The current slate of Marcellus and Utica shale takeaway expansions exceeds expected supply growth, a dynamic that points to shrinking Appalachian basis differentials and major upside for regional production over the next few years, according to analysts with Raymond James & Associates Inc.
A combined 7.5 Bcf/d of planned un-risked pipeline expansions are expected to come online through 2018 in the Marcellus and Utica, compared to an anticipated 2 Bcf/d of increased production over the same period, a team of analysts led by Darren Horrowitz and J. Marshall Adkins said in a research note Monday.
As for the 2 Bcf/d of production growth, that’s based on a cash flow-driven model where Raymond James expects the Marcellus and Utica to go from a combined 65 rigs to 87 rigs by year-end 2018. “Additionally, we expect a drawdown of the current” drilled uncompleted (DUC) “backlog from around three months of a completion backlog to a more normalized level of two months of completion backlog by mid-2018,” the analysts said.
“The combination of more drilling and even faster completions should translate to a roughly 10% increase in year/year average daily production volumes from around 22 Bcf/d in 2017 to around 24 Bcf/d in 2018 for the combined Marcellus/Utica.”
But Horrowitz and Adkins emphasized that the new takeaway capacity could see actual production surpass this forecast given “there is a strong likelihood that producers will find a way to fill those pipes.”
“All things considered, we expect this new pipeline takeaway capacity to do its part to de-bottleneck trapped gas and lead to better gas pricing and significant regional production growth,” the analysts said. “Better prices should improve” exploration and production (E&P) “company netbacks, ultimately driving more cash flow and volume expansion out of the region.”
While “there’s no question that there’s a sizeable amount of takeaway capacity being added in the Northeast market in a relatively short amount of time,” the $1/MMBtu-plus negative basis differentials at Appalachian points the last few years clearly show a constrained region in need of a long-term solution to free up its economic supply, the analysts said.
And new pipes like Rover, Nexus and Atlantic Sunrise should do just that.
Horrowitz and Adkins said they expect a 13% reduction in average Appalachian basis differentials and gathering, processing, marketing and transportation costs by 2019. “As the gap grows between pipeline takeaway capacity (and regional demand) and Northeast gas supply, differentials may narrow more quickly than anticipated. If Northeast differentials were to improve more than we model, it is entirely possible (if not likely) that our current production outlook could be proven conservative as soon as next year.”
Despite the drawdown of the DUC backlog, “very prolific wells and improving producer efficiencies should allow Northeast E&Ps grow gas supply throughout the Marcellus/Utica at Henry Hub prices well below $3/MMBtu,” the analysts said.
Meanwhile, Raymond James projects associated gas output from oil-directed drilling in the Permian Basin, the Niobrara-Denver Julesburg, the Eagle Ford Shale, the Midcontinent and the Bakken Shale could generate another 3 Bcf/d of incremental supply through 2018.
Horrowitz and Adkins said they “still believe that structural U.S. gas demand drivers are coming in 2018” in the form of about 3.5 Bcf/d of new demand from liquefied natural gas exports, pipeline exports to Mexico and industrial consumption.
“All things considered, we expect 2018 gas supply growth to outpace demand growth leading to modestly lower” natural gas prices. “That said, improving Northeast basis differentials should offset these lower end market prices and incentivize gas production growth in Appalachia.”
Between associated gas and Marcellus and Utica E&Ps ramping to fill new pipes, “the U.S. has all the natural gas it needs (and more) with Henry Hub at $2.75/MMBtu” or potentially even lower, the analysts said.
While the broader conclusion that the new Appalachian takeaway will shrink average basis differentials is fairly straightforward, “the actual dynamics are fairly complicated,” according to Horrowitz and Adkins.
Tariffs are generally higher on new-build pipelines to the Gulf Coast, with costs being “much cheaper” to get gas to nearby end markets such as in the Southeast, they said.
“Differentials will also fluctuate throughout the year based on storage and demand seasonality. In-basin demand basically doubles in the winter (New England has about a 10-20 Bcf/d seasonal demand range),” the analysts said.
“…If this significant of a gap between supply and regional demand and pipeline takeaway capacity actually develops, we would easily see Northeast differentials narrow to more than we currently model. As the model presently stands, we estimate Northeast wintertime gas may even receive close to ‘premium pricing’ from the combination of” winter in-basin demand and new takeaway capacity going underutilized.
© 2020 Natural Gas Intelligence. All rights reserved.
ISSN © 2577-9877 | ISSN © 1532-1266 | ISSN © 2158-8023 |