New industry report notes rising natural gas demand, output; futures move above $3 level

An IHS Markit report shows that U.S. natural gas production in the lower 48 states increased by about 1.4% in August, marking the second month in a row where output has outpaced the prior month’s level. It is unclear if improved trends will help Arkansas’ energy sector.

This the first such occurrence dating back to September 2015. Overall, lower 48 U.S. dry-gas production averaged 73 Bcf/d (billion cubic feet of gas/day), IHS Markit said. The report on improved production levels come as natural gas futures moved above the $3 per million British Thermal units for the second time in the past week, touching a 20-month high on Monday (Sept. 26) on strong demand.

Natural-gas futures for October delivery settled up 4.2 cents, or 1.4%, at $2.997 a million British thermal units on the New York Mercantile Exchange in Monday’s session. The October contract expires on Wednesday and options on Tuesday. The more actively traded November contract gained 4.2 cents, or 1.4%, to $3.055 per mmBtu.

In addition, Baker Hughes reported on Friday that the U.S. natural gas rig count rose by three to 92 rigs. In Arkansas, the natural gas rig count has remained at zero in the first three quarters of 2016.

IHS Markit business unit PointLogic Energy tracks U.S. production levels daily across 92 producing areas in the lower 48 states. While August 2016 production levels increased compared to July 2016 levels, overall production is down about 0.7 Bcf/d (or 1%) compared to August 2015.

“Northeast production led the pack again this month, increasing by 0.4 Bcf/d in August compared to July,” said Jack Weixel, vice president for analytics at PointLogic Energy, part of IHS Markit. “Gains in the region were largely centered in the Utica shale basin, which has pushed total Northeast production to its highest level since February of this year.”

August data also shows production in West Texas and the Gulf of Mexico increased compared to July, reflecting greater amounts of associated gas from oil production in the area. South Texas production continues to struggle as drilling activity rotates out of the Eagle Ford formation and into the Permian Basin, driven by producers searching for better margins during this period of lower oil prices.

“The year-over-year decline in natural gas production is largely due to lower associated-gas production, which fell as oil production declined, but there were also pipeline constraints relative to Appalachia production,” said Sam Andrus, senior director of North American natural gas research for IHS Markit. “Also, a warmer-than-normal winter left record storage inventories and reduced summer gas-injection demand by almost 4 Bcf/d.”

However, Andrus added, the warmer-than-normal summer has replaced that demand loss with record gas demand for power generation. “The increased demand for power generation has elevated Henry Hub cash prices in the South and is driving production increases in the pipeline-constrained Appalachia Basin,” he said.

It remains to be seen if increased demand and improved prices will draw drilling crews back to selected day-natural gas plays in the Fayetteville, Haynesville, Utica and Eagle Ford shale developments.

In an investor presentation in August, Fayetteville Shale leader Southwestern Energy said it would will increase production to 500 drilling locations if the price of natural gas moves to $3 per MMbtu. If prices move to $4 or higher, then Southwestern is prepared to adjust its production level up to as many as 4,300 drilling locations.