Takeaway capacity in the northeast region of the Marcellus Shale at present is "barely ahead" of production, and that tells you everything you need to know, according to Jefferies & Co. equity analyst Subash Chandra. “Very small changes in timing or weather could really swing basis differentials around. Local markets are pretty fickle,” he told Hart Energy.
To wit, when the Henry Hub natural gas price in early March stood at $4.77 per thousand cubic feet, pricing in a relatively small geographic area in the Northeast ranged from as low as $1.80 in northern Pennsylvania to $16 in Connecticut, per Energy Information Administration data, depending on which end of the constrained pipelines sat the supply or demand.
Offtake for burgeoning Marcellus volumes is at a premium in the current environment, and spot markets discount deep for excess stranded gas. Production from the rapidly growing basin is mounting at a breakneck pace, now some 14 billion cubic feet per day (Bcf/d) basinwide and climbing. Wells are huge, and find-and-develop costs are low. Yet infrastructure struggles to keep pace in moving those volumes; spot price differentials to Henry Hub are volatile.
Operators, meanwhile, assure they have their situations under control or signal they are confident of finding uncontracted third-party capacity and buyers in time. Maybe, just maybe, they might pace their development for a while, but at Street-pleasing growth levels all the same. Large volume percentages are hedged, if they can get it to market.
The analysts aren’t so optimistic.
Bob Brackett, senior analyst for Bernstein Research, in a series of spring reports titled “Who’s Afraid of Marcellus Differentials,” stated that the bear case for northeast Marcellus producers centers around those price differentials to Henry Hub.
“The view is that rising Marcellus production—some 2 billion cubic feet a day year-over-year for 2014—versus lack of incremental takeaway capacity—about 800 million cubic feet a day year-over-year for 2014—will result in another year of even worse basis differentials, with negative revenue implications for operators in the region.”
This year will get more painful before the situation gets better. The bright light at the end of the tunnel for northeast Marcellus producers shines primarily from two big pipeline projects. Williams Cos. Inc.’s Constitution pipeline will carry 650 million cubic feet per day (MMcf/d) and is expected online in late 2015 or early 2016.
Transcontinental Gas Pipeline Co. LLC’s Atlantic Sunrise will deliver 1.7 Bcf/d, anticipated in 2017. They can’t come too soon. Until then, producers are hard pressed to find capacity.
“The improving average well of the northeast Marcellus indicates that even with only 26 active rigs, we would expect continuation of too much supply vs. pipeline capacity through at least 2015, and likely through 2017,” Brackett said. “This will likely drive sustained depressed pricing at the Marcellus inlet of as low as $2 per MMBtu, our estimate of where the highest-cost producers are likely to shut in production.”
Jefferies’ Chandra reiterates this prognosis, warning that northeast Marcellus players are “on the brink” for at least two years. Economics here are “extremely fluid and getting incrementally more challenging. Operators are going to have to be very flexible with drilling plans,” he said.
“Producers can’t afford to be speculators where they produce more gas when prices are high, and don’t produce when prices are low. They don’t have that option.” Unfortunately, the Northeast does not have the baseload demand needed to level differentials. Over time, the Gulf Coast will be the market for base loading excess Marcellus gas, he said, with projects already in the queue.
“But you’ll pay more” to move the gas, he noted. “The whole notion is, ‘Will my Henry Hub price compensate for my transport costs?’ That, of course, is a developing situation. It’s not like you can pay a dollar and change at $4 gas to get your gas to the Gulf Coast, and still make a lot of money.”
Until the big pipes are built, the next two years offer “incredible uncertainty,” and some operators will be less aggressive or will shut down entirely, he said.
In the northeast Marcellus, Chandra places the mantle at the feet of Cabot Oil & Gas Corp. “Cabot will decide marginal supply,” he said. “They’re the biggest source of growth. No one else really matters up there. They will either balance it or imbalance it.”
While the next two years might be an uncomfortable period for impatient producers, the growing pains of a maturing play will subside in the long term. As infrastructure catches up and markets balance, the Marcellus Shale is poised to be the primary hub of U.S. natural gas supply into the future.
Canadian Oil Group Says Federal, Provincial Tension Blocking Carbon Capture Talks
2023-01-24 - The Pathways Alliance, comprised of Cenovus Energy, MEG Energy, Suncor Energy, Canadian Natural Resources, Imperial Oil and ConocoPhillips, represent 95% of Canada's oil sands production.
Alberta Offers to Work with Trudeau on Carbon Capture with Conditions
2023-02-17 - Alberta Premier Danielle Smith agreed to work with Prime Minister Justin Trudeau on carbon capture regulations on the condition that Alberta is consulted before passing legislation or policies impacting the oil and gas sector.
Alberta Minister Says Canada Emissions Cap Stalls Other Climate Action
2023-02-14 - Canada needs to pack nearly all its decarbonization into eight years to meet its 2030 target since its emissions have only fallen 3% since 2005, according to an emissions report.
Exxon Halts Routine Gas Flaring in the Permian, Wants Others to Follow
2023-01-25 - Exxon Mobil is seeking tougher regulations on flaring to "level the playing field."
Emissions Management: The New ‘E’ for E&P
2023-01-24 - Emissions management strategies are having a greater influence on E&P profitability, according to Enverus.