Natural gas forward markets rebounded sharply for the trading period ending Aug. 4 as widespread sweltering heat set to return sounded the alarm once again that U.S. storage inventories are on pace to fall uncomfortably short ahead of winter.

September forward prices averaged 20.0 cents higher for the July 29-Aug. 4 period, according to NGI’s Forward Look. Gains were stout across the curve, with forward prices for the upcoming winter (November 2021-March 2022) averaging 14.0 cents higher for the period and the summer 2022 strip (April-October) averaging 10.0 cents higher.

East Coast markets put up much heftier gains as the typical response by exploration and production (E&P) companies to higher prices appears to not be in the cards this time around. More than halfway through second quarter 2021 earnings results, most public E&Ps are remaining disciplined, shunning higher output and instead shoring up balance sheets.

For example, BP plc’s Lower 48 unit BPX reported a year/year decline in 2Q2021 production. Total output fell to 273,000 boe/d from 262,000 boe/d in 2Q2029. Natural gas production declined to 971 MMcf/d from 1.38 Bcf/d.

That said, BP executives offered a robust outlook for natural gas, largely because of strong export demand. CEO Bernard Looney said higher gas prices followed a cold winter in Europe and the United States, along with “unusually low storage levels.” In addition, U.S. liquefied natural gas (LNG) exports, particularly to Asia, now are “maxed out” as hot weather continues to blast the country.

“A whole number of factors…have come together to cause gas prices to be strong,” Looney said. “Whether they remain strong or not remains to be seen.”

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Meanwhile, EQT Corp., the largest natural gas producer in the United States, plans to run a maintenance program on the Marcellus Shale assets it recently acquired from Alta Resources Development LLC. Production is increasing because of the tie-up, but management indicated it won’t chase short-term gains because of the recent, stronger price signals.

As such, much stronger pricing is being reflected for the production that is expected to be online when winter comes around. Eastern Gas South September prices rocketed 69.0 cents higher from July 29-Aug. 4, averaging $3.160, according to Forward Look. Similarly strong gains were seen for the balance of summer (September-October), while the winter strip jumped 23.0 cents to $3.640. Summer 2022 prices were up 14.0 cents to $2.460.

Downstream in the Northeast, Transco Zone 6 non-NY September prices shot up 58.0 cents from July 29-Aug. 4, averaging $3.192, Forward Look data showed. The balance of summer climbed 56.0 cents to $3.140, and the winter tacked on 16.0 cents to $5.260. Summer 2022 averaged $2.610, up 12.0 cents.

EBW Analytics Group LLC said natural gas output has remained subdued, with the latest monthly production report from the Energy Information Administration (EIA) showing few notable surprises as producers shift into maintenance mode. While output grew less than one-tenth of 1 Bcf/d during May, dry gas production remained within 0.75 Bcf/d of last December and more than 2.2 Bcf/d below pre-pandemic levels.

“The market appears to be increasingly recognizing that new production to bail out very tight core fundamentals appears unlikely, leading to continued upward momentum for natural gas,” EBW analysts said.

Meanwhile, the EBW team pointed out that any hopes for production to jump once the Whistler Pipeline began operations have been dashed. Project sponsor MPLX LP announced Monday (Aug. 2) that the 2.0 Bcf/d Permian Basin pipeline has been in service since July 1, suggesting concerns for a large production gain with Whistler’s commencement were misplaced. Instead, while the first-of-month pipeline nominations often decline, early August supply appears particularly weak.

“If production declines during August — as is eminently plausible — apparent shortfalls in the forward storage trajectory may become glaringly apparent and drive natural gas to new highs,” EBW analysts said.

Drilling analytics firm Enverus on Thursday provided some insight into current drilling activity levels. The company said Appalachia and the Permian both tied for the biggest week/week drop in the rig count, losing four rigs each in the week ending Aug. 4. In Appalachia, five companies each dropped their only rig in the region, while only one added a rig. Ascent Resources Utica Holdings LLC and Southwestern Energy Co. continue to lead the region with four rigs each.

In the Permian, Pioneer Natural Resources Co. dropped from 27 rigs to 23, and Diamondback Energy Inc. dropped from nine to seven. Matador Resources Co. was the only company to add more than one rig over the week, doubling its count to four.

As for Permian gas prices, gains were generally in line with Henry Hub. Waha September forward prices climbed 12.0 cents from July 30-Aug. 4 to reach $3.934, as did the balance of summer, which averaged $3.910. Waha’s winter strip averaged 13 cents higher at $4.180, while the summer 2022 package was up 13.0 cents to $3.280.

Meanwhile, EBW said there are added risks ahead as LNG feed gas demand is set to ramp higher in the coming months. The sixth production unit at the Sabine Pass LNG facility and Venture Global Inc.’s Calcasieu Pass LNG facility are expected to come online next year. Cheniere Inc. on Thursday said construction of Sabine Pass Train 6 is 90% complete, and early commissioning activities have begun with the first fuel gas introduced in July. Bloomberg in the spring reported that Calcasieu Pass was offering cargoes for loading between October and December 2022.

How this added structural demand impacts supply is already causing concern in the market. On Thursday, after the EIA released its weekly storage data, participants on The Desk’s online energy chat Enelyst said the seasonal records that gas prices are setting overseas would mean U.S. prices would have to take another step higher if storage levels don’t improve.

The EIA said inventories for the week ending July 30 rose by only 13 Bcf, or 1 Bcf shy of the lowest estimate ahead of the report. On Wednesday, a Wall Street Journal poll produced estimates ranging from an increase of 14 Bcf to as much as 34 Bcf. Reuters polled 17 analysts, whose estimates were in the same range with a median injection of 21 Bcf. A survey by Bloomberg had a median injection of 18 Bcf, and NGI modeled a 17 Bcf build.

The EIA recorded a 32 Bcf injection in the same period last year, and the five-year average is 30 Bcf.

Bespoke Weather Services said the EIA’s 13 Bcf injection continued to reflect an “uncomfortably tight supply/demand balance” and kept the market on pace for end-of-season inventories below 3,400 Bcf.

One Enelyst participant said he didn’t think 3.4 Tcf was “the new norm” and expects the market to take “another leg higher” if storage does wind up at that level at the end of October. However, he was unsure of what the price might be. “Given European prices, it’s a random number at this point. It could be $5.00 or $6.00. What’s the difference?”

Given rampant export demand, and near triple-digit temperatures across the South Central region, local inventories declined at both salt and nonsalt facilities. The EIA said salt stocks fell by 19 Bcf, and nonsalt dropped by 3 Bcf.

Another Enelyst participant noted that the 19 Bcf withdrawal in the South Central salt inventories was the largest third quarter salt draw of all time.

The nonsalt draw also surprised. “I didn’t see that draw from nonsalt coming,” said Enelyst managing director Het Shah.

Elsewhere across the country, Pacific stocks also slipped by 2 Bcf amid ongoing heat and low hydroelectric power in the region. East inventories climbed 21 Bcf, and the Midwest added 17 Bcf.

Total working gas in storage as of July 30 was 2,727 Bcf, which is 542 Bcf below year-ago levels and 185 Bcf below the five-year average, according to EIA.

“All in all, the backdrop remains quite supportive, given where current levels of supply sit,” Bespoke said.