Will Summer Temps Move U.S. Natural Gas Demand? Wind, Solar May Have a Word

By Chris Newman

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Published in: Daily Gas Price Index Filed under:

Natural gas production cuts have stabilized the fuel’s prices by countering weak Lower 48 winter demand, turning the market’s attention to the next big levers for fundamentals: the upcoming summer and added wind and solar capacity.

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Prompt-month New York Mercantile Exchange futures, trading above the $1.800 level at the start of April, had settled as low as $1.576/MMBtu in late February before several big natural gas heavies, Chesapeake Energy Corp. and EQT Corp., said they were cutting output.

“We saw really big gains, not only at Henry Hub, but at a lot of the pricing locations throughout the United States,” said NGI's Leticia Gonzales, price and markets editor, at a recent Intercontinental Exchange Inc. (ICE) event in Calgary. 

Criterion Research LLC’s James Bevan, vice president of research, also spoke at the event. “Production seems like it's fixed itself for the most part, and power demand is just the biggest risk by far going into the summer months,” he said.

On Feb. 21, the day of Chesapeake’s news, NGI’s Henry Hub spot price jumped 9.5 cents to $1.600. That strength rolled through the forward curve, with NGI’s Forward Look showing Henry Hub gained 20-30 cents for summer months, Gonzales noted.

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When CNX Resources Corp. joined the other gas producers by announcing it too would cut output, prices were more muted. “Part of that is that the near-term outlook is so incredibly bearish,” Gonzales said. “We’re in the final stages of what was a record warm winter, which has had a devastating impact on cash prices.”

Weak near-term fundamentals like slower U.S. LNG exports have also weighed, as has a massive storage surplus, according to Gonzales. Lower 48 gas inventories stood at a 41% surplus to the five-year average after a storage withdrawal of 36 Bcf was reported for the week ended March 22.

Cuts Tally

Appalachian Basin gas production dropped from around 36 Bcf/d to between 33.5-34 Bcf/d in February and has held within that lower bound into late March, according to Bevan. EQT cut about 1 Bcf/d of production, while other companies in Appalachia have accounted for around 1-1.5 Bcf/d of the region’s curtailments, according to Bevan.

“Whether you want to call that maintenance or production curtailments, or just seasonal drops, it did help balance things a little bit as far as production goes,” Bevan said. EQT said it would reevaluate market conditions at the end of March, so one question is whether the company would extend its 1 Bcf/d of curtailments into April, according to Bevan.

Haynesville Shale output has come down from 16.5 Bcf/d in mid-February to just over 15 Bcf/d through March 25, according to Bevan. One concern that Criterion analysts had going into 2024 was the possibility of additional volumes flowing on DT Midstream Inc.’s Louisiana Energy Access Project, or LEAP, after it completed a Phase 2 expansion in January.

LEAP’s deliveries to the Gillis Hub “never went up as soon as that phase came online,” Bevan said. “So that presented a little bit more comfort that production is actually starting to drop off in the Haynesville Shale.”

Meanwhile, Permian Basin outtake pipeline capacity is capped until more pipeline capacity is back online, Bevan said. Permian output recently has been pinched by pipeline maintenance. Matterhorn Express Pipeline would add 2.5 Bcf/d of capacity when it ramps up later this year, he said.

Volatility Ripples

If U.S. liquefied natural gas export capacity doubles as expected from today’s 14 Bcf/d nameplate capacity by 2028, the price ramifications could go well beyond the Gulf Coast, according to Gonzales. 

Basis pricing for the Permian’s benchmark hub Waha showed April 2024 pricing at minus $1.691, a discount that narrows to minus 17.1 cents for January 2025 pricing, according to Forward Look as of March 27.

California’s SoCal Citygate also showed an impact, according to Gonzales. The hub supplies a region with growing demand supplied in part by the Permian. “Anytime you have all this gas demand that is coming in the form of LNG making its way to the Gulf Coast, then you’re obviously taking away gas that can move to other markets,” she said.

SoCal forward basis prices at 29.4 cents for April 2024 jump to a $3.979 premium for January 2025 against the Henry Hub benchmark, according to Forward Look

“SoCal and the entire western region is where we’ve been seeing a lot of increased volatility as these LNG exports have come online,” Gonzales said. “Growing LNG demand doesn’t have just ramifications for Gulf Coast markets, but for a lot of other markets as well.”

Risky Summer Outlook

While production “seems like it’s figuring itself out…the next concern is power demand throughout the summer months,” Bevan said.

“It’s great to assume that we’re going to have another extremely hot summer, just like we did last year, and power burns go through the roof. There is a risk to that, though, with all the wind and solar coming online,” he noted.

The U.S. Energy Information Administration (EIA) estimated that roughly 6 GW of wind and 35 GW of wind generation are due to come online this year, Bevan said. Those estimates may be overestimated but are a rough starting point to model, he said. New wind and solar capacity would equate to about 1.3 Bcf/d of gas-generated power if the additions were to run at capacity, he added.

Criterion has a base case of about a 37.7 Bcf/d power burn through the injection season. In that case, Lower 48 gas inventories could end at around 3.8 to 3.9 Tcf, “which is a pretty reasonable place to end up,” Bevan said. However, a higher amount of wind and solar generation could push end-of-season gas storage levels to 4.1 Tcf or higher.

“There’s a lot of bearish risk. That just seems to be the gist of what is happening right now,” Bevan said. “There’s not a lot of things where you look at the news and you’re like, ‘Oh, that’s a really bullish thing.’ It seems like the market keeps getting pummeled,” as when the Freeport LNG outages happened.

NGI’s Henry Hub forward prices do not point to sustained pricing above the $3 level until summer 2025. Even with the new LNG capacity coming online, the forward curve does not show a tremendous difference in variation, Gonzales said. Henry Hub forward prices rise above $3.000 in late 2024, according to the NGI forward prices.

“Prices are generally in the $3 to $4 range in 2025, and it’s not until you get way further out on the curve that you start flirting with that $5 threshold, and that’s really just in the peak winter season,” Gonzales said.

EIA in its latest Short-Term Energy Outlook modeled an average Henry Hub price of $2.27/MMBtu for 2024 and an average of $2.94 for 2025.

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Chris Newman

Chris Newman joined NGI in October 2023. He worked 18 years at Argus Media, starting in 2004 in Washington, D.C., where he covered U.S. thermal/coking coal markets and rail transportation. In 2014, he moved to Singapore to help lead Argus’ coverage of steel and its raw material feedstocks. A graduate of the University of Virginia, Chris returned to his native Virginia in 2021.