Natural gas forwards prices were mixed, with mostly modest gains during the July 28-Aug. 3 trading period amid forecasts for minor easing in the intensity of summer heat through the middle of August, NGI’s Forward Look data show.

Southeast Prices

Fixed price trading for September delivery at benchmark Henry Hub climbed 13 cents week/week to $8.135/MMBtu. That established the baseline for small gains in fixed prices at a majority of Lower 48 hubs during the period, though losses were scattered across eastern and southern hubs.

NatGasWeather said strong upper high pressure with peak temperatures in 90s-100s will define conditions through mid-August for most of the country, but weather systems with showers were expected to track across the Upper Midwest and to the East beginning this weekend. This could provide some pockets of respite. Toward the end of next week, cooler exceptions were forecast for the Great Lakes, Ohio Valley and Northeast, with highs in the 70s and 80s.

The outlook remains bullish overall, the firm said, though not as much as earlier in the summer. “It will still be hot over most of the interior U.S.” through the week ahead “for regionally strong demand, just not as impressive without the East participating.”

With enough hints of moderating temperatures in northern and eastern regions, forwards prices steadied or even declined in regions where they had been propelled to lofty highs following persistently strong heat in June and July.

Additionally, as EWB Analytics Group noted, production in late July and early this month hovered near a 2022 high around 97 Bcf/d at times, creating the potential for greater supply heading into the fall months.

“Relenting heat” and “a flash of surging production” could weigh on natural gas price sentiment, creating an “August hangover” after a surge in July, said EBW’s Eli Rubin, senior analyst.

The most notable pullback in forwards prices could be found in the Southeast, where Transco Zone 4 September front-month fixed fell 71.0 cents to $9.763, and Florida Gas Zone 3 shed $1.020 for the period to $9.196.

Still, prices held strong overall by historical standards. Chicago Citygate was up 10.0 cents to about $7.948, while SoCal Border Avg. advanced 9.0 cents to $8.586 and Iroquois Zone 2 was up 14.0 cents to $7.890.

Forward Look data also showed that the U.S. benchmark’s winter strip (November-March) held onto solid fixed prices, with Henry Hub up 10 cents to about $7.978.

With few exceptions, including hubs in southern markets where prices were already lofty, winter strip fixed prices were ahead across most of the Lower 48. Agua Dulce was up 10.0 cents to $7.981, and Trunkline Zone 1A was ahead 13.0 cents to $7.844.

Futures Fluctuate

After spiking 56.0 cents in Wednesday’s session, the September Nymex contract shed 14.4 cents to $8.122/MMBtu on Thursday.

Markets lost momentum after the Energy Information Administration (EIA) posted a plump 41 Bcf injection into natural gas storage for the week ended July 29.

The print exceeded the highest of analyst estimates and appeared to reflect recent production increases. The latest injection compared with the year-earlier build of 16 Bcf and a five-year average increase of 35 Bcf, according to EIA.

Production “is difficult to predict, but certainly we’ve had enough demand and enough upward pressure on prices to justify more from producers,” StoneX Financial Inc.’s Thomas Saal, senior vice president of energy, told NGI.

Additionally, during the latest EIA inventory period, a train at the Sabine Pass LNG terminal was out of commission, providing more gas for injection.

Still, Saal said, supply/demand balances are “very tight” and bulls may have plenty of room to roam through the summer if output falters.

Total working gas in storage rose to 2,457 Bcf, though it was 268 Bcf below year-earlier levels and 337 Bcf below the five-year average.

“Compared to degree days and normal seasonality, the reported 41 Bcf injection appears loose/bearish by approximately 1.9 Bcf/d versus the prior five-year average,” Wood Mackenzie analyst Eric Fell said of the EIA print. The period saw an above-average injection rate “despite degree days that were also above average for the week.”

In addition to production, Fell cited a “noticeable increase in coal generation” that “drove gas burns lower versus the prior week.”

Futures traded in a narrow range to close out the week. The prompt inched down 5.8 cents day/day to settle at $8.064/MMBtu on Friday.

Freeport’s Return?

The bearish inventory miss offset news Wednesday of a potential October return to full service for the 2.0 Bcf/d Freeport liquefied natural gas terminal after a consent agreement was reached with the Pipeline and Hazardous Materials Safety Administration. The LNG plant was forced offline in June after an explosion and fire.

Since then, Freeport gas once destined for export has been consumed domestically, helping the market meet robust cooling demand through the summer to date. Should Freeport supplies return to the export market this fall, it would mark a bullish change for futures as the peak winter demand season looms.

Freeport expects to resume partial service by early October and return three liquefaction trains, two storage tanks and one loading dock to operations. That would allow it to produce 2 Bcf/d of LNG, or enough to meet its existing long-term sales contracts.

Rystad Energy analyst Karolina Siemieniuk noted that European demand for American LNG is elevated and expected to remain so through the winter. Countries across the continent are trying to reduce dependence on Russian gas in protest of the Kremlin’s invasion of Ukraine. They are looking for U.S. LNG to help fill the void long term.

Europe is sure to soak up the Freeport supplies, Siemieniuk said, and futures prices, while volatile, are “are likely to stay elevated” this year as a result.