Recurring winter storms disrupting US natural gas production

Over the last four winters, US natural gas production has been disrupted by more than 15 Bcf/d, according to daily estimates from S&P Global Commodity Insights.

Winter storms Uri (February 2021), Elliott (December 2022) and most recently Heather (January 2024) were the biggest interruptions to US natural gas production over the past four years. Although the impact of these disruptions appeared more muted over the course of a month, winter storms Uri and Elliott still drove declines in monthly average natural gas production of 3-7 Bcf/d.

"Interruptions to natural gas production can occur at any time of the year in the United States and often vary in scale and impact," the US Energy Information Administration said in a March 13 report. "These interruptions can be caused by different factors, including inclement weather, maintenance events, or temporary oversupply conditions that cause a producer to reduce the volume of natural gas moving through a pipeline system."

The report added that severe weather that affects one or more of the major US natural gas-producing regions, such as the Appalachia, Permian and Haynesville regions, can cause noticeable levels of interruption on a national scale. These three regions combined accounted for 66% of US natural gas production in 2023 and 60% in 2022.

Uri, Elliott and Heather affected US natural gas-producing regions in different ways, depending on where the storms hit the hardest and how producers decided to adjust their operations to lessen the impact of cold temperatures.

All three storms had a relatively large impact on the Permian Basin in West Texas and southeastern New Mexico. Some natural gas infrastructure in the Permian is not weatherized, so equipment is exposed fully to low temperatures and moisture in the winter.

Producers often attempt to prevent freeze-offs within the natural gas stream by injecting methanol or other chemicals into the natural gas stream to lower the freezing point of the water in the stream, reducing ice blockages, the EIA said.

Despite various efforts to prevent freeze-offs, severe winter weather still causes issues, and producers generally voluntarily interrupt production to avoid events that might cause damage to equipment or force natural gas in blocked pipes to be vented into the atmosphere. Although a voluntary shutdown stops production for a short time, from a few hours to a few weeks, the natural gas production is not completely lost. The natural gas in temporarily shut-in wells remains in the wells until production begins again. Immediately after restarting production, these wells often produce more natural gas than before the shutdown because of a temporary pressure build up.

Total feedgas deliveries to major US liquefaction terminals saw a sharp decline following Heather, averaging 13.25 Bcf/d during the week ended Jan. 16, down 1.42 Bcf/d on the week, S&P Global data showed. Flows continued to fall, with the average reaching a near four-month low during the week ended Jan. 23 at 13.16 Bcf/d.

Utilization at major LNG liquefaction terminals in the US has remained below the weekly average of 14 Bcf/d since then, due in part to an outage at Freeport LNG, whose train 3 has been offline since January due to an electrical issue which impacted the liquefaction unit. The motor repair work was initially expected to last approximately one month, but the timeline was later extended by about another two weeks.

Feedgas flows to Freeport have remained well below levels seen in early January, averaging 857 MMcf/d during the week ended March 12, compared with an average of 2.02 Bcf/d during the week ended Jan. 9, S&P Global data showed.

Despite the impact from the last four winters, the global gas and LNG markets still remain comfortably stocked. Milder temperatures have been coupled with ample supply to keep the gas and LNG markets across the globe relatively weak.

The US Energy Information Administration slashed its forecast for Henry Hub spot natural gas prices by more than 40 cents for the first and second quarters of 2024 March 12, pointing to higher-than-average storage stocks following a mild winter.

Platts, part of S&P Global, assessed the Gulf Coast Marker for US FOB cargoes loading 30-60 days forward as unchanged on the day at $6.70/MMBtu March 12.