A recently released report by West Virginia University sets recoverable gas reserves in the Utica Shale at more than 20 times the estimate of the U.S. Geological Survey (USGS).

The two-year study by the Appalachian Oil & Natural Gas Consortium concluded that the Utica possesses total recoverable resources of 22 Tcm (782.2 Tcf) of natural gas, far beyond the previous estimate of 1 Tcm (38 Tcf). The neighboring Marcellus Shale is estimated to hold 14 Tcm to 22.7 Tcm (500 Tcf to 800 Tcf) of natural gas.

“The revised resource numbers are impressive, comparable to the numbers for the more established Marcellus Shale play and a little surprising based on our Utica estimates of just a year ago, which were lower,” Douglas Patchen, director of the consortium, said in a statement.

“But this is why we continued to work on the resource estimates after the project officially ended a year ago,” he said. “The more wells that are drilled, the more the play area may expand, and another year of production from the wells enables researchers to make better estimates.”

The study, “A Geologic Play Book for Utica Shale Appalachian Basin Exploration,” also estimates recoverable crude oil at 1.96 Bbbl, or about double the USGS estimate.

“The combination of a relatively shallow reservoir and the potential for liquids production has made this an attractive play,” researchers wrote.

Even if the study overestimates its natural gas figure by a factor of 10, the Utica would still possess more than two-and-a-half times the reserves of Australia, which is on the brink of leading the world in LNG exports.

Funded by 15 industry members of the consortium, the research team also included individuals from state geological surveys in Ohio, Kentucky, Pennsylvania and West Virginia; Washington University, St. Louis; Indiana University; Smith Stratigraphic LLC; the USGS; and the U.S. Department of Energy’s National Energy
Technology Laboratory.

The study focused on the underlying Point Pleasant Formation, where drilling is concentrated in a north-south trend in eastern Ohio, although more recent drilling in the north has shifted toward the northeast and into northern Pennsylvania. As operators migrate their activities eastward into deeper drilling and higher maturation areas, they encounter dry gas.

“The level of thermal maturity in the Utica/Point Pleasant shows a progression in increasing bitumen reflectance from west to east, with a very steep increase occurring in eastern Ohio,” the researchers noted.

That could be a concern since technically recoverable does not necessarily transition to economically viable.

As Gregory Wrightstone, owner of Wrightstone Energy Consulting, told the Pittsburgh Tribune-Review, “The billion-dollar question is how far east it will prove to be profitable and productive.”

Eclipse has Utica’s number
Ben Hulburt, CEO of Eclipse Resources Corp., showcased his company’s many strengths in the Utica play at Hart Energy’s DUG East conference in June, including his claim—along with Chesapeake Energy Corp.—to be among the fastest and most efficient drillers in the play.

“In my opinion, we drill faster and cheaper than any company in the Utica, except Chesapeake,” said Hulburt. “And part of the reason is that our drilling team has drilled more wells in the Utica than anyone out there, except Chesapeake. It’s a real competitive advantage to be able to drill the highest pressure and deepest part of the Utica, which is really challenging, and to drill a 21,000-ft [6,400-m] well in 17 days.”

To date, Eclipse has participated in drilling 187 gross Utica wells, including 70 operated wells. In a comparison of operated vs. nonoperated wells, as measured by drilling days, Eclipse-operated wells since inception were 19% faster at 26 days vs. 31 days for nonoperated wells. Comparing just the last 20 wells, Eclipse was 38% faster at 18 days vs. 29 days, according to Hulburt.

He noted that since it commenced operated drilling in 2013, the company has increased lateral lengths by 33%, while well costs have been lowered by 23% so far this year compared to 2014. In the wet gas area, well costs have come down to $7.4 million from $9.5 million in 2014, and in the dry gas area costs have been cut to $8.2 million vs. $10.5 million previously, he said.

In terms of resource potential, Hulburt noted the company had some 800 remaining drilling locations. The company has recently started downspacing in the dry gas area, testing spacing of 230 m (750 ft) vs. 305 m (1,000 ft) previously, with results looking “very similar” to the wider spacing area.

“That could potentially increase our total company locations by as much as 20% just by downspacing from 1,000 ft to 750 ft,” Hulburt said. A similar test in the wet gas area, testing downspacing from 230 m to 152 m (500 ft), could provide a further 20% increase in locations, he added.

Based on the company’s current drilling space coupled with internal type curve assumptions, Eclipse management estimates that its current asset base can generate about $4 billion of net present value based on current commodity prices. By comparison, the company’s enterprise value’s was trading at only about $1.6 billion, according to Hulburt.

In addition, Hulburt pointed to a comparison of how much Utica acreage could be acquired for each $1 million of enterprise value for Eclipse and its peers. For Eclipse, each $1 million translated into 69.3 Utica acres vs. a peer group average of 41.9 acres. The range for the five peers was from 21.8 acres on the low end to 65.3 acres for the highest of the peers.

Noting its superior leverage to the play, “you get the most bang for your buck with our stock if you believe in the core of the Utica, which we do very much,” he said.

Planned capex for 2015 is $352 million. With one rig, the company projects 145% to 160% year-over-year growth in 2015, followed by 60% to 80% growth in 2016. For 2016, Eclipse assumes a continued one-rig program and the completion of 15 net drilled but not yet completed wells in the liquids area.

Projected internal rates of return (IRR) are highest for the company’s two dry gas areas based on futures strip pricing and consensus estimates. Assuming strip pricing, dry gas west and dry gas east wells had IRRs of 49% and 74%, respectively, while using consensus estimates, the two areas’ wells had IRRs of 32% and 50%, according to data shown by Eclipse.

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