DALLAS—Can producers still make money in the Permian Basin despite recent stratospheric movements in land prices that have gone as high as $50,000 an acre? The answer is maybe, according to an analyst who follows the big play.

Darrel Koo, director at Calgary-based RS Energy Group, told a Petroleum Engineers’ Club of Dallas luncheon March 24 that it’s still possible to make money in the Permian even after buying such high-cost leases. The basin’s multi-pay potential is a plus but high drilling and completion costs and lease operating expense (LOE), coupled with a potential shortage of midstream takeaway capacity that could crimp commodity prices, can offset that advantage.

“I get asked a lot if the Permian Basin is overhyped,” Koo said. “But it can make economic sense even at current acreage prices.” His presentation covered the Permian’s geologic and technical aspects—which despite its overall promise can vary widely—and then discussed how its attributes can turn into a profitable return. He said RS Energy relies on “a ground-up approach’ for its data research, using information available from some 100,000 wells in the Lower 48 states. “The rocks really do matter,” he added with a chuckle.

Koo traced drilling trends in the Permian’s two active areas, the Midland Basin and the Delaware Basin, going back to 2012, which show the industry’s move from conventional production that dates back more than 90 years to unconventional plays, such as the Wolfcamp and Spraberry.

There was a “step change” in 2014 as the Permian became truly an unconventional play, he said, “and by 2016 there was a dramatic shift away from conventional wells. Producers are still working to perfect how to drill unconventional wells and across the board, the results end up determined by completion design,” Koo added.

He discussed stratigraphic cross sections of both the Midland and Delaware. The Midland, being the more mature province has been substantially high-graded by producers and, not surprisingly, the highest acreage prices lie atop the basin’s best geology. The Delaware remains in more of an exploratory phase “and is not as well de-risked.” Still, the best Delaware acreage already commands “lofty multiples” on the M&A market.

Koo reviewed charts that compared lateral lengths and volumes of proppant used, pointing out results are “noisy” since producers are still working to find the best combinations—particularly in the Delaware. Midland completions are beginning to fall into a narrower band that may establish benchmarks for completion protocols that yield the most bang-per-buck in both initial production rates and estimated ultimate recovery.

In time, “the Delaware may really eclipse the Midland Basin even though the western side of the Delaware is very gassy,” he said.

Koo showed maps of Midland and Delaware geology that, by RS Energy’s estimates, are profitable at a $55 per barrel (bbl) West Texas Intermediate (WTI) price for oil and $3.50 per thousand cubic feet for natural gas at Henry Hub. A second set of maps showed smaller—but still expansive—regions that can make money at $45 and $3, respectively.

WTI was just below $48/bbl and the Henry Hub natural gas price was at $3.05 on March 27 in the afternoon.

“It looks as though the LOE is not that different between the Midland and Delaware,” he said, adding water-handling costs trend higher in the Delaware. He said the best operators have LOE in the $4-5/bbl range with good all-in expenses in the $10-15/bbl range.

Paul Hart can be reached at pdhart@hartenergy.com.