A “very weak demand” picture quickly sapped last week’s momentum for natural gas forward prices, with November contracts plunging an average 26.0 cents for the Sept. 24-30 period, according to NGI’s Forward Look. December on average dropped half as much.
Unlike earlier in September when the 2020-2021 winter strip (November-March) remained largely immune to steep drops at the front of the curve, prices over the past week tumbled an average 13.0 cents. The summer 2021 strip (April-October) also fell, but losses were far less severe at an average 4.0 cents, and smaller declines were seen further out the curve.
With large fluctuations in liquefied natural gas (LNG) demand and moderate weather blanketing a large chunk of the Lower 48, volatility has been rampant along the Nymex futures curve and across other U.S. market hubs.
EBW Analytics Group said the October Nymex contract rolled off the board at $2.101/MMBtu after trading in a “stunning” 53-cent range in the prior two weeks. Volatility approaching this level is typically reserved for mid-winter weather forecast surprises, according to the firm.
“Although November may be more stable, heightened volatility is likely to persist and a wide range of price outcomes remain possible over the next few weeks,” EBW said.
Extremely weak spot prices have plagued the front of the curve, with Henry Hub cash prices at only $1.630 on Wednesday dragging the November Nymex contract down to a $2.527 settle. By Friday, Henry Hub cash fell to $1.335, and the November Nymex contract dropped to $2.438, off 8.9 cents from Thursday’s close.
That makes near-term weather forecasts all the more important given the current storage situation.
On Thursday, the Energy Information Administration (EIA) reported a 76 Bcf injection into storage inventories for the week ending Sept. 25, lifting stocks to 3,756 Bcf. The figure was 471 Bcf above year-ago levels and 405 Bcf above the five-year average, according to EIA.
With less than 50 Bcf needed on average per week to reach 4.0 Tcf by the end of October, the latest EIA stat may seem bearish. However, the figure is reflective of some of the tightest supply/demand balances seen this summer, but not enough yet to avoid containment issues, Bespoke Weather Services said. In particular, stout storage in the South Central region stands to pressure Henry Hub pricing even further.
“Nationally, we are on pace to have enough room, but need to alleviate the surplus especially in salts,” Bespoke said.
South Central inventories rose to 358 Bcf, including a 9 Bcf injection into salt facilities and an 11 Bcf build in nonsalts, according to EIA. Salt capacity is reported to be around 400 Bcf, with four more weeks remaining in the traditional injection season. Builds often continue into November.
Elsewhere across the Lower 48, the Midwest added 24 Bcf into storage, and the East added 21 Bcf, EIA said. Mountain inventories climbed 6 Bcf, and the Pacific rose 4 Bcf.
Genscape Inc. senior natural gas analyst Eric Fell said for the next month, spot prices may be prone to wild swings based on weather forecasts, production and how long the ongoing LNG terminal outages last. Cameron LNG remains offline following Hurricane Laura, while Dominion Cove Point is shut down for planned maintenance.
While cooling degree days still have some impact on demand, October is predominantly a heating degree day month, and “the near-term cold shot is being followed by a warmer-than-normal outlook,” Fell told participants on The Desk’s online platform Enelyst.
Genscape continues to expect a significant ramp-up in LNG feed gas deliveries in October, with nominations to Cameron now at 0.1 Bcf/d after being at zero for most of September. It also expects the return of Cove Point, while nominations to Elba and Freeport recently hit new all-time highs.
NGI’s U.S. LNG Export Tracker showed total feed gas demand continuing to edge higher, reaching close to 6.8 Bcf on Friday, up from the 5.96 Bcf seen at the start of the week but still off September highs.
Going forward, demand is expected to be hypersensitive to gas prices, according to Fell, “but weather is the 800-pound gorilla in the winter.”
Taking a closer look at the Nymex futures curve, Mobius Risk Group said the 59.0-cent spread between November and December futures as of Sept. 30 may require a narrowing of the cash-to-prompt spread, and/or a colder forecast in the next couple of weeks for the December contract to not begin feeling the pressure of late-injection season woes. For consumers, now could be “a period of opportunity” to consider how willing they are to carry open exposure into next year. The firm noted that weather-adjusted balances are shifting quickly to a “drastically undersupplied” backdrop.
“This is not to say consumers are facing a short-lived window of opportunity,” Mobius said. Still, in the next few weeks “they should contemplate the risk/reward of being exposed to monthly or daily pricing in 2021 while the market cleans up current inventory constraint issues.”
Accurately predicting the future direction of prices and the weather are long shots. While it is possible that spot market prices would snap higher, EBW said the more likely outcome is continued near-term declines in the November contract.
That’s largely because weather-driven demand is at its seasonal nadir. Forecaster DTN called for seasonal weather over the eastern United States and continued warmth for the western part of the country in the back half of October.
“Space heating demand is likely to pull nearly even with year-ago levels,” EBW said. “Further, despite the widespread warm anomalies, forecast gas-heating degree days fall only 2 below 30-year normals.”
From a meteorological perspective, much depends on the strength of the Madden-Julian Oscillation, according to DTN. If a strong pattern emerges, it could drive cooler temperatures into the East. If not, a warmer European model may extend warm anomalies to later into the month.
There aren’t many headlines for Permian Basin prices when cash and forward prices are well above zero. Still, a dramatic cash decline that prompted a major sell-off in November forwards, along with pronounced weakness further along the curve, put the spotlight back on the West Texas play in the past few days.
Forward Look data showed Waha November prices tumbling 43.0 cents from Sept. 24-30 to reach $1.341. Cash prices on Wednesday plunged to a 71.0-cent average.
With weather patterns across neighboring regions generally expected to be mild in the coming weeks and extreme summer heat in the West forecast to start fading, demand for Permian gas is rapidly dwindling. AccuWeather said unrelenting heat should continue for the next several days, but “much lower temperatures” along with clouds and even rain could arrive late next week.
“How much and how fast the cooler and wetter pattern evolves will depend on how much the jet stream shifts later next week,” said AccuWeather senior meteorologist Alex Sosnowski.
Meanwhile, there are signs of life emerging in drilling activity. As of Sept. 30, Baker Hughes Co. said the Permian had added four oil rigs for the week to stand at 129, versus 415 a year ago. Though higher associated gas production may be months away, the prospect of added supply amid the currently weak demand environment may have factored into the forward price weakness.
Waha prices for December were down 32.0 cents from Sept. 24-30 to reach $2.416, while the full winter strip dropped 24.0 cents to $2.480, according to Forward Look. The next two seasonal packages were down only 5.0 cents a piece, with summer 2021 averaging $2.460 and winter 2021-2022 averaging $2.610.
Other markets across the Lower 48 recorded price fluctuations that were more in line with benchmark Henry Hub.
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