Falling internal rates of return for dry gas producers and a faltering rig count could mean slower-than-expected growth in US natural gas production this year as producers adapt to a weaker market outlook in 2023.
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From December to January, percentage returns for many gas producers fell by double digits, tracking a steep decline in Henry Hub gas prices, according to a recent analysis by S&P Global Commodity Insights. Over the same period, the US rig count appears to have peaked, settling into a gradual decline recently – mostly reflecting a drop in rig activity across the smallest, and likely least-profitable, basins.
While continued strength in oil prices could allow the Permian Basin to emerge as a key driver for US gas production this year, previously expected gains in output from the Haynesville now looks less certain.
"Our conversations with producers are pointing to potential lower activity in places like the Haynesville, so we could see those rig counts fall a bit more over the coming weeks," said RBC Capital Markets analyst Scott Hanold in a recent investor note to clients.
With Appalachian Basin gas production in a "steady state," effectively capped by infrastructure constraints, Hanold sees the Permian as the most likely driver for US gas production growth in 2023. Debottlenecking and compression expansions, he says, could allow production there to grow at a robust pace this year, even before new pipeline expansion projects enter service later this year and in 2024.
Over the past six weeks, the Henry Hub 12-month forward gas curve – a key component of S&P Global's internal rate of return calculation – has fallen by nearly $1/MMBtu, or about 23%, to an average $3.35/MMBtu, fueling a sharp decline in many gas producers' profit margins.
S&P Global's IRR estimates are based on a half-cycle analysis, which excludes sunk capital costs like acreage acquisition, seismic and appraisal drilling and federal corporate taxes.
In January, internal rates of return in the Haynesville Shale dipped to an estimated 30%, representing a monthly decline of 22 percentage points from December. In Appalachia, the Marcellus and Utica dry windows saw even steeper declines of 25 percentage points or more, pushing IRRs just below 30% last month. Thanks to stronger liquids prices, margins in the Marcellus and Utica wet windows suffered smaller declines and remained among the top-10 most-profitable basins at 63% and 43%, respectively.
For producers in the Permian Basin, meanwhile, the average 12-month forward curve for WTI edged back over $80/b in January, driving a 4 to 5 percentage-point increase in IRRs for operators in the Delaware Basin, now estimated at 63%, and the Midland Basin, at 55% as of January.
After reaching a three-year high in November, US rig activity also appears to have crested recently.
In January, the US rig count retreated to an average 870 – down from a brief high at just over 900 rigs in mid-November, data from S&P Global shows.
While most of the recent decline has come from the smaller plays, the US' bellwether Permian Basin has also seen rig numbers plateau over the past six weeks with major West Texas producers like ExxonMobil and Chevron now projecting slower growth in 2023 compared with gains achieved last year.
In the Haynesville, now the most-likely candidate for future dry gas production growth, rig activity also appears to have slowed with rig numbers seemingly topped out in the low-80s.
After hitting a winter high at nearly $7/MMBtu, benchmark Henry Hub gas futures prices have all but collapsed under the combined weight of mild January weather, a rising storage surplus, and growing skepticism over the timely return of LNG exports at the long-shuttered Freeport LNG terminal.
With prompt-month futures prices now trading below $2.50/MMBtu, the outlook for a major turnaround in the US gas market this year looks increasingly dim for many.
Assuming those price levels stick around this summer, gas demand could get a boost from an uptick in power burn fueled by more coal-to-gas switching. Market analysts aren't betting on it, though, with many now projecting US gas storage levels to reach an annual high near, or even above, 4 Tcf. Traders are taking a more cautious approach, keeping the NYMEX futures curve in solid contango with winter 2023-2024 contracts still pricing at over $4/MMBtu. For producers caught in the middle, the best approach for now at least, seems to be a cautious wait-and-see mode.