As of fall 2012, natural gas prices are in the basement, liquids prices just one floor up, and oil continues to command the penthouse view. These varying commodity prices have sometimes obvious, sometimes subtle effects on the economics of oil and gas plays, and investors must try to assess these and other factors when analyzing plays’ relative strengths.
In recent reports, Global Hunter Securities’ analyst Mike Kelly tackled some of the questions investors most frequently ask about comparative breakevens, rates of return and general economics of the “mounting list of oil/liquids resources plays in the Lower 48.” In a follow-up, he developed a “what if this all works” scenario, forecasting “what today’s 6.26 million barrels per day of U.S. crude production could be 10 years from now if a handful of these nascent resources plays ultimately reach shale celebrity status like the Bakken and the Eagle Ford….”
Kelly studied 28 “early-innings” horizontal plays, some with only slight production history to date, such as the Brown Dense, Woodbine, Tuscaloosa Marine shale and Utica—“which means we had to take the often dangerous route of relying on managements’ assumptions and expectations in order to calculate these, admittedly, very preliminary figures,” he says.
His calculations showed that at $90 oil and $4.50 per thousand cubic feet of gas, the average pretax internal rate of return (IRR) for the 28 plays is 42%; the average oil price needed for a 25% IRR is $75 per barrel. He thinks a 25% IRR is needed to justify drilling in most cases, because general and administrative, leasing and seismic expenses aren’t included in the figuring.
At $90 oil, the top IRR plays were Mississippian-Nemaha Ridge, the Niobrara-Wattenberg extension, the Woodbine, the Mississippian Permian, the liquids-rich Eagle Ford, the Granite Wash, the Niobrara Wattenberg, the Cleveland/Tonkawa, the Barnett Combo, and the Yeso. Those same plays could generate a 25% IRR at oil prices below the $74.99 average breakeven.
Kelly then looked at his play assessments in light of potential U.S. crude production. He asked, What if a handful of those 28 plays achieved as much investment and eventual production as the Bakken and the Eagle Ford have? He figured those eventual “celebrities” might be the Permian’s horizontal Wolfcamp and Cline; the Utica; the Tuscaloosa Marine shale; and the Woodbine.
“Under this scenario we assume the horizontal oil-rig count increases at a 7% annual rate, and while that assumption isn’t outlandish, the end result is quite extravagant—2022 production of 11.95 million barrels per day (from all plays, including the Gulf of Mexico and Alaska), which is 92% higher than our 2012 estimate,” Kelly says.
While the scenario is “far from our base-case scenario,” he says, it provides an interesting contrast to the EIA’s current oil forecast “that calls for a paltry 13% absolute growth rate over the same period.”
Kelly and others on the GHS team presented their analysis of 27 “early-innings” horizontal plays at a recent Society of Petroleum Engineers “Liquids-Rich Basins Conference” in Midland, Texas.
Contact Susan Klann at sklann@hartenergy.com.
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