natural Gas Intelligence

Messy Winter Weather in Pacific Northwest, Rockies Drives Stout Forward Price Gains

Tue, 11/22/2022 - 13:11

Huge natural gas forward basis moves continued for pipeline capacity-starved New England, but hefty premiums also shifted further west during the short Nov. 17-21 period, NGI’s Forward Look data showed. With several inches of snow falling and a stormy outlook ahead, the Rockies and Pacific Northwest posted sharply higher forward prices.

Northwest Sumas December basis picked up 79.0 cents through the period to reach $3.465, according to Forward Look. Sumas prompt-month fixed prices hit $10.239, while January jumped 89.0 cents to $10.093. The balance of winter (December-March) picked up 83.0 cents to average $8.742/MMBtu, and the summer strip (April-October) moved up 22.0 cents to $4.410.

Similarly steep gains were seen at Opal, where December basis tacked on 67.0 cents to reach $2.320, Forward Look data showed. This represented a fixed price of $9.096 for the prompt month. Further out the forward curve, the January contract climbed 89.0 cents to reach $9.263 and the balance of winter added 82.0 cents to average $8.262. The summer strip, meanwhile, ticked up only 13.0 cents to average $4.560.

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The National Weather Service (NWS) said a shortwave trough in the eastern Pacific was expected to arrive in the Pacific Northwest on Tuesday. It could bring low-elevation rain and mountain snow to the region before spreading over the Northern Rockies. 

The system is forecast to then shift over the Northern/Central Plains ahead of Thanksgiving. Snowfall was expected primarily over the northern Cascades, where up to one foot of snow and isolated higher amounts were expected, according to NWS. Freezing rain and some sleet also were likely to accumulate over portions of east-central Washington.

By Friday, the next storm is likely to be knocking on the doorstep of the Northwest, according to AccuWeather. The forecaster said this would be the start of a much stormier and colder pattern overall for the West heading into early next week.

Pipelines in the region already were being impacted by the frigid weather. Kern River Gas Transmission reported low linepack this week, with deliveries limited beginning over the weekend and remaining through the week so far.

Criterion Research LLC noted that Canadian imports into the Pacific Northwest have ratcheted up amid the bitter conditions, with regional demand remaining high even as overnight temperatures trended on the warm side. Storage facilities in the region also have boosted withdrawals.

Meanwhile, inventories at Pacific Gas & Electric Corp. (PG&E) are low. Maintenance along the PG&E pipeline, which began Monday, is set to continue through late November, adding to constraints, Criterion said. PG&E declared an operational flow order amid the tight conditions. Storage withdrawals extended into Southern California as well.

“PG&E’s storage was in especially bad shape as its net inventory dropped to only 3.8 Bcf,” Criterion Research’s James Bevan, director of research, said. “To put this in perspective, aside from 2019 (and this year), inventories have only been lower once, and that was 2018’s end of season. Not a promising look.”

Henry Hub Volatility

With a stretch of widespread chilly air finally showing signs of easing, Henry Hub forward prices continued to post mostly gains during the short trading period.

There are lots of potential reasons prices have risen close to $7.00 again. Some traders are pointing to the potential for a railroad strike that could limit coal deliveries and prop up gas demand. The possibility of cold weather returning in December also provided momentum for bulls, as has the typical volatility seen ahead of contract expiration.

NatGasWeather said the weather data are mixed. The Global Forecast System trended a little warmer for the next five days, a few heating degree days colder for Nov. 27-Dec. 2 and warmer again for Dec. 3-7.

There were major changes in the latest data related to the timing of swings in national demand, with demand easing for the next week as temperatures are forecast to climb into the 60s and 70s over the southern United States and into 40s and 50s over the northern states.

“Frigid air remains on track to arrive over Northwest, Mountain West and Northern Plains Nov. 29-Dec. 7 with lows of minus 10s to 30s for regionally strong demand,” NatGasWeather said. “However, recent weather data wasn’t as aggressive advancing cold air eastward Dec. 2-7, thereby keeping the southern and eastern U.S. mild most days with highs of 40s to 70s.”

Given the recent cold that’s blanketed much of the Lower 48, market observers expected a considerable decline in storage inventories. After all but erasing deficits to historical levels, storage deficits could widen over the next two weeks.

At noon ET on Wednesday, the Energy Information Administration (EIA) is set to publish its weekly inventory report. Estimates ahead of the report were wide ranging, from a draw as light as 60 Bcf to one as steep as 111 Bcf.

A Bloomberg survey of nine analysts had a range of draws from 74 Bcf to 111 Bcf, with a median pull of 86 Bcf. Estimates submitted to a Wall Street Journal poll also were within that wider range and averaged an 89 Bcf withdrawal. NGI estimated a lower-end draw of 65 Bcf.

EBW Analytics Group LLC said the cold December now favored by independent weather forecaster DTN could rapidly deplete the storage cushion and reintroduce upside price risks. These risks come into play particularly if Freeport LNG hits its updated guidance. The liquefied natural gas export facility said last week it is targeting mid-December for initial operations.

“Cold may have to prove enduring to sustain Nymex risk premiums on a seasonal basis, but renewed upside for the 30-45 day period remains possible,” EBW senior analyst Eli Rubin said.

The December Nymex gas futures contract inched higher Tuesday to settle at $6.779, up slightly from Monday’s close of $6.776.

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Natural Gas Forwards Rally Further as Cold Snap Seen Widening Deficits after Massive Recovery

Thu, 11/17/2022 - 12:24

Natural gas forward prices continued to strengthen during the Nov. 9-16 period amid a continuation of colder-than-normal temperatures ahead of the core of winter, according to NGI’s Forward Look.

Gains (again) were most pronounced in New England, where rising heating demand and pipeline constraints combined to drive hefty premiums compared to the rest of the country.

Basis prices at the Algonquin Citygate were the clearest example of the tight conditions that have plagued the region. December basis climbed $1.05 during the period to reach $11.296, Forward Look data showed. For comparison, December basis averaged only 4.0 cents across North America.

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Substantial premiums extended throughout the winter strip, with Algonquin fixed prices for January jumping $3.210 to $28.830, and the balance of winter (December-March) climbing $2.200 to $22.395. By next summer (April-October), prices are seen sliding back to around $4.630 on average.

Benchmark Henry Hub, meanwhile, moved higher through the period – but remained below $7.00 in even the peak winter months. December fixed prices stood Wednesday at $6.205, up 34.0 cents on the week, while the balance of winter averaged $6.193, up 35.0 cents. The summer strip rose 13.0 cents to average $4.890.

After enjoying rather comfortable temperatures in recent days, temperatures were forecast to plunge in Boston. Highs in the upper 50s on Wednesday were expected to top out in the upper 40s by Thursday and then continue falling through the weekend. Sub-freezing overnight lows were expected by Saturday before a gradual warmup next week.

Earlier this month, the CEO of New England’s largest utility, Eversource Energy, called on President Biden to enact federal emergency orders to “swiftly address the growing concerns” of the region’s access, or lack thereof, to natural gas this winter heating season. New England, which lacks the gas pipeline infrastructure to meet all of its demand, relies on gas shipments to three liquefied natural gas import facilities that serve the region.

Company chief Joseph Nolan called on Biden to waive the Jones Act of 1920, which mandates that all goods shipped between U.S. ports must be transported by U.S. flagged vessels. Such vessels must be built, owned and operated by U.S. citizens or permanent residents. 

There are currently no U.S. flagged LNG vessels, meaning LNG produced in the United States cannot be transported to LNG import facilities in the country, let alone any of the three LNG import facilities that serve New England. 

Interstate Natural Gas Association of America chief Amy Andryszak also sent a letter to President Biden this month to address “the root cause of the region’s long-standing electric reliability problems – a lack of adequate natural gas infrastructure.” In addition, leaders of the New England Independent System Operator have stressed the importance of natural gas to ensure stable power supply as it transitions to a renewable-powered grid.

Elsewhere on the East Coast, lake-effect snow was starting to intensify across northwestern Pennsylvania and western New York, according to AccuWeather. About 19 miles southeast of Buffalo, in Colden, NY, 11.6 inches of snow had accumulated in 24 hours. In the nearby town of Springville, NY, 11 inches of snow was measured as of early Thursday, while in Ohio and Pennsylvania, snowfall totals surpassed the one-foot mark. 

Even with the bitter cold in the region, though, prices paled in comparison to those farther north in New England, according to Forward Look. Transco Zone 6 NY’s December contract rose 43.0 cents during the Nov. 9-16 period to reach $5.504, while the balance of winter picked up 40.0 cents to average $5.522. The summer 2023 strip climbed 20.0 cents and averaged only $4.270, a 62.0-cent discount to Henry Hub.

A Full Recovery For Storage

On the whole, widespread price gains were seen along the forward curve, but those could prove fleeting.

NatGasWeather said weather models have been struggling about how much cold may impact the northern United States before the Thanksgiving holiday through the end of the month. Overnight, the Global Forecast System was warmer, while the European data was colder. Regardless, though, the pattern during that time is closer to seasonal rather than bullish, like it is expected to be through the next week.

The forecaster said early-season cold, including deep into Texas, already has cut into production. As a result of widespread subfreezing temperatures, the first wellhead freeze-offs of the season have dropped U.S. production by 2 Bcf/d after hitting fresh all-time highs this past weekend.

“…With power burns strong this week and into the mid-30s Bcf/d on widespread cold, the supply/demand balance is tighter,” NatGasWeather said.

As such, the forecaster noted that storage inventories, which all but erased historical deficits based on the latest data, were likely to see significant withdrawals reflected in upcoming government inventory data.

On Thursday, the Energy Information Administration (EIA) said stocks for the week ending Nov. 11 rose by 64 Bcf, likely the last injection of the fall injection season. After sitting more than 300 Bcf below the five-year average late in the summer, stocks finished the period only 7 Bcf short. What’s more, stocks rose 4 Bcf above last year’s level during the same week last year.

Broken down by region, the South Central added a plump 35 Bcf into storage, EIA said. This included a 19 Bcf build in nonsalt facilities and a 16 Bcf build in salts. East stocks climbed 17 Bcf, while Midwest stocks rose by 16 Bcf. Mountain inventories remained flat on the week, and the Pacific withdrew 6 Bcf.

Total working gas in storage reached 3,644 Bcf.

Looking forward, however, EBW Analytics Group LLC said the near-term outlook showed bitter near-term cold rapidly rebuilding storage deficits. As deficits rebuild, the market may again refocus on upside risks facing natural gas, potentially yielding upside momentum for Nymex futures pricing.

Importantly, Freeport LNG’s absence from the market puts the onus on cold winter weather to sustain pricing at these levels, according to EBW. While prices are off the double-digit peaks seen a couple of months ago, futures remain at the highest levels since 2008.

After weeks of rumors swirling in the market, EBW said its base case for Freeport’s return has shifted to January. The LNG export facility has said it planned to restart operations at the facility on the upper Texas coast in early to mid-November. That timeline has come and gone now, with Freeport not yet submitting a restart plan to federal regulators.

Media and analyst outlets also reported that Freeport has notified customers of unlikely November and December cargoes. The facility’s outage, ongoing since June, has contributed to market anxieties over the historically tight global LNG market. Speculation and unverified statements shared on social media have caused domestic gas prices to fluctuate, but Freeport as of Thursday had not put the rumors to rest with an updated timeline.

The Pipeline and Hazardous Materials Safety Administration said earlier in the month that Freeport filed its Root Cause Failure Analysis on Nov. 1, fulfilling one step in its process to meet regulators’ August consent agreement. As part of that filing, the company said it is developing testing protocols and expanding staff at the export facility after a third-party review highlighted process failures and human error as possible factors in the summer explosion.

“This is now the third delay to Freeport’s stated timetables, and further delays should not be ruled out,” EBW senior analyst Eli Rubin said. “At the same time, however, any news confirming a January restart could be interpreted as bullish by the market. If the facility secures needed regulatory approvals and accepts test gas flows in advance of a full January restart, for example, it would likely be a bullish catalyst for Nymex futures.”

The post Natural Gas Forwards Rally Further as Cold Snap Seen Widening Deficits after Massive Recovery appeared first on Natural Gas Intelligence

Brief Wintry Blast Boosts Natural Gas Forwards Prices; New England Sporting Hefty Premiums

Wed, 11/09/2022 - 13:50

With subfreezing temperatures on the way, natural gas forward prices strengthened during the trading period from Nov. 3 to 8, according to NGI’s Forward Look.

Price swings were relatively modest at the front of the forward curve when compared with recent weeks, likely because the drop in temperatures is expected to be short lived. The majority of U.S. locations posted fixed natural gas price increases of less than a quarter, while New England markets posted substantial decreases. Notably, though, December fixed prices in the region are more than $10.00 above benchmark Henry Hub.

At the Algonquin Citygate, December natural gas forward prices tumbled 84.0 cents from Nov. 3 to 8 to reach $16.881, Forward Look data showed. This represents a $10.743 premium over Henry Hub. That spread was even wider for the January contract, with Algonquin sitting at $26.142 and Henry Hub at $6.529.

Further out the curve, stout premiums were seen throughout the balance of winter (December-March). The four-month strip managed to slip $1.00 through the trading period but still averaged a hefty $20.747. Summer 2023 (April-October) prices held steady at $4.540.

Elsewhere in the Northeast, Iroquois Waddington posted similarly high prices across the winter strip, even as they fell week/week, Forward Look data showed. December stood Tuesday at $12.529 and January at $27.142. The balance of winter averaged $18.391, while the summer strip averaged only $4.640.

Though current weather models show mild temperatures remaining in place for a few more days across most of the Lower 48, the Northeast is one of a couple of regions that is in store for chilly weather. NatGasWeather said a glancing cool shot would drop high temperatures into the 50s for the next few days.

New England, in particular, faces uncertainty in the event of significant, prolonged cold this winter. Despite its proximity to prolific Appalachia Basin gas supplies, a lack of sufficient pipeline infrastructure has opened up the region to extreme volatility and sharply higher prices. This normally occurs in the winter, but prices have spiked sharply in the summers as well.

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In addition to piped gas, New England has to rely on imported LNG to meet its wintertime needs. Against that backdrop, the region is at risk of having to price itself high enough to attract liquefied natural gas cargoes in the event of a colder-than-normal winter.

Oil also factors into the equation, but distillate fuel oil (DFO) stocks have dwindled to historic lows following last winter. Should the region experience yet another cold snap, further reliance on the fuel may require in-season replenishments to keep up with last winter’s total utilization of 637 GWh, according to BTU Analytics LLC.

“At current levels, DFO generation can be maintained for a few days,” said BTU analyst Eric Hinojosa. “Furthermore, without sufficient replenishments during the winter, or accelerated depletions due to lack of LNG imports, oil generation’s ability to balance the market is at risk.”

What Do The Weather Maps Say?

As for the rest of the country, NatGasWeather said a huge swing in temperatures is expected by the weekend as frosty air over Western Canada releases and spreads across the northern half of the United States. Overnight lows are expected to plunge more than 10 degrees below zero in some areas, while others hold near the freezing mark.

Subfreezing air also is expected to advance aggressively into the southern states, sending lows into the 20s and 30s over Texas and the South. This should be a boon to national demand through next week, with the latest weather data trending slightly colder.

Beyond next week, the weather data points to the bitter air retreating into Canada by Nov. 20 and remaining there for the next five days at least. NatGasWeather said this should result in a return to seasonal demand, although the overnight data was slower to erode cold and where a few additional heating degree days were added.

“However, much of the longer range data for the last week of November into early December isn’t as cold as needed to intimidate,” NatGasWeather said. However, there is some risk of colder trends in time because of the frigid air becoming anchored over much of Canada going forward, according to the forecaster.

Freeport And Other Burning Questions

The return of Freeport LNG also has dominated headlines this week as rumblings of a delayed restart circulate throughout the market. Last week, Freeport reiterated comments that it plans to restart operations at the export facility this month. However, federal regulators have indicated that the facility has yet to file the required paperwork to do so.

Freeport has been offline since early June following an explosion.

“If the facility were to surprise the market and restart tomorrow, prices could jump $1-2/MMBtu,” said EBW Analytics Group LLC’s Eli Rubin, natural gas analyst. “The distribution of potential risks, however, leans bearish: If Freeport does not restart by a rapidly approaching December, the odds plummet for a sufficiently cold winter to spark storage fears in the market.”

EBW noted that independent weather forecaster DTN is calling for a cold December. However, that alone is not enough to induce winter shortage risks, a key catalyst for higher prices. “Instead, it would require extended, durable cold to drive prices sustainably higher,” Rubin said.

That’s largely because mild weather this fall has led to a string of well above-average storage injections that have all but wiped out fears of a crunch this winter. As of Oct. 28, total working gas in storage stood at 3,501 Bcf, according to the Energy Information Administration (EIA). This is 101 Bcf below year-earlier levels and 135 Bcf below the five-year average, a vast improvement from the 300 Bcf-plus deficit seen this summer.

What’s more, estimates ahead of Thursday’s EIA inventory report point to yet another much larger-than-normal increase in stocks. Reuters polled 15 analysts, whose estimates ranged from injections of 75 Bcf to 101 Bcf, with a median forecast of 83 Bcf. A Bloomberg survey had a wider range of projections that included a low-end injection of 66 Bcf. It too produced a median build of 83 Bcf. NGI pegged the storage increase at 68 Bcf.

For comparison, the EIA recorded a 15 Bcf injection for the similar week last year, while the five-year average build is 20 Bcf.

Other external bullish catalysts also could boost prices, though.

Rubin pointed out that there is growing anticipation in the gas market of a railroad strike. This potentially could imperil coal deliveries and vastly increase the call on natural gas-fired generation to keep the lights on.

The threat of a railroad shutdown briefly sent prices spiking above $9.00 in September, and Rubin pointed out that the dispute was not resolved. Rather, it was postponed until after the midterm election.

Rubin noted that all 12 railroad unions separately need to approve the deal to avoid a strike. Seven have approved deals. Two have rejected union contracts, and must find a way forward over the next 10 days if a strike is to be averted.

“In our view, the overwhelming pressure to reach a negotiated settlement ahead of the holiday season is likely to contain any strike, should one even occur, to only a few days,” Rubin said. “Still, renewed price volatility may be likely until an agreement is secured across all 12 rail worker unions.”

The December Nymex gas futures contract settled Wednesday at $5.865, off 27.3 cents from Tuesday’s close.

The post Brief Wintry Blast Boosts Natural Gas Forwards Prices; New England Sporting Hefty Premiums appeared first on Natural Gas Intelligence

Mere Tease of Winter’s Arrival Sends Natural Gas Forwards Prices Soaring

Thu, 11/03/2022 - 13:01

Natural gas forward prices surged from Oct. 27 to Nov. 2 as hints of colder weather finally emerged in long-range forecasts, NGI’s Forward Look data showed. 

December prices rose an average 41.0 cents through the trading period, while frigid air and early-season snow in the Pacific Northwest and Rockies fueled even more substantial increases in those regions.

Plump natural gas price hikes were seen through the balance of winter (December-March), which added 25 cents on average, according to Forward Look. Smaller price increases were seen further out the curve.

[Want to know how global LNG demand impacts North American fundamentals? To find out, subscribe to LNG Insight.]

The hefty price gains for the winter occurred in spite of stout production, rising storage inventories and an ongoing curtailment of LNG demand, at least for now.

With the turn of the calendar to November, the gas market has been eagerly anticipating the arrival of widespread cold for clues on how it may impact supply and demand. After all, liquefied natural gas exports are considerably higher year/year, with Freeport LNG still offline following a June explosion. Any significant cold could spark a rally in gas prices that have plunged back down to around $6.00 compared to about $10 in late August.

Though far from certain, weather models have shown signs of winter in recent days. Notably, colder runs in both the American and European models fueled a 67-cent surge at the front of the curve on Monday. But, as NatGasWeather pointed out, the models have struggled the past several days.

A warmer shift in the data occurred on Tuesday, leading to a swift price correction along the Nymex futures curve, while Wednesday saw another reversal and led to another rally.

“While market circumstances are different, price action feels reminiscent of the mid-September price spike induced by escalating fears over a then-pending railroad strike,” said EBW Analytics Group LLC’s Eli Rubin, senior analyst. “On Sept. 14, the front-month surged 83 cents only to return 79 cents of gains the following day. Then, as now, the market was about to plunge into a multi-week period of enormous injections.”

That said, the market remains structurally exposed to bullish catalysts driving prices steeply higher, according to Rubin. Of course, that may prove a difficult feat given the blowtorch weather in play.

NatGasWeather said the overnight data was mixed, though, with the Global Forecast System (GFS) gaining a hefty 10 heating degree days (HDD) but the European Centre (EC) losing 5 HDDs. This makes the GFS colder and more bullish than the EC by 20 HDDs. This is an important difference in need of resolving, according to NatGasWeather.

The forecaster expects exceptionally light national demand to continue another eight to nine days as the eastern half of the country remains much warmer than normal. During this time, highs in the 60s to 80s should be widespread, including in key demand centers like New York City.

Wintry Mix In The West

“Where temperatures are cold enough the next nine days is across the West, as chilly weather systems track through with rain and snow,” NatGasWeather said.

The chilly outlook boosted forward basis prices across the region. Stanfield December basis jumped 43.0 cents from Oct. 27 to Nov. 2 to reach $1.210, according to Forward Look. By comparison, the average basis move was a modest 2.0 cents. Several locations also saw basis prices weaken during the period.

The hefty natural gas price gains continued throughout the winter months, with Stanfield fixed prices for the balance of winter averaging $7.036. The summer 2023 strip (April-October) picked up 19.0 cents to average $4.420.

Northwest Sumas December basis jumped 54.0 cents from Oct. 27-Nov. 2 to reach $2.702, Forward Look data showed. Fixed prices hit $8.97 for the prompt month, while the balance of winter averaged $7.825.

In northern California, PG&E Citygate December basis tacked on 34.0 cents through the period to reach $1.838, while the fixed price rose to $8.106. The balance of winter jumped 63.0 cents to $7.789, and the summer strip posted a stout 31.0-cent increase to average $6.160.

The National Weather Service said moderate to heavy mountain snow would continue through Friday across the Central Rockies. Meanwhile, the next moisture surge from the Pacific is forecast to reach the Pacific Northwest late Thursday, with mountain snow and lower-elevation rain rapidly overspreading the area. Rainfall amounts of up to six inches are possible across the region.

The early-season precipitation would bode well for hydroelectric power supplies this spring, if it continues. A prolonged drought out West has lowered reservoirs to record lows, with hydroelectric generators operating at reduced capacity as a result. This has proven to boost demand for gas, though, with soaring temperatures in the summer leading to increased cooling loads and plunging temperatures in the winter bolstering gas demand for heating.

‘Significant Upside Potential’ With Freeport Return

Notwithstanding the strength in forward prices out West, much of the rest of the country largely moved in tandem with Henry Hub. The benchmark posted noteworthy gains of its own during the Oct. 27- Nov. 2 trading period.

The rally in spite of continued bearish fundamentals is a reflection of the outsized moves prices can make given thin liquidity. Notably, production continues to hover near 100 Bcf/d despite ongoing maintenance across the Lower 48. Further, that maintenance – largely in the Permian Basin and Appalachia – is expected to conclude within the next couple of weeks, opening the door for more production growth.

With widespread cold failing to materialize so far, the overhang in supply amid slugging weather demand has trickled down into storage over the past six weeks and vastly improved the supply outlook for the coming months.

On Thursday, the Energy Information Administration (EIA) reported the sixth triple-digit storage build of the injection season, a whopping 107 Bcf increase to storage inventories, which was just 3 Bcf shy of NGI’s 110 Bcf build estimate for the week.

The build easily surpassed last year’s 66 Bcf build as well as the 45 Bcf five-year average injection. It also topped most expectations of a build closer to 100 Bcf.

The South Central region led with a monstrous 44 Bcf injection that was split evenly between nonsalt and salt facilities, according to EIA. The increase lifted nonsalt stocks to a slight 11 Bcf surplus to both year-ago and five-year average levels. Salts stood only 19 Bcf below last year.

Participants discussing the EIA report on energy chat Enelyst attributed the large injection in the South Central region to strong wind generation during the reference week. Enelyst managing director Het Shah pegged wind generation at 65 average GWh last week, but said wind is at only 38 average GWh so far this week. That said, coal has stepped in this week to help offset the loss of wind this week. “It didn’t all fall on natural gas.”

Elsewhere across the country, Midwest inventories rose by 35 Bcf and East stocks increased by 23 Bcf, EIA said. The Mountain region added 5 Bcf, while the Pacific reported a 1 Bcf withdrawal.

Total working gas in storage rose to 3,501 Bcf, which is 101 Bcf below the similar week last year and 135 Bcf below the five-year average.

EBW’s Rubin said the string of “tremendously bearish” storage injections is making it increasingly difficult to justify elevated risk premiums in Nymex futures prices. Still, it is possible that the back of November may provide some incremental physical support for gas.

Likewise, the return of Freeport LNG also could deliver a swift kick to gas prices. EBW noted that Freeport LNG filed a long-awaited certificate of compliance report late Wednesday with federal regulators. Although the “supplemental information” was marked “privileged and confidential” and shielded from the public, the response to FERC could get the ball rolling on the required Federal Energy Regulatory Commission’s review to startup operations, according to EBW.

It is unclear if a similar filing at Pipelines and Hazardous Materials Safety Administration (PHMSA) has been made, EBW said.

The firm noted the mixed messages surrounding Freeport LNG’s return. LNG offtakers have relayed Freeport’s communications to anticipate November cargo loadings, but both PHMSA and FERC have stated as recently as Tuesday they were not even in possession of documentation to review.

“It is likely that a facility restart is not imminent as regulators will need to review Freeport’s submissions, and could require further modifications or alterations,” Rubin said. “Still, if news of a Freeport LNG return coincides with the dramatic turn colder in Weeks 3 and 4, significant upside potential is possible for Nymex gas futures.”

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Natural Gas Forwards Mixed as Mild Forecast for East Keeps Pressure on Prices

Thu, 10/27/2022 - 14:30

Reflecting forecast maps that showed early winter cold largely confined to western portions of the Lower 48, regional natural gas forwards underwent a mix of changes during the Oct. 20-26 trading period, NGI’s Forward Look data show. 

Fixed prices at benchmark Henry Hub picked up 14.4 cents to trade at $5.611/MMBtu for November delivery, finding a middle ground between healthy gains for western markets and hefty losses in the Northeast.

November fixed prices at SoCal Citygate surged 86.2 cents to $7.318; Opal climbed 56.2 cents for November, finishing at $5.771.

[Will the Polar Vortex Disrupt Winter Gas Prices? Join NGI’s Senior Energy Analyst Shaylon Stolk as she goes back to her academic roots in climate modeling to discuss how the Polar Vortex works, how much we can predict, and how and extreme winter storm might affect this winter’s natural gas marketplace. Listen now.]

Meanwhile, it was a radically different story for the Northeast, where Algonquin Citygate plunged 70.6 cents to average $6.878 for November delivery. Farther upstream, Eastern Gas South shed 36.1 cents to fall to $4.235.

The contrasting moves largely mirrored the latest weather maps.

In the updated six- to 10-day forecast Thursday, Maxar’s Weather Desk was calling for a “trough diving into the West with an increasing coverage of below normal temperatures.” Meanwhile, “a ridge will be enhanced over the Eastern Half with above to much above normal temperatures.”

Market Waiting On Winter

Albeit with a healthy dose of volatility, Nymex futures continued to face bearish headwinds during the period. A broadly weak weather-driven demand outlook and ample supply figured to continue erasing the storage deficit to the five-year average.

The November contract rolled off the board Thursday at $5.186, a 42.0-cent decline on the day. December tumbled 24.4 cents to $5.875.

The latest Energy Information Administration (EIA) storage report, a 52 Bcf build for the week ended Oct. 21, came in on the lower end of expectations and broke a streak of consecutive triple-digit fall injections.

Still, prices ultimately lost ground on the day.

“What’s driving today’s strong selling is likely expiration of the November contract at the close, warm and bearish weather patterns the next 15 days” and expectations for a larger-than-average injection near 100 Bcf for the next EIA report, NatGasWeather said. 

The year-on-five-year deficit is on track to shrink to minus-50 Bcf by mid-November.

“Going forward, what will be most important is when widespread sub-freezing air finally arrives over the northern and eastern U.S., since larger than normal builds will continue until this occurs,” the firm said. “The latest midday data suggests the natural gas markets will have to impatiently wait a while longer.”

Europe Storage Easing Worries

Meanwhile, looking overseas, the storage situation in Europe has improved to where the continent should endure through the winter absent “very, very cold” temperatures, according to Rystad Energy analyst Nikoline Bromander.

“But the continent is not out of the woods yet — with Russian flows continuing to decline, winter 2023 will be even tougher,” the analyst said. 

European natural gas prices recently dropped to their lowest levels since the summer, Bromander observed.

“The decline is thanks to Europe’s storage facilities now being at high levels, above-normal forecast temperatures for the upcoming European winter, high output from wind power and political agreement within the European Union on cooperative measures to reduce gas prices and consumption,” Bromander said.

Waha Basis Resilient

In contrast to price action in the day-ahead market, basis differentials in West Texas strengthened during the Oct. 20-26 trading period. Waha front month basis picked up 10.0 cents week/week to end at minus-$2.479, while El Paso Permian added 7.0 cents to finish at minus-$2.409.

However, the situation in West Texas was a little more dramatic in the spot market during the period, with day-ahead prices crashing into negative territory as pipeline disruptions limited takeaway out of the region.

Wood Mackenzie analysts Quinn Schulz and Ricardo Falcon-Bautista said late-month maintenance events on the Gulf Coast Express (GCX) and El Paso Natural Gas (EPNG) pipeline systems were causing a “supply glut” in the region.

As these events began, Waha cash crashed, and East Texas cash prices began to move higher. This indicates that the Permian molecules that normally reach the East Texas market are being held captive at their source,” the analysts said in a note to clients Thursday.

The GCX and EPNG maintenance events were expected to conclude by the end of the week.

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Natural Gas Forwards, Futures Prices Tumble Lower, But Too Early to ‘Write Off Winter’

Fri, 10/21/2022 - 12:54

Buckling under the weight of one triple-digit shoulder season storage injection after another, natural gas forwards sold off sharply during the Oct. 13-19 trading period, NGI’s Forward Look data show.

Regional forwards price action from coast to coast reflected a market reconsidering the extent of winter upside risks in light of a rapidly shrinking inventory deficit. Fixed prices for November delivery at benchmark Henry Hub sank 97.3 cents to $5.467/MMBtu for the period. 

Numerous Mid-Atlantic and Northeast hubs saw losses of $1-plus. Algonquin Citygate November fixed prices plummeted $2.562 to $7.584. Basis differentials at the New England hub shed $1.589 week/week to end at plus-$2.122.

[The TTF, LNG Price Divide: Tune into NGI’s podcast to learn about the growing gap between the price of LNG landing in Europe and the pipeline hubs on the continent like the Title Transfer Facility. Listen now.]

Fixed prices at Transco Zone 5 dropped $1.408 to $6.043 for November delivery. Front-month basis there shed 43.5 cents to end at a 58.1-cent premium to the national benchmark.

Meanwhile, the Oct. 13-19 period saw losses continue to mount for Nymex futures, with a run of huge storage injections, compounded by the absence of any compelling signs of early winter weather, putting bulls on the defensive. 

Wrapping up a fifth straight session in the red, the November Nymex contract dropped 10.4 cents to settle at $5.358 Thursday. The front month went on to extend that losing streak on Friday, giving up 39.9 cents to settle at $4.959 as bearish forecasts kept the pressure on prices.

Market Ready to ‘Write Off Winter’?

Nymex natural gas futures have been “in freefall,” EBW Analytics Group analyst Eli Rubin observed Thursday.

Still, “oversold conditions and seasonal fundamentals continue to offer upside risks over the next 30 to 45 days — if more supportive early-winter weather arrives,” the analyst added.

However, bulls hoping to see that winter weather actually arrive were still waiting as the work week drew to a close, based on forecasting from NatGasWeather.

“The weather pattern for the start of November is still expected to be near to warmer than normal over most of the U.S. for light national demand,” NatGasWeather said. “The pattern would favor temperatures being stratified from north to south, with highs of 40s to 60s across the northern U.S. and 60s to 80s across the southern U.S.

“It will take much colder weather maps for bearish weather headwinds to end,” the firm added. Mid-November represents “the next best opportunity” for more impressive cold to show up in the outlook.

Thursday saw the Energy Information Administration (EIA) report a 111 Bcf injection into U.S. natural gas stocks during the week ended Oct. 14. That marked the fifth straight triple-digit injection and cut the deficit to the five-year average to 183 Bcf, or minus-5.2%. Lower 48 stockpiles stood at 3,342 Bcf as of Oct. 14, according to EIA.

“On a weather-adjusted basis, we estimate the market was more than 5 Bcf/d oversupplied for the third straight week,” analysts at Tudor, Pickering, Holt & Co. (TPH) said of the latest EIA print. This level of oversupply is “doing little to support the market on the back of what have been negative revisions” to heating demand expectations, pointing to a “somewhat warm start to winter.”

Even so, it’s too early to “write off winter” at this point in the season, according to TPH.

The $5 range offers “decent downside support ahead of delving more deeply into the winter months, barring continued negative trends in the weather outlook,” the TPH analysts said.

Estimates suggest strong domestic production levels have played a role in the recent run of outsized builds.

Haynesville pipeline samples have increased by around 200 MMcf/d so far in October, lending support to our bullish ArkLaTex supply outlook,” analysts at East Daley Analytics said in a recent research note.

The firm said it expects Haynesville Shale volumes to ramp up by roughly 430 MMcf/d for the September to December time frame.

“In the Northeast, we model an even larger supply ramp of around 922 MMcf/d between September and December,” the East Daley analysts said. “Our forecast is in line with recent winters, which typically see production grow to capture higher regional demand and prices. We anticipate Northeast samples start trending upwards in late October/early November.

Stronger Basis In Western Canada

As for notable regional basis trends during the Oct. 13-19 period, producing hubs in West Texas and Western Canada fared better than the North American market overall.

Perhaps benefitting from the transition into winter heating, or from the steep declines at Henry Hub, NOVA/AECO C November basis strengthened 74.5 cents week/week to end within $1.356 of the national benchmark.

Meanwhile, in the Permian Basin, Waha basis rose 45.4 cents for November to end at minus-$2.579, while El Paso Permian finished at a $2.479 discount to the Hub, a 44.7-cent swing higher week/week.

The latest rig numbers from Enverus showed activity slowing across the United States, including a two-rig decline in the Permian, which dropped its total to 329 rigs for the period ended Oct. 20. 

“While the Gulf Coast and Williston Basin were flat at 119 and 42 rigs, respectively, all other major plays saw weekly declines,” the firm said. 

The Appalachian and Denver Julesburg basins each posted one-rig declines for the period, ending with 56 and 22 rigs, respectively, while the Anadarko Basin dropped four rigs to lower its tally to 80, according to Enverus.

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Natural Gas Forward Prices Plummeting Amid Ample Storage Builds, Mild Temps

Thu, 10/20/2022 - 14:10

Buckling under the weight of one triple-digit shoulder season storage injection after another, natural gas forwards sold off sharply during the Oct. 13-19 trading period, NGI’s Forward Look data show.

Regional forwards price action from coast to coast reflected a market reconsidering the extent of winter upside risks in light of a rapidly shrinking inventory deficit. Fixed prices for November delivery at benchmark Henry Hub sank 97.3 cents to $5.467/MMBtu for the period. 

Numerous Mid-Atlantic and Northeast hubs saw losses of $1-plus. Algonquin Citygate November fixed prices plummeted $2.562 to $7.584. Basis differentials at the New England hub shed $1.589 week/week to end at plus-$2.122.

[Want to know how global LNG demand impacts North American fundamentals? To find out, subscribe to LNG Insight.]

Fixed prices at Transco Zone 5 dropped $1.408 to $6.043 for November delivery. Front-month basis there shed 43.5 cents to end at a 58.1-cent premium to the national benchmark.

Meanwhile, the Oct. 13-19 period saw losses continue to mount for Nymex futures, with a run of huge storage injections, compounded by the absence of any compelling signs of early winter weather, putting bulls on the defensive. 

Wrapping up a fifth straight session in the red, the November Nymex contract dropped 10.4 cents to settle at $5.358 Thursday. 

Futures ‘In Freefall’

Nymex natural gas futures have been “in freefall,” EBW Analytics Group analyst Eli Rubin observed Thursday.

Still, “oversold conditions and seasonal fundamentals continue to offer upside risks over the next 30 to 45 days — if more supportive early-winter weather arrives,” the analyst added.

However, bulls hoping to see that winter weather actually arrive were still waiting Thursday, based on the latest forecasting from NatGasWeather.

“The weather pattern for the start of November is still expected to be near to warmer than normal over most of the U.S. for light national demand,” NatGasWeather said. “The pattern would favor temperatures being stratified from north to south, with highs of 40s to 60s across the northern U.S. and 60s to 80s across the southern U.S.

“It will take much colder weather maps for bearish weather headwinds to end,” the firm added. Mid-November represents “the next best opportunity” for more impressive cold to show up in the outlook.

Thursday saw the Energy Information Administration (EIA) report a 111 Bcf injection into U.S. natural gas stocks during the week ended Oct. 14. That marked the fifth straight triple-digit injection and cut the deficit to the five-year average to 183 Bcf, or minus-5.2%. Lower 48 stockpiles stood at 3,342 Bcf as of Oct. 14, according to EIA.

Estimates suggest strong domestic production levels have played a role in the recent run of outsized builds.

“Haynesville pipeline samples have increased by around 200 MMcf/d so far in October, lending support to our bullish ArkLaTex supply outlook,” analysts at East Daley Analytics said in a recent research note.

The firm said it expects Haynesville Shale volumes to ramp up by roughly 430 MMcf/d for the September to December time frame.

“In the Northeast, we model an even larger supply ramp of around 922 MMcf/d between September and December,” the East Daley analysts said. “Our forecast is in line with recent winters, which typically see production grow to capture higher regional demand and prices. We anticipate Northeast samples start trending upwards in late October/early November.

Stronger Basis In Western Canada

As for notable regional basis trends during the Oct. 13-19 period, producing hubs in West Texas and Western Canada fared better than the North American market overall.

Perhaps benefitting from the transition into winter heating, or from the steep declines at Henry Hub, NOVA/AECO C November basis strengthened 74.5 cents week/week to end within $1.356 of the national benchmark.

Meanwhile, in the Permian Basin, Waha basis rose 45.4 cents for November to end at minus-$2.579, while El Paso Permian finished at a $2.479 discount to the Hub, a 44.7-cent swing higher week/week.

The latest rig numbers from Enverus showed activity slowing across the United States, including a two-rig decline in the Permian, which dropped its total to 329 rigs for the period ended Oct. 20. 

“While the Gulf Coast and Williston Basin were flat at 119 and 42 rigs, respectively, all other major plays saw weekly declines,” the firm said. 

The Appalachian and Denver Julesburg basins each posted one-rig declines for the period, ending with 56 and 22 rigs, respectively, while the Anadarko Basin dropped four rigs to lower its tally to 80, according to Enverus.

The post Natural Gas Forward Prices Plummeting Amid Ample Storage Builds, Mild Temps appeared first on Natural Gas Intelligence

Natural Gas Forwards Tumble as Run of Triple-Digit Injections Allays Winter Supply Worries

Thu, 10/13/2022 - 14:17

A shoulder season slump brought on partly by a run of ample storage builds saw natural gas forwards fall sharply during the Oct. 6-12 trading period, NGI’s Forward Look data show.

With the year-on-five-year-average inventory deficit shrinking fast, forcing a recalibration of the market’s winter risk assessment in the process, November fixed prices at most Lower 48 hubs sold off by 40 cents or more week/week.

Benchmark Henry Hub set the pace, with front month fixed prices dropping 49.5 cents to $6.440/MMBtu during the Oct. 6-12 period.

[Trying to understand where the price of natural gas at the Henry Hub is headed? Learn more about what to watch when analyzing the North American natural gas market with this episode of the Hub & Flow podcast. Listen now.]

Nymex futures similarly experienced downward pressure during the period as the market processed the pricing implications of the outsized storage builds, and as early heating season forecasts failed to impress. The Oct. 6-12 period notably included a 31.3-cent sell-off on Monday (Oct. 10).

Perhaps counterintuitively, however, the front month rallied 30.6 cents to settle at $6.741 Thursday following a fourth straight triple-digit injection reported by the Energy Information Administration (EIA).

Another Whopper Of A Build

The 125 Bcf injection reported for the week ended Oct. 7 outpaced the 82 Bcf five-year average injection but was baked into market expectations, with some analysts even predicting a print in the 130s Bcf.

The latest EIA report marked the fourth straight triple-digit injection this shoulder season. Going back to Sept. 9, prior to the recent run of outsized builds, the deficit to the five-year average stood at minus-354 Bcf, EIA data show. That deficit has shrunk to minus-221 Bcf as of the latest EIA report.

The consecutive triple-digit inventory builds “bolster our view that we will be structurally long supply by 1Q2023,” analysts at East Daley Analytics said in a recent note. 

The hefty injections come as “mild weather has prevailed so far in October” and as maintenance at the Cove Point LNG terminal has removed roughly 0.8 Bcf/d of export demand from the market, according to the firm.

Recent East Daley modeling pointed to an end-October storage level of 3,447 Bcf.

“Storage exits October just 189 Bcf short of the five-year average,” the analysts said. “Much depends on when winter weather arrives, but our model shows storage continues to build into early November and returns to seasonal averages by mid-December.”

The plump injections, along with weakness in liquefied natural gas exports amid the prolonged Freeport outage, contribute to the bearish case for natural gas prices, according to NatGasWeather. 

“To the bullish side, U.S. supplies are still relatively tight at minus-221 Bcf, while power burns are impressive when favorable weather patterns and light winds work in concert,” the firm said. “…Bears will use today’s massive EIA build and improving supplies as reason for lower prices, while bulls have had seemingly endless reasons to buy dips for more than a year, and the risk of a new reason is seemingly just a news release away.”

Cooler Forecasts Ahead?

In terms of the early heating season weather outlook, model runs Thursday were pointing to cooler trends for the Oct. 21-27 time frame, according to NatGasWeather.

The American model added demand midday Thursday after trending cooler overnight and showed “a greater push of cooler Canadian air across the border,” the firm said. However, “it’s not a surprise demand is being added for Oct. 21-27…the greatest risk to weather patterns the next two to three weeks is that the weather models are too warm and will add demand in time on cooler trends over the northern U.S.”

Maxar’s Weather Desk was forecasting an “amplified pattern” during the six- to 10-day time frame, from this coming Tuesday through Oct. 22, one that would deliver warmer temperatures for the West and colder temperatures to the eastern half of the Lower 48.

“Below to much below-normal temperatures are in the Eastern half,” Maxar said. “The coldest conditions follow high pressure out of Canada, with notable lows including Chicago in the low 30s early and Atlanta in the low 40s through mid-period.”

Shrinking New England Premiums

Looking at regional basis dynamics for the Oct. 6-12 period, early winter premiums shrank at a number of New England hubs. 

November basis at Algonquin Citygate eased to plus-$3.711, a 42.7-cent swing lower. Iroquois Zone 2 basis tumbled $1.114 week/week to end at a $1.602 premium to Henry Hub, Forward Look data show.

Meanwhile, Permian Basin hubs saw strengthening front-month basis following signs of being impacted by pipeline disruptions in the week-earlier period.

El Paso Permian basis for November delivery closed the gap on Henry to minus-$2.926, a 22.0 cent gain for the period. Waha similarly gained 16.8 cents week/week to trade $3.033 back of Henry Hub.

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Natural Gas Forwards Mixed, but Market Shows Signs of Shaking Off Shoulder Season Doldrums

Thu, 10/06/2022 - 14:20

With the market preparing to turn its attention to the start of winter heating demand, natural gas forwards at numerous Lower 48 hubs posted modest gains during the Sept. 29-Oct. 5 trading period, NGI’s Forward Look data show. 

Despite a small discount at benchmark Henry Hub, which shed 3.0 cents to $6.935/MMBtu, prices for November delivery climbed at a number of demand hubs. Strengthening in November basis differentials was widespread, including trading locations in the Northeast, Appalachia, Midwest and Rockies.

In New England, Algonquin Citygate basis climbed to plus $4.138 for November delivery, a 16.1-cent swing higher for the period. 

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In the Midwest, Chicago Citygate basis added 14.8 cents for November, ending 37.6 cents back of the national benchmark.

Several Appalachian hubs posted even stronger basis gains, including Eastern Gas South, where November basis rallied 30.2 cents week/week to minus 91.1 cents.

Out west in the Rockies, Cheyenne Hub narrowed the gap to Henry to minus 65.3 cents, an 11.7-cent gain.

Why Are Bulls ‘Buying The Dip’?

Meanwhile, after selling off sharply in recent weeks, Nymex futures showed signs of establishing a shoulder-season bottom during the period, a stretch that notably included a 36.7-cent rally in Tuesday’s session.

Traders shrugged off a hefty triple-digit storage build on Thursday to push the November contract another 4.2 cents higher to $6.972, just shy of the $7 mark. 

Still, the Energy Information Administration’s (EIA) latest report, a whopping 129 Bcf injection for the week ended Sept. 30, served to temper the bullish case. 

The print far outpaced the 87 Bcf five-year average, pushing stockpiles to 3,106 Bcf and cutting the year-on-five-year deficit to minus-7.8% as of Sept. 30, EIA data show. 

In terms of factors potentially putting upward pressure on prices Thursday, “immediate-term gas demand will rise into the weekend, technicals are supportive of extended gains and seasonal upside risks outweigh downside,” according to EBW Analytics Group analyst Eli Rubin.

Storage builds over the next few weeks, though, are poised to shrink the deficit to the five-year average, the analyst said. This coupled with a “lack of cold weather may postpone attempts for Nymex gas to breakout to the upside.”

NatGasWeather said next week’s reported build “could be even larger than today’s, potentially climbing into the 130s Bcf.” With domestic production reaching record highs, “the supply/demand balance isn’t as scary as market participants were looking at a few months ago.”

And yet, “this hasn’t stopped bulls from again buying the dip,” the firm added.

The recent move higher might reflect technical or seasonal factors, or it might reflect “expectations U.S. and global supplies will tighten considerably this winter season,” NatGasWeather said. 

Those holding such supply adequacy concerns “must be looking forward” given that “U.S. supplies will have increased more than 600 Bcf in just six weeks, smashing the previous fall shoulder season injection record,” NatGasWeather added.

Winter Risks For Europe

Looking overseas, with winter approaching in the northern hemisphere, natural gas markets in Europe have reason to feel “snug but by no means cozy,” according to a recent note from Rystad Energy vice president Emily McClain.

Recent damage to the Nord Stream 1 and 2 pipelines has further tightened global natural gas supply, the analyst noted.

“Europe’s gas market participants are now looking to storage injections to safeguard inventories through winter,” McClain said. “However, while European storage levels are shaping up nicely, an early or extended winter could yet send gas stocks sledding downward, pushing prices higher.”

As for Asia, with high storage levels “expected to last through December, most market focus has now shifted to January LNG imports,” McClain added. 

Permian Basis Slips

Meanwhile, looking at regional trends in the domestic market, pipeline disruptions served to pressure Permian Basin forward prices lower during the Sept. 29-Oct. 5 period.

El Paso Permian basis for November delivery tumbled 25.0 cents lower, ending at minus $3.146, while Waha fell 20.6 cents to minus $3.201.

Wood Mackenzie reported a number of pipeline events impacting the Permian region during the period, including a force majeure on the El Paso Natural Gas (EPNG) system on its Line 1300 that was expected to impact roughly 180,000 MMBtu/d of flows.

EPNG was also scheduled to reduce westbound flows on its Line 1100 for maintenance starting Monday and continuing through Oct. 21, according to the firm.

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Natural Gas Forward Curves Retreat as Deadly Ian Rages Across Southeast

Fri, 09/30/2022 - 12:49

With natural gas production remaining stout – even amid temporary shut-ins ahead of Hurricane Ian – and cooler weather leaving its mark on storage inventories, natural gas forward prices continued to fall during the Sept. 22-28 week, according to NGI’s Forward Look.

In the latter part of the period, all attention was on Florida, where Ian packed maximum sustained winds around 150 mph when it made landfall on the southwest coast near Cayo Costa Wednesday afternoon.

The system was downgraded to a tropical storm on Thursday but regained hurricane status by early Friday. Ian made a second landfall as a category 1 hurricane near Georgetown, SC, Friday afternoon.

About one million Florida utility customers remained without power as of Friday afternoon, with more outages likely along Ian’s path. The storm killed more than 20, and the death toll was expected to climb substantially. Thousands of residents were unaccounted for Friday, according to the Florida governor’s office.

The National Hurricane Center (NHC) said on the forecast track, after landfall Ian would move farther inland across eastern South Carolina and central North Carolina Friday night and Saturday. Ian should dissipate over western North Carolina or Virginia late Saturday.

The governors of North and South Carolina, Virginia and Georgia declared states of emergency in their respective states.

Chevron Corp. and BP plc shut in offshore platforms ahead of Ian, but had begun redeploying offshore personnel and restarted production by Thursday. On Friday, early data pointed to output that was back near recent highs.

October forward prices at Florida Gas Zone 3 – which includes transactions east of Compressor Station 8 in East Baton Rouge Parish, LA, through the end of Zone 3 in Santa Rosa County, FL – came off 43.0 cents to average $7.214/MMBtu for the period through Wednesday, according to Forward Look. This compared with a 22.0-cent decline at the Henry Hub, thereby tightening Zone 3’s premium over the benchmark to 33.5 cents, compared to 60.8 cents a week earlier.

A similar basis contraction was seen for the winter strip (November-March), where Zone 3’s premium tumbled to 37.6 cents from 84.2 cents last week. The five-month package settled Wednesday at $7.657. Basis pricing for next summer (April-October) was stable at 51.0 cents, with fixed prices for the strip averaging $5.400.

Weakening in basis pricing also was seen at Transco Zone 5, which begins at the South Carolina/Georgia border and ends at the Maryland/Virginia border just northeast of Station 185. October prices as of Wednesday stood at $4.500, a roughly $2.38 discount to Henry Hub, Forward Look data showed. A week ago, that discount was $1.855. Notably, the winter strip was down by more than 50 cents on the week but still averaged a plump $10.182. The summer 2023 strip averaged only $3.890.

‘Long, Challenging’ Road To Recovery

There is risk for more downside ahead given Ian’s devastating impact and the potentially long recovery ahead.

Florida Power & Light Co. (FPL), the largest electric utility in the state, had restored power to more than one million – or just over 50% – of its customers by Friday morning. As FPL begins assessing the far-reaching damage, the company expects some customers to face prolonged outages because portions of the electric system in Southwest Florida need to be rebuilt rather than repaired.

“Hurricane Ian has forever altered the lives of so many of our fellow Floridians and we recognize the road to recovery will be long and challenging,” said CEO Eric Silagy. “We understand how difficult it is to be without power, and our dedicated men and women will continue to work around the clock until every customer’s electricity is back on. That said, the catastrophic nature of this storm means that we may need to rebuild parts of our system in Southwest Florida, which will take time.”

Duke Energy Florida also had made headway into its restoration efforts, with 650,000 customers restored by Friday afternoon. About 430,000 customers were still without power.

EBW Analytics Group said any delayed restoration of the electric grid in Florida could lead to protracted gas demand destruction lasting multiple weeks, although volumes may be increasingly small. By contrast, near-term demand destruction is set to rise this weekend as Ian’s second landfall extends the cumulative destructive toll. 

Het Shah of Analytics.AI agreed the impact to gas demand may be not as significant had the storm landed at the peak of summer. He noted that Florida natural gas consumption in September is between 4.5-5.0 Bcf/d on average, with power burns making up roughly 90% of the gas consumption.

“We also need to remember that this number is front loaded with more cooling degree days at the beginning of the month. So for the last few days of the month, power burn should be roughly 3.8 Bcf/d with normal temperatures,” Shah said. “Assuming 24% of customers are out of power as of Thursday, that equates to 0.9 Bcf/d at the peak.”

Demand should start to recover as power is restored across Florida, according to Shah. “The question still remains on how long it takes to restore power, so some unknowns remain.”

Warm October Forecast

Beyond storm activity, October is expected to be warmer than normal, offering a catalyst for prices to move lower. Independent forecaster DTN’s outlook favors extensive warming across the central United States, leading to a most-likely forecast of only 223 gas-heating degree days (gHDD), which is 25 gHDDs below 10-year normals.

The bearish near-term outlook enables injections to potentially reach into the 120s Bcf per week, according to EBW. Still, the late-October forecast is subject to extensive variability.

“While it is too early in the season to generate substantial heating demand, weather models have cooled in the Northeast” over the past couple of days, EBW senior analyst Eli Rubin said. “If cold builds and November cracks resistance near $7.14/MMBtu, a notable near-term upswing is favored.”

For now, the projected warmth should continue to chip away at the lingering storage deficit. Recent inventory data suggest production growth and declining demand already have had an impact on stocks.

Adding to the bearish picture, Cove Point LNG is scheduled to go offline over the weekend for planned maintenance. The three-week turnaround would trim 800,000 Mcf/d off demand, and potentially shift this gas into storage.

Storage crunch fears for the upcoming winter are dissipating, with recent storage data showing some improvement in inventories.

The Energy Information Administration (EIA) on Thursday reported the second consecutive triple-digit injection into underground storage. The 103 Bcf build matched the prior week’s build and trimmed the deficit to the five-year average by 26 Bcf week/week.

The latest inventory stat surprised the market once again, with consensus ahead of the EIA report in the low to mid-90s Bcf.

In the comparable week last year, EIA reported an injection of 86 Bcf. The five-year average is 77 Bcf.

Broken down by region, the Midwest led with a 35 Bcf increase to stocks, while the East added 31 Bcf, according to EIA. South Central inventories rose by 23 Bcf, which included an 18 Bcf injection into nonsalt facilities and a 5 Bcf build in salts.

Total working gas in storage as of Sept. 23 was 2,977 Bcf, which is 180 Bcf below year-ago levels and 306 Bcf below the five-year average, EIA said.

Looking ahead to the agency’s next report, for the week ending Sept. 30, Shah said he’s modeling “a really small impact” because of only two days of hurricane impact. This would equate to roughly 2-3 Bcf of demand destruction.

“My current storage estimate is 121 Bcf for the week ending Sept. 30,” Shah said. “For week ending Oct. 6, we are likely to have some demand destruction throughout the week even with crews ready to get power infrastructure back up. So roughly 5-7 Bcf of demand destruction.”

Lingering Winter Supply Concerns

Despite the larger storage builds of late, deficits have proven to be rather sticky, and the forward curve shape reflects an appropriate concern of insufficient winter supply, according to Mobius Risk Group.

The October contract, fell by more than $2 in less than two weeks’ time, held a roughly 74-cent premium to the March contract when it rolled off the board. October also expired at a $1.91 premium to the October 2023 contract.

“With such a dramatic decline in a brief period of time, it is rational to consider what fundamental changes may be prompting the change in flat price,” said Mobius gas analyst Zane Curry. “However, curve shape is often a better indicator of fundamental conditions.”

He noted that the February contract remained almost $1.00 over March, which held a $1.23 premium to April. “Fall demand weakness is a factor, but not necessarily a reason to believe explosive winter upside is off the table.”

Harping down on recent volatility, Curry noted that the winter strip has been under intense pressure of late. As of Wednesday’s close, the strip priced at around $6.940.

“Over the past month the upcoming winter withdrawal season peaked at $9.34, and the round trip since just after the Fourth of July has been prolific,” he said. “…We have seen this tenor travel more than $6.00 in less than three months.”

The November Nymex gas futures contract settled Friday at $6.766, down 10.8 cents from Thursday’s close.

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