PITTSBURGH—Eclipse Resources Corp. (NYSE: ECR) didn’t rest on its laurels after drilling its record-breaking Purple Hayes last year, which boasted the world’s longest onshore lateral leg at the time, 18,544 feet into the Utica Shale.

Now the company is drilling even longer laterals, Eclipse Chairman, President and CEO Benjamin Hulburt told attendees at Hart Energy’s recent DUG East Conference. New Generation 3 completion designs are being extended from the company’s Utica condensate and rich gas areas into the dry gas area and also to its Marcellus opportunities in southeast Ohio.

The company’s Outlaw C 11H, its third “super-lateral” in Ohio, had an extension of 19,500 feet and was drilled in 17 days. In the Utica condensate window, it set a new company record for lateral length. This well, in turn, surpassed Eclipse’s recently drilled Great Scott 3H, which went out to 19,300 feet. Both the Scott and Outlaw wells will be completed in the third quarter.

The Purple Hayes, meanwhile, was fracked in 134 stages and after waiting on flowback, is producing about 5.6 MMcf/d from the Utica in Guernsey County, Ohio. Proper fracking and pressure management were keys to Eclipse’s Utica success.

Eclipse will continue to push the envelope. The longest laterals it plans in the Utica’s dry gas window will be 16,000 to 17,000 feet, Hulburt said. “We have 11 super-laterals planned in 2017: eight in the condensate window and three of which are in the dry gas portion of the play. What works in the Utica does not necessarily work in the Marcellus,” he noted. In dry-gas Utica locations, the company could go out as far as 19,000 feet eventually, but in the Marcellus, “we’ll see how these 10,000-footers work.”

“We plan on 13,000-foot laterals on average in the Utica and 10,000 feet in the Marcellus.”

Due to the downturn and because Eclipse emphasizes engineering, the company has focused on innovation to drive down costs, get drilling days down and drive up EURs, he said. Eclipse’s super-laterals were designed after six to eight months of intense engineering study. Although he said the goal was to reduce the company’s cost per lateral foot more than to improve recoveries, the super-laterals do both, and have outperformed the company’s type curves.

“In 2014 in our wet gas wells, it cost us $1,500 per lateral foot. That was too expensive…now on a 13,000-foot lateral, we’re down to $818 per lateral foot. This is really unparalleled by any other operator in the Utica,” Hulburt said. “We’re struggling to make sure we get the same recovery per foot in these super-laterals.”

Hulburt started Eclipse in 2011 when the Utica play first kicked off. “We chose to go to the southern end of the play—which has now proven to be the core of the core in Ohio. We’ve always focused on ‘How do we make it work?’ by looking at innovation and operational excellence. Why? Frankly these wells didn’t work at the previous commodity prices, so we focused on what we could do,” he said, which was reduce the costs.

“One thing we focused on was lateral lengths, which had enormous benefits, and how to make our completion designs cheaper and more effective. We have exceeded every type curve across our acreage and we’re getting 50% wellhead rates of return at today’s low commodity prices, which I think is a phenomenal result,” he said.

“This year in the Utica we will average 13,300 feet lateral lengths with 11 of those wells averaging 15,000 feet.” Some 40% of the wells will be in the condensate portion of the play that Hulburt said the rest of the industry abandoned. “We stayed there and went to work. Eclipse has a 15-year drilling inventory at its current pace.”

Eclipse will begin testing Gen 4 completions shortly, he said. It has switched all its fracks to slick water, which is less expensive than prior completion designs, and gets better results. At the same time it’s pushing more and more sand into the fractures.

Pressure management is especially important in the dry gas portion of the Utica, he said. Engineered flowback procedures bring the wells slowly up to target production rates while preserving fracture conductivity and minimizing formation damage. Results led the company to increase its type curves.

Of the Purple Hayes, he said, “We fracked that well with 135 stages—and out of that we put away 134 stages. But one of the criticisms we got—and still get—is that we wouldn’t be able to put away all these stages in the Utica Shale. We did have to develop some ‘designer’ friction reducers to allow us to move the proppant out that far.”

Why these longer laterals? With decreased costs and more recovery per foot, the return benefits are enormous and the economics improve. “For one thing, pads in Appalachia are relatively expensive. Depending on where we are in Ohio, the more cost we can spread across a pad, with greater amounts of production, the more economic it is.”

Gen 3 completions focused on tighter frack staging, increasing proppant to 2,300 pounds per foot. Gen 4 uses 3,000 pounds per foot and more.

Hulburt said Eclipse doesn’t measure wells by IP rate, but by what it calls the Productivity Index, which looks at how pressure changes across the horizontal leg as more sand is used. “We’ve only tested 3,000 pounds per foot so far. The cost of proppant will temper our experimentation somewhat. But proper pressure maintenance keeps the proppant in the fractures. In the condensate portion, there’s the added benefit of keeping the pressure at a certain dew point so the condensate stays a gas—we delay the point at which that happens as long as possible.”

In the Utica’s condensate portion, Eclipse has 16 wells that used Gen 3 completions, and gas production is easily exceeding its type curve. “We are very pleased with their performance.”

“We’ve laid out a three-year plan for our investors, and our stock is available and on sale for all of you today! We anticipate seeing a 25% compound annual growth rate in production over a three-year period, and all the while during that period we will actually be deleveraging on a cash flow-to-debt basis.” The company has hedged about 90% of its gas output in 2017 and 60% in 2018.

“We’ve been public now for 12 quarters and we have met or exceeded our guidance every single quarter. So we believe very strongly that these numbers are conservative and realistic. If we have $3 gas and $45 oil, which is pretty much the current strip, virtually every well we drill has rates of return in excess of 60%.”

Leslie Haines can be reached at lhaines@hartenergy.com.