Pipeline Constraints

Marcellus/Utica natural gas production grew by leaps and bounds in the 2010s, but the pace of growth has slowed dramatically in recent years, mostly due to takeaway constraints. Finally, the prospects for renewed growth are improving. New pipeline capacity out of Appalachia is coming online — especially to the booming Southeast, and maybe the Gulf Coast too. New LNG export capacity is about to be commercialized. And a lot of new gas-fired generating capacity — much of it tied to planned data centers — is under development within (or very near) the Marcellus/Utica region. In today’s RBN blog, we examine the three big gas-demand drivers behind the shale play’s impending renewal. 

Marcellus/Utica natural gas production grew by leaps and bounds in the 2010s, but the pace of growth has slowed dramatically in recent years, mostly due to takeaway constraints. Finally, the prospects for renewed growth are improving. New pipeline capacity out of Appalachia is coming online — especially to the booming Southeast, and maybe the Gulf Coast too. New LNG export capacity is about to be commercialized. And a lot of new gas-fired generating capacity — much of it tied to planned data centers — is under development within (or very near) the Marcellus/Utica region. In today’s RBN blog, we examine the three big gas-demand drivers behind the shale play’s impending renewal. 

The Marcellus/Utica region is by far the most prolific natural gas production area in the U.S., accounting for about one-third of the nation’s daily output. The shale play experienced phenomenal growth in the 2010s, its gas production rising from less than 2 Bcf/d to more than 33 Bcf/d over that decade. But the pace of growth has slowed dramatically in recent years, mostly due to takeaway constraints. In today’s RBN blog, we discuss how a combination of new pipeline projects, in-basin data center development and incremental Gulf Coast LNG demand might breathe new life into the Marcellus/Utica. 

For the past decade, producers in the Permian Basin have been the driving force in domestic production growth, but lately there has been a hard-to-miss slowdown in incremental production rates for crude, gas and natural gas liquids (NGLs). While Permian producers are primarily motivated by crude oil economics, those volumes also come with a lot of associated natural gas and NGLs. These commodities are therefore fundamentally interlinked. So if there’s a hangup with one, the effects will be felt across the upstream and then cascade downstream. There is a lot of money riding on these markets and the impacts of an extended slowdown in the Permian could be monumental, not just in the energy industry but also in the broader U.S. and global economies. In today’s RBN blog, we will examine what’s to blame for plateauing production in the U.S.’s most prolific basin and gauge what its big-picture implications might be. 

Six months ago, the U.S. West Coast natural gas market looked like it was in dire straits. A harsh winter had depleted stocks to the lowest level in over a decade and it seemed like the region would be hard-pressed to refill storage to a reasonable level, given limited and constrained pipeline options to flow incremental gas west. Instead, a combination of mild weather and operational changes eased demand and pipeline constraints, and Pacific Region storage staged a remarkable comeback this summer. In today’s RBN blog, we delve into how the region escaped a worst-case scenario heading into the heating season. 

Appalachian natural gas producers and marketers are adapting to a new status quo — a world where new pipeline takeaway capacity out of the Northeast is hard to come by and is more or less capped ad infinitum. Without the assurance of pipeline expansions, regional gas producers are no longer drilling with abandon in hopes that the capacity will eventually get built. Instead, producers are practicing restraint by slowing drilling activity, delaying completions and choking back producing wells to manage their inventory during periods of lower demand and prices. In today’s RBN blog, we consider what this new playbook will mean for pricing trends in the supply basin.

We’ve seen this movie one too many times. Just when natural gas prices are rallying across the world to multi-year or historic highs, another monkey wrench gets thrown into the workings of the Western Canadian gas market, imploding its suite of price markers. Last week, gas prices in Western Canada collapsed to mere pennies and even went negative for a time due to an unfortunate combination of pipeline restrictions and record-high production — a situation that will cost the region’s gas industry billions if left unchecked. In today’s RBN blog, we examine the root cause of the latest price collapse and when a turnaround might be expected.

It seems that, once again, Canada is struggling to build crude oil pipeline export capacity fast enough to keep pace with production growth. The latest setback came with the announcement that completion of the Canadian government-owned Trans Mountain Expansion (TMX) will be delayed until the third quarter of 2023 and that the 590-Mb/d project will cost almost twice as much as previously estimated. The latest six-to-nine-month delay appears to set the Canadian oil industry on a path to exhausting its spare export capacity by later this year. And that’s not good news for producers. In today’s RBN blog, we consider this latest TMX announcement and what it might mean for pipeline constraints and heavy oil price differentials.

Oil sands, the workhorse of Alberta’s — and Canada’s — crude oil production growth, achieved a record production year in 2021. A steady turnaround in crude oil prices, improved market access, and the tried-and-true resilience of oil sands producers combined to drive the increase in output. With 2022 barely out of the starting blocks, the oil sands players have provided production guidance for this year that, if fulfilled, could set the oil sands on track for another year of record output. In today’s RBN blog, we consider the latest production guidance estimates and what these could mean for the availability of oil pipeline export capacity from Western Canada.

Pandemic. Deep freeze. Decarbonization. Stymied production growth. Sky-high prices. 2021 was definitely one for the record books. But thank goodness we made it and can look forward to a New Year! That means it is time for our annual Top 10 Energy Prognostications, the long-standing RBN tradition where we consider what’s coming next to energy markets. Say what? Surely it would be foolhardy to make predictions now. After all, we’re in the midst of a chaotic energy transition, a pandemic that’s becoming endemic, and political shenanigans in Washington and across the globe. Foolhardy? Nah. All we need to do is stick out our collective RBN necks one more time, peer into our crystal ball, and see what 2022 has in store for us.