marcellus

The Rockies Express Pipeline (REX) has been transformative. Originally built as a west-to-east pipeline, its main job was to give Rockies natural gas a way to reach premium markets in the Midwest and the Northeast. But by the time it was constructed, surging production in the Marcellus and Utica shales had overwhelmed the need for Rockies gas in the East, and REX evolved to become a major outlet for Appalachian gas to the Midcontinent. Now, REX has moved beyond its first two incarnations, and its owner, Tallgrass Energy, has announced plans to build a greenfield pipeline that would connect REX and the markets it serves with the prolific Permian Basin, 900 miles south of the existing mainline. In today’s RBN blog, we’ll discuss REX’s history, where it stands today, and how a new pipeline connection with the Permian might fit into its evolving strategy. 

Just over three years ago, Cabot Oil & Gas — Coterra Energy’s corporate predecessor — was focused exclusively on producing natural gas in the Marcellus Shale. But unlike other gas-centric E&Ps like EQT Corp., Chesapeake Energy and Antero Resources, Cabot decided it was time to diversify. In October 2021, it merged with Cimarex Energy, an oil-and-gas producer in the Permian and the Anadarko, to form Coterra. Now, Coterra has doubled down on diversification with a plan to acquire oil-weighted Permian assets from privately held Franklin Mountain Energy and Avant Natural Resources for a total of $3.95 billion in cash and stock. In today’s RBN blog, we discuss the deals and why Cabot/Coterra decided to “go its own way.” 

Shell’s petrochemical complex in Western Pennsylvania has had plenty of challenges on its way to startup and full operation. Announced a dozen years ago, the project was set back by COVID-related construction delays and a rougher-than-expected production ramp-up. But that’s all in the past now (fingers crossed) and the ethane-rich Northeast finally has its first big ethylene plant. In today’s RBN blog, we’ll examine Shell’s return to plastics and what it took to get there. 

Observers of the natural gas market over the past 20 years know that the main story has been one of enormous growth. The Shale Revolution gave new life to the U.S. natural gas sector, leading to the record production levels we are seeing in early 2024. The economy has found many uses for this new gas: increased power generation, more pipeline exports to Mexico, expanded industrial gas usage and — most prominently — the many LNG export facilities that have cropped up since 2016. But with the pause on new LNG export licenses and the push to renewables in the power sector, there’s a looming question of where the new natural gas would go if production continues to expand. In today’s RBN blog, we look at how that new gas might be absorbed, both domestically and internationally, and what continued growth would imply for gas prices and producers in the long term. 

In a deal the energy industry had been whispering about for months, Chesapeake Energy and Southwestern Energy will combine to form what will be the largest natural gas producer in the U.S., with 7.3 Bcf/d of production in the Marcellus/Utica and the Haynesville and ready access to the Northeast and the LNG export market — assuming the merger passes muster with federal regulators. In today’s RBN blog, we discuss the merger and why it makes sense for both E&Ps. 

With ever-increasing volumes of Permian crude oil being exported and the recent inclusion of WTI Midland in the assessment of Dated Brent prices, the issue of iron content — especially in some Permian-sourced crude — is coming to the fore. This has become such a point of emphasis for exported light sweet crude because many less complex foreign refineries do not have the ability to manage high iron content adequately. Iron content that exceeds desirable levels could have far-reaching repercussions, from sellers facing financial penalties for not meeting the quality specifications to marine terminals being excluded from the Brent assessment if they miss the mark. It’s a complicated issue, with split views on what causes the iron content in a relatively small subset of Permian oil to be concerningly high — and how best to address the matter. In today’s RBN blog, we look at iron content in crude oil, why it matters to refiners, how it affects prices, and what steps the industry is taking to deal with it.

As U.S. E&Ps deal with a slew of shorter-term challenges such as broken supply chains, labor shortages, and infrastructure constraints, they’re also paying increasing attention to a longer-term concern: “inventory exhaustion.” There is a growing chorus of analysts asserting that oil and gas producers’ inventory of top-tier drilling locations has been significantly depleted as the nation’s major unconventional resource plays mature. Many producers have continued to rein in their capital spending and husband their current resources and several have boosted inventories through bolt-on acquisitions. Premier E&P EOG Resources has taken a different approach, emphasizing organic exploration that has led to the discovery of two new significant plays over the past two years, including the recent announcement of a new Utica Shale combo play that it describes as being “almost reminiscent” of the early Delaware Basin. In today’s RBN blog, we discuss EOG’s dramatically different approach to building inventory and dive into the details of its new Utica discovery.

Without a doubt, the two biggest changes to U.S. natural gas markets in the last 15 years have been the Shale Revolution and the development of LNG exports. These completely upended the way gas flowed in this country, with the Northeast now home to the largest gas-producing basin and the Gulf Coast — including its fleet of LNG export terminals — now the U.S.’s largest demand center. Production growth in the Marcellus/Utica has stalled, however, largely due to the regulatory and legal challenges associated with building new pipeline takeaway capacity. One possible fix would be a new East Coast LNG terminal, which in addition to having easy access to cheap, almost-local gas would also be close to gas-hungry European markets. But just how likely is such a project? In today’s RBN blog, we discuss the advantages and hurdles of developing LNG export capacity on the East Coast.

The U.S. Department of Energy has laid out a clear set of criteria for the six to 10 clean hydrogen hubs it will select next year to receive up to $8 billion in federal support. For example, DOE wants at least one hub to use renewable energy to make hydrogen, another to use nuclear power, and another to use fossil fuels with carbon capture and sequestration (CCS). It also wants diversity among hydrogen end-users — geographic diversity too (at least two hubs must be in areas with the greatest natural gas resources) — and the department says it will give extra weight to proposals likely to create the most opportunities for skilled training and long-term employment. Yet another factor that’s sure to boost the prospects for hydrogen hub proposals in the heart of the Marcellus/Utica Shale is the looming presence of West Virginia Senator Joe Manchin, the Energy & Natural Resources Committee chairman who helped make hydrogen hub funding — and the rest of last year’s $1-trillion-plus infrastructure bill (and this year’s Inflation Reduction Act) — a reality. In today’s RBN blog, we discuss the hydrogen hub proposals now under development in northern West Virginia, western Pennsylvania and eastern Ohio.