“Operators with firm takeaway capacity have been the real winners” over the past couple of years, she said, “but going forward, as production is tempered by demand, it’s going to come down to who has the best acreage, and who can best manage their costs.”

Miller spoke on an Appalachian economics panel at Hart Energy’s DUG East Conference and Exhibition in Pittsburgh held in June. Also on the panel were Paul Morgan, Stratas Advisors’ executive director of upstream, and ITG Investment Research’s director of energy research, Ryan Horvat.

Once infrastructure projects scheduled to come online through 2018 have relieved takeaway pressures, North American demand will become the new constraining factor for Appalachian producers, Miller said. “Expect demand to temper prices and also Northeast production going forward.”

U.S. demand for natural gas supply through 2018 can be met by three sources: existing producing wells, associated gas from crude oil drilling, and Northeast production, Miller said. “The Northeast is going to set the price for natural gas in this country.”

That is, until LNG exports begin to bolster the price of natural gas in 2019 or so. “LNG has to be the game-changer,” she said.

Marcellus and Utica producers hold a vast inventory of undrilled economic acreage. “We don’t necessarily need the price to be much higher than $2.40,” she said. “We’ve got enough inventory to continue drilling wells at that sub-$2 level.”

There is evidence of producer high grading as the percentage of wells breaking even at $3/Mcfplus is declining over time.

Miller noted that in 2014, only 15% of wells drilled had breakevens above $3. “That shows operators understand where the best wells should be drilled.”

Stratas’ Paul Morgan argued that even in a low price environment, operators with enough scale and well cost control can create value.

Measuring against average well costs and estimated ultimate recoveries (EURs), Stratas determined that roughly one-third to one-half of all wells drilled at current gas prices are economic, based on a 10% pre-tax breakeven. “Then what are we doing, if so many wells are struggling so much, because a lot of companies are still out there drilling?” he asked.

The answer is cumulative portfolio economics. “If you can control your costs, and you can drill a sufficient number of wells to offset the bad with the good … then that builds a portfolio that creates value.”

An optimized Marcellus

ITG’s Horvath explored the premise of what Marcellus results might look like once the play is optimized, focusing on two variables—completion stage spacing and lateral length.

Measuring EURs per 1,000 foot of lateral of all wells drilled since 2010, ITG confirmed operators experience better results generally with tighter spacing, but see diminishing returns as spacing narrows. Maximum value occurs at 164- to 210-foot spacing, Horvath said, with ITG setting the baseline for its model at 200 feet, “which seems to be what most operators are trending toward.”

The results for increasing lateral lengths proved opposite, however. As operators have pushed lateral lengths outward, ultimate recoveries show a modest but insignificant deterioration, from an average of 1.6 billion cubic feet (Bcf) per 1,000 feet for a 2,500-foot lateral, to 1.5 Bcf per 1,000 feet for an 8,000-foot lateral.

“So as long as you have the acreage orientation to do it, and you continue to see costs go down per 1,000 feet, it makes sense to drill out as far as you can,” Horvath said.

Considering lease limitations, ITG has established 5,500 feet as its baseline lateral length in its model.

“We see the average EURs across the play increasing by almost 3 Bcfe to 9.5 Bcfe at the wellhead” with optimization, he said. Premier dry gas counties like Susquehanna, Wyoming and Sullivan, Pennsylvania, could exhibit average EURs of more than15 Bcf.

“With better well designs, we believe the Northeast dry gas area could get to 19-Bcf recoveries on average—from a 5,500-foot lateral,” he said. Wet gas areas could see 7-Bcfe EURs at the wellhead, and 10-Bcfe recoveries post processing.

ITG calculates more than 35,000 Marcellus drilling locations to be economic below a natural gas price of $3.50/Mcf with optimized well performance, representing some 350 trillion cubic feet equivalent (Tcfe) of resource potential. “That equates to over 20 years of drilling inventory,” at today’s rig count, Horvath noted.

Capturing more for less

Today, Chesapeake Energy Corp., a top-tier operator in the Marcellus and Utica shale plays, is focusing on cost control, rock quality and operational changes in a radical departure from its “leave no acre behind’ philosophy held prior to 2013.

“We are looking at how to maximize the value of hydrocarbons for every dollar we spend,” said Dale Malody, vice president, Appalachia North.

Chesapeake has dramatically improved its balance sheet. In 2014, it reduced debt, spun off its oilfield services unit and sold its southern Marcellus assets. It is now a surgical and targeted acquirer, said Malody. And its operational turnaround has been stunning: In 2014, the company had one-third the rig count and half the capital budget as in the prior year, but it drilled the same number of wells.

The Appalachian Basin shale plays are foundational assets for the new Chesapeake, accounting for 40% of the firm’s total production.

Chesapeake holds roughly 1 million net acres in the Utica, primarily in eastern Ohio and spread across all hydrocarbon windows. Its production from the play is 120,000 barrels of oil equivalent per day (boe/d) net. From the four rigs it runs currently, the company plans to drop to two by the middle of the third quarter. That will allow the company to drill the number of wells it needs to hold its acreage.

A good example of production optimization is Chesapeake’s progress on enhanced completions. These completions, which feature longer laterals, more stages per well and customized cluster spacing, have resulted in a 20% boost to the company’s EUR per well.

In the Marcellus play, Chesapeake now holds roughly 500,000 acres in northeastern Pennsylvania’s dry gas area. It makes just under 2 Bcf of gas per day gross (835 MMcf per day net) and it plans to keep one rig at work through year-end 2015. As in the Utica, Chesapeake’s priorities are to maintain the minimum activity required to hold acreage, continue to drive efficiencies, and increase resources. It is executing on the latter through expansion of the traditional lower Marcellus play and also through new testing in the upper Marcellus interval, which could lead to stacked pay developments.

In the lower Marcellus, enhanced completions are also leading to better results, with the EUR per well rising more than 20%, increasing from 9 Bcf in 2011 to an estimated 12 Bcf per well this year.

Also claiming efficiencies is Eclipse Resources Corp. CEO Ben Hulburt said, “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 drill a 21,000-foot well in 17 days.”

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

The Eclipse CEO noted that since the company began operated drilling in 2013, it has increased lateral lengths by 33%. Well costs have been lowered by 23% so far this year as 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 versus $10.5 million previously, he said.

In terms of resource potential, Hulburt noted the company had some 800 remaining drilling locations. It has recently started downspacing in the dry gas area, testing spacing of 750 feet versus 1,000 feet 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 feet to 750 feet,” he said. A similar test in the wet gas area, testing downspacing from 750 feet to 500 feet, could provide a further 20% increase in locations, he added.