U.S. natural gas futures eased about 1% on Friday on rising output and forecasts for warmer-than-expected weather over the next two weeks, which should reduce the amount of gas that utilities need to pull from storage to meet heating demand in mid- to late December.
The price decline occurred despite gas volumes flowing to U.S. liquefied natural gas export plants that were on track to hit a 10-month high.
Front-month gas futures NGc1 for January delivery on the New York Mercantile Exchange were down 4.1 cents, or 1.3%, to $3.038 per million British thermal units (mmBtu) at 8:32 a.m. EST (1332 GMT).
For the week, the contract was down about 10% after gaining about 49% over the prior six weeks.
Some analysts have said that winter and the high prices it usually brings could already be over before the season officially starts now that the heavily traded, March-April “widow maker” spread started trading in unusual contango this week, meaning the April contract is priced higher than the March contract.
March is the last month of the winter storage withdrawal season, and April is the first month of the summer storage injection season. Because gas is primarily a winter heating fuel, traders have said summer prices should not trade above winter.
It is possible that gas prices have already hit their 2024 peak in November when they reached $3.56 per mmBtu. Over the past five years, prices hit their yearly highs in January 2023, August 2022, October 2021 and 2020, and January 2019.
In the spot market, cold weather in West Texas helped boost next-day gas prices at the Waha hub NG-WAH-WTX-SNL in the Permian shale, the nation’s biggest oil-producing basin, to their highest level since January.
Wintry weather in New England also boosted next-day gas prices to more than $14 per mmBtu and power to more than $100 per megawatt hour (MWh) in the gas pipeline-constrained six-state region.
That compares with averages in New England of $2.55 per mmBtu for gas and $41 per MWh for power so far this year.
Power and gas prices usually spike in New England when the winter weather turns cold because there is not enough gas pipeline capacity into the six-state region to both fuel power plants and heat homes and businesses. That forces several generators to switch to more expensive oil and liquefied natural gas to fuel power plants.
SUPPLY AND DEMAND
Financial firm LSEG said average gas output in the Lower 48 U.S. states has risen to 102.4 billion cubic feet per day (bcfd) so far in December, up from 101.5 bcfd in November. That compares with a record 105.3 bcfd in December 2023.
Meteorologists projected the weather in the Lower 48 will turn from mostly colder than normal from now through Dec. 7 to mostly warmer than normal from Dec. 8-21.
With warmer weather coming, LSEG forecast average gas demand in the Lower 48, including exports, would drop from 137.3 bcfd this week to 130.6 bcfd next week and 124.6 bcfd in two weeks.
The amount of gas flowing to the seven big operating U.S. LNG export plants has risen to an average of 14.3 bcfd so far in December, up from 13.6 bcfd in November. That compares with a monthly record high of 14.7 bcfd in December 2023.
On a daily basis, LNG feegas was on track to hit a 10-month high of 14.8 bcfd after flows to Cheniere Energy’s LNG.N 4.5-bcfd Sabine Pass plant in Louisiana rose to a seven-month high of 5.1 bcfd.
Source: Reuters (Reporting by Scott DiSavino; Editing by Paul Simao)