Natural-gas prices have dropped more than 65% since mid-December and this week hit their lowest level since 2020’s pandemic lockdown, leading producers to throttle back drilling in a dramatic turn in the market for the heating and power-generation fuel.
Expensive natural gas was a major contributor to inflation over the past two years, pushing up the price of electricity and staying warm as well as manufacturing costs for fertilizer, steel, glass, aluminum, plastic and cardboard.
Now, producers are trying to avoid swamping the market while traders and analysts are calculating how low prices will need to fall to spur the right mix of curtailments and demand to balance the market.
American bill payers should benefit, especially once air-conditioning season starts. Lower natural-gas prices would also bolster companies’ bottom lines, which have been eroded by rising input costs. Profit margins among companies in the S&P 500 index are on track to decline for the sixth straight quarter, threatening the rebound in stocks.
Natural-gas futures for March delivery ended Wednesday at $2.174 per million British thermal units, down 53% from a year ago. In early trading, futures dipped below $2, a threshold that has rarely been breached over the past 20 years.
Production normally can’t fulfill demand in winter, so gas is drawn-out of storage facilities to make up for the shortfall. During an especially mild stretch at the start of this year, production outstripped demand and the volume of gas in storage rose, the only instance of a January inventory build in weekly Energy Information Administration data going back to the start of 2010.
The market currently is oversupplied by about 5 billion cubic feet a day and without producers choking back output, U.S. inventories would swell beyond storage capacity before next winter, said Ryan Smith, vice president of consulting at energy-data firm East Daley Analytics. “Prices might still have a little bit of downside risk,” he said.
Analysts and energy executives say that producers must dial back output to buoy prices. They expect drilling activity to decline most sharply in the Haynesville Shale, where break-even production costs are higher than in Appalachia’s Marcellus Shale, and in West Texas, where gas is an abundant byproduct of oil drilling.
The Haynesville lies beneath East Texas and northern Louisiana. Drilling there has boomed since the lockdown to supply liquefied natural gas export terminals and chemical makers along the Gulf Coast. Already, though, big producers in the region are parking drilling rigs.
“The prudent step is to show capital discipline and reduce our activity levels,” Chief Executive Nick Dell’Osso said. “Given the price set up that’s in front of us now, we’re going to expect to curtail some gas in the shoulder season.”
Overall, producers received less than half as many drilling permits for the Haynesville and Marcellus shales in January as they did in December, according to Evercore ISI analysts.
Bank of America analysts told clients this week that they believe prices have bottomed and will average $2.45 per million BTUs during the first half of the year before rising in the second half. One risk to their outlook, they wrote, is that producers, flush from last year, might be better able to weather low prices and slow to cut back.
Demand should climb in the coming weeks as Freeport LNG restarts the Texas export facility that has been down since a June fire. The outage of one of the country’s largest gas export terminals has left a lot of gas in the domestic market that would have been shipped abroad. But big price gains aren’t expected until next year when a batch of new export terminals begin to open, boosting U.S. export capacity by 40%.
“The consensus call is gas is dead until late 2024, early 2025,” Truist Securities analyst Neal Dingmann said. “It’s hard to point to anything different until the large LNG projects start to come in late next year.”