US natgas prices edge up 1% on contract expiry, higher demand

U.S. natural gas futures edged up about 1% on Wednesday in volatile trade ahead of the expiration of the September contract as relatively low gas prices in recent weeks prompted power generators to burn more gas and less coal to produce electricity.

That price increase came despite forecasts for less hot weather over the next two weeks than previously expected and the shutdown of the Freeport LNG export plant in Texas for what should be a brief outage following the unexpected activation of a fire suppression system during routine maintenance.

Less hot weather means power generators do not need to burn as much gas to keep air conditioners humming. The shutdown of an LNG plant, meanwhile, will reduce the amount of gas flowing to the plant to be turned into LNG for export.

Energy analysts also noted that the tremendous oversupply of gas in storage for this time of year has kept a lid on prices all year.

There was still about 12% more gas in storage than normal even though weekly builds, including a rare decline during one week in August, have been smaller than normal in 13 of the past 14 weeks.

On its last day as the front-month, gas futures NG1! for September delivery on the New York Mercantile Exchange rose 2.6 cents, or 1.4%, to settle at $1.930 per million British thermal units (mmBtu). On Tuesday, the contract closed at its lowest since April 26.

That was the first price increase in seven days and pushed the contract out of technically oversold territory.

Futures for October (NGV24), which will soon be the front-month, gained about 1% to settle at $2.097 per mmBtu.

In the spot market, pipeline constraints caused next-day gas prices at the Waha hub (NG-WAH-WTX-SNL) in the Permian Shale in West Texas to average in negative territory again for a record 30th time this year.

Waha prices first averaged below zero in 2019. It happened 17 times in 2019, six in 2020 and once in 2023.

SUPPLY AND DEMAND

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 U.S. Henry Hub benchmark (NG-W-HH-SNL) 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.

As monthly Henry Hub spot prices increased to $1.60 per mmBtu in April, $2.12 in May, and $2.54 in June, some producers, including EQT EQT and Chesapeake Energy (CHK.O), started to increase drilling activities, boosting output to 101.0 bcfd in June and 103.4 bcfd in July.

But with average spot Henry Hub prices back down to $2.08 per mmBtu in July and $2.01 so far in August, analysts said output would likely decline in coming months as some producers reduce drilling activities again.

Financial firm LSEG said gas output in the Lower 48 U.S. states slid to an average of 102.4 bcfd so far in August, down from 103.4 bcfd in July.

Meteorologists forecast weather across the country would remain mostly hotter than normal through Sept. 12. Energy traders, however, noted that hot weather at the start of September would only average around 78 degrees F (25.6 Celsius), versus around 83 F (28.3 C) at the start of August.

LSEG forecast average gas demand in the Lower 48, including exports, will slide from 105.8 bcfd this week to 102.9 bcfd next week. Those forecasts were higher than LSEG's outlook on Tuesday.