Denver — Stronger natural gas and crude prices have boosted internal rates of return across most US shale plays, but major operators have signified their intent to maintain level production moving forward despite the spike.
Receive daily email alerts, subscriber notes & personalize your experience.Register Now
The average 12-month forward curve for the US domestic crude price benchmark, WTI, sharply increased to $52/b in January as OPEC agreed to reduce production by 1 million b/d through March. With WTI back above the $50/b mark, crude-focused plays saw another strong month of improvement in wellhead internal rate of return.
The Permian Delaware, Midland, Bakken, Denver-Julesburg, Eagle Ford, SCOOP/STACK and Powder River all shifted above the 10% cost of capital mark, suggesting new wells coming online should be able to realize cash flow neutrality at a minimum, according to S&P Global Platts Analytics.
Platts Analytics IRRs are based on a half-cycle, after-federal corporate tax analysis, which excludes sunk costs such as acreage acquisition, seismic and appraisal drilling.
For gas-directed plays, the Henry Hub average 12-month forward curve settled at $2.68/MMBtu for January. At this price point, only the Utica-Dry and Haynesville plays are bringing wells online with an IRR of over 10%, as regional gas differentials continue to hurt the Northeast's ability to price gas at all close to Henry Hub.
Dominion-South and Columbia Gas-App. Hubs, which are associated with the Marcellus and Utica, were discounted on average by 67 cents/MMBtu and 49 cents/MMBtu to the Haynesville's Henry Hub price point for the month of January, hurting operator's ability to produce strong revenue results on their new horizontal wells.
The jump in crude prices has also closed the profitability gap between the wet and dry pockets of West Virginia and Pennsylvania as IRRs for the Marcellus-Wet and Marcellus-Dry both hovered around 7.5% for January. This suggests more rigs may be reallocated to West Virginia-Wet and Pennsylvania-Southwest Wet plays for 2021, assuming crude prices remain strong, according to Platts Analytics.
The Delaware continues to lead all US shale plays as a stronger Waha price has boosted most of the region's robust wellhead gas revenue, pushing this region's IRRs into the 25% area. With IRRs of 20% to 30%, operators will likely start to increase their completion activity quickly in the near term, according to Platts Analytics. Hydraulic fracturing of the approximately 200 drilled-but-uncompleted wells will help Texas and New Mexico operators stabilize the region's production after the reduction in activity experienced in 2020.
Other crude plays such as the Midland, Bakken and Eagle Ford are each obtaining 20% IRRs as a solid gas environment with over $50/b oil will drive operators to bring on frack crews in the short term with these favorable economic conditions. While a $50/b WTI environment provides respectable returns for most of the crude shale plays at a theoretical asset level, it would likely take $60/b WTI to change the recovery trajectory of drilling and completion activity in US shale.
Many operators continue to be rewarded for paying down debt and returning cash to shareholders as positive cash flow results continue to dominate quarterly conference calls for most exploration and production companies.
For example, Northeast producer Cabot Oil & Gas announced its 2021 guidance on Feb. 4, highlighting the company's plan to remain in maintenance mode this year, with minimal production growth. Cabot will continue to focus on capital discipline and generating free cash flow, maintaining production levels relatively flat year over year.
Cabot expects declines in production this quarter to be driven by reduced operating activity and capital spending in the second half of 2020, a move that may likely ripple amongst several regional operators over the balance of 2021.