NEW YORK: US natural gas futures slid about 2% on Tuesday on forecasts for less hot weather over the next two weeks than previously expected, which should cut the amount of gas power generators need to burn to keep air conditioners humming.
Front-month gas futures for September delivery on the New York Mercantile Exchange fell 4.2 cents, or 1.9%, to $2.193 per million British thermal units (mmBtu) at 9:26 a.m. EDT (1326 GMT). On Monday, the contract closed at its highest since July 22.
Another factor that has kept a lid on gas prices all year was the tremendous oversupply of gas in storage.
There was still about 13% more gas in storage than normal for this time of year even though weekly builds, including last week’s rare decline in August, have been smaller than normal in 13 of the past 14 weeks.
The storage decline during the week ended Aug. 9 was the first weekly withdrawal in August since 2006.
In the spot market, pipeline constraints caused next-day gas prices at the Waha hub in the Permian Shale in West Texas to average in negative territory again for a record 27th time this year.
Waha prices first averaged below zero in 2019. It happened 17 times in 2019, six in 2020 and once in 2023.
In Canada, next-day gas prices at the AECO hub in Alberta fell to 36 cents per mmBtu, their lowest since October 2022.
Producers increase and decrease output in reaction to prices, but it usually takes a few months for changes in drilling activity to show up in the production data.
Average monthly spot prices at the US Henry Hub benchmark in Louisiana hit a 12-month high of $3.18 per mmBtu in January before dropping to a 44-month low of $1.72 in February and a 32-year low of $1.49 in March, according to Reuters and federal energy data.
In reaction to that price plunge, producers cut average monthly output from 106.0 billion cubic feet per day (bcfd) in February to 102.7 bcfd in March, 101.5 bcfd in April and a 17-month low of 101.3 bcfd in May, according to federal energy data.
Winter storms at the start of the year caused output to fall from a record 106.3 bcfd in December to 103.6 bcfd in January.
As monthly Henry Hub prices increased to $1.60 per mmBtu in April, $2.12 in May and $2.54 in June, some producers, including EQT and Chesapeake Energy, started to increase their drilling activities, boosting output to 101.0 bcfd in June and 103.4 bcfd in July.
But with average Henry Hub prices back down to $2.08 per mmBtu in July and $2.00 so far in August, analysts said output would likely decline as some producers reduce drilling activities again.
Financial firm LSEG said gas output in the US Lower 48 states slid to an average of 102.3 bcfd so far in August, down from 103.4 bcfd in July.
On a daily basis, LSEG said output was on track to drop by 1.9 bcfd to a preliminary nine-week low of 100.0 bcfd on Tuesday. If correct, that would be the biggest daily decline since April. Analysts, however, noted that preliminary data is often revised later in the day.
With hotter weather expected, LSEG forecast average gas demand in the Lower 48, including exports, will rise from 103.7 bcfd this week to 104.3 bcfd next week. Those forecasts were lower than LSEG’s outlook on Monday.
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