Analysts: Marcellus, Utica Economics Swing On Cost Efficiencies, Well Optimization

PITTSBURGH—With takeaway capacity for produced gas in the Northeast moving toward equilibrium as new pipelines come online, the criteria for determining winners and losers among Marcellus and Utica producers are about to change, according to Kathryn Downey Miller, managing director of analytics for BTU Analytics LLC.

“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.”

Thus, having firm transportation is no longer the advantage to producers that it has been. “It’s about having the lowest cost structure.”

Miller spoke on a panel addressing Appalachian economics at Hart Energy’s DUG East conference on June 24, along with Stratas Advisors executive director of upstream Paul Morgan, and ITG Investment Research’s director of energy research Ryan Horvat.

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

Miller illustrated that U.S. demand for natural gas supply through 2018 can be met by three sources—existing producing wells, associated gas from crude oil drilling, along with Northeast production. All other sources are supply growth. “The Northeast is going to set the price for natural gas in this country.”

That is at least until LNG exports begin to provide upside to the price of natural gas in 2019 or so. “LNG has to be the game changer.”

The good news? Marcellus and Utica producers hold a vast inventory of economic acreage to remaining to drill. “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.”

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’ Morgan argued that even in a low price environment, operators with enough scale and that can control well costs can still—on the whole—create value.

Measured against average well costs and EURs, Stratas determined that roughly one-third to 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?”

The answer, he surmised, is cumulative portfolio economics.

“You’re going to have some hogs, and you’re going to have some dogs,” said Morgan. “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. Portfolio economics is the key.”

Effective portfolio economics can be achieved with sufficient scale, he said, a possible incentive for operator consolidation.

ITG’s Horvat 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, Horvat said, with ITG setting the baseline for its model at 200 foot spacing, “which seems to be what most operators are trending toward.”

However, the results for increasing lateral lengths proved opposite. 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 moving to 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,” Horvat said.

Considering lease limitations, ITG 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 well head” with optimization, he said. Premier dry gas counties like Susquehanna, Wyoming and Sullivan, Pa., could exhibit average EURs over 15 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.” Wet gas areas could see 7 Bcfe EURs at the wellhead, and 10 Bcfe post processing.

The reveal: 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 Tcfe of resource potential. “That equates to over 20 years of drilling inventory,” at today’s rig count, Horvat noted.

Contact the author, Steve Toon, at stoon@hartenergy.com.