Tudor, Pickering Reveals Differing Costs of Various Shale Plays

by Deon Daugherty, Senior Editor

As exploration and production companies continue counting their quarters and contemplating the future, we take a look at a piece of Tudor Pickering Holt & Co research from April that may help us anticipate where the shale action will happen next year.

While these price points are from the spring, they provide a snapshot of what operators are confronting when they decide where to spend their drilling capital.

Given the price required for a 10 percent after tax rate of return (ATROR) with a 20 percent cost savings, TPH found this spring that among the least expensive basins to drill – between $35 and $40 per barrel to turn a reasonable profit – are in particular areas of the Eagle Ford; the Bakken; and the Three Forks Sanish, which is in the upper part of the Bakken. Ironically, depending on where you’re drilling in the Eagle Ford and the Bakken, the oil price to turn a profit grew more step, well into the $60-plus barrel range.

The Permian Basin, an expansive play that includes areas described as “Midland” and “Delaware,” runs the gamut of prices needed to be profitable. In the Midland Wolfcamp Tiers 1 and 2 on the east side of the Permian, and on the western Delaware side, $50 oil was needed to make a profit. The Midland Wolfberry region was less developed and needed a minimum $60 barrel of oil.

The Mississippi Lime, Eagle Ford Tier 3 and Uinta Basins were lumped closely together in the $65 per barrel range. And topping $70 per barrel, the Tuscaloosa Marine Shale required the highest oil prices to turn a profit.

No doubt, there are a variety of factors that figure into the cost benefit analysis of a particular play. TPH associate Jeoffrey Lambujon told Rigzone that on the capital expenditures (CAPEX) side, operators must consider the depth of which to drill, the life cycle of the play, completion recipes, days required to drill and contracts.

In the heady days of 2014, Lambujon said that when drillers were considering their budgets, one of the major themes was to increase the well cost as a result of pumping more frack fluid to increase production.

“Even with the downturn ongoing, some operators are still increasing the amount of fluids in their wells as the incremental cost may be outweighed by incremental productivity,” he said. “Those increased costs are offset by efficiencies, [such as] crews drilling the wells faster, the ability to share common facilities as infrastructure, such as roads or storage units, or general fine turning of the processes.”

Lambujon said the research team will revisit the basin costs in April 2016, as it reflects the relative economics across the different plays.

“In general, an approximate 10 percent reduction in well costs equates to about a $5 barrel reduction in the breakeven price,” he said.


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