One of the most compelling Greek myths is the story of Sisyphus, a man condemned by the gods to eternally push a giant boulder to the top of a mountain, only to have it crash back down to the valley just short of his goal. His plight is not a bad metaphor for the long-term historical trend of U.S. E&Ps, which neared pinnacles of financial stability in 1999, 2008, 2014 and 2020 — just before price drops sent returns plunging. Producers seem to have ducked out from under the curse recently, recording record post-pandemic profits in 2021 and 2022, then settling into an extended period of stable, elevated returns. However, deteriorating gas realizations have at least paused the boulder’s climb for all E&Ps and sent it rolling back for gas-weighted producers. In today’s RBN blog, we analyze the overall positive returns for Oil-Weighted and Diversified producers and the more dramatic impact of low pricing on the Gas-Weighted E&Ps.
Crude Oil
The Gulf of Mexico (GOM) has long been a hotspot for crude oil and natural gas production, but technological advancements have pushed the boundaries of what’s possible in deepwater operations, opening previously inaccessible reservoirs. Chevron is the first to deploy new equipment capable of handling the more extreme pressures found very deep below the seafloor. In today’s RBN blog, we’ll highlight the project — known as Anchor — and explore how this new technology is paving the way for similar developments.
Over the past decade, the only significant growth market for U.S. crude oil and NGLs has been exports, with over 90% departing from the Gulf Coast. Exports via Gulf of Mexico ports have surged from about 1 MMb/d in 2016 to over 6 MMb/d last year. Great news for PADD 3 export facilities, right? Well, it’s not that simple. The distribution of barrels has been wildly uneven, resulting in significant winners, forlorn losers, and everything in between. And export volumes are still ramping up, as is the competition among marine terminals for crude and NGL export market share, with far-reaching consequences for producers, midstreamers and exporters. This is one of the core themes at our upcoming NACON conference, which is all about PADD 3 North American Crude Oil & NGLs and scheduled for October 24 at the Royal Sonesta Hotel in Houston. In today’s RBN blog, we’ll delve into the highly competitive liquids export landscape, consider some of the important factors driving flows one way or the other, and — fair warning — slip in some subliminal advertising for the NACON event.
Through a pair of newly announced, multibillion-dollar acquisitions, ONEOK is following up on its game-changing purchase of Magellan Midstream Partners by gaining additional scale, significantly increasing its role in NGLs and adding a huge crude oil gathering system in the Permian. The new deals are designed in large part to help ONEOK “feed and fill” its gas processing plants, takeaway pipelines and fractionators. In today’s RBN blog, we’ll discuss the details and implications of ONEOK’s newly announced plan to acquire EnLink Midstream and Medallion Midstream.
Crude oil production in the U.S. Gulf of Mexico (GOM) is poised for a growth spurt through 2030 even as producers brace for a host of challenges, not least from forecasts that global oil demand will subside in the long term. But while the GOM’s supply accounts for a relatively small portion of total U.S. production, exploration and production companies (E&Ps) haven’t lost interest, in part because the Gulf offers key crude grades in high demand. In today’s RBN blog, we examine what is stoking the renewed interest in developing the GOM.
For a few days last week, Canada experienced a nationwide shutdown of its rail transportation network — the backbone of its economy. Of the literally thousands of items railed across Canada to consumers and for export to the U.S. and overseas, we consider three important liquid energy commodities — crude oil, propane and butane — that are transported by rail to provide some perspective on the volumes and dollar values that could have been jeopardized by an extended shutdown. In today’s RBN blog, we summarize the short-lived disruption to Canadian and international commerce and tally the impacts that could have been.
Every year, the biggest wild card regarding Gulf of Mexico (GOM) crude oil production is the severity of the Atlantic hurricane season. A season generally free of major storms in offshore production areas will likely have only a minimal impact, but a summer and early fall with even just one or two powerful hurricanes along certain paths can cause output to plummet, sometimes for extended periods. In today’s RBN blog, we’ll look at GOM production gains over the years, the degree to which hurricanes and other issues have reduced output in the past, and the new production expected to come online later this decade.
Guyana’s crude oil production is surging, a trend that is expected to continue through the rest of the decade, and with no domestic refining industry its exports are booming. Shipments of Guyana’s medium-density, sweet-ish crude to the U.S. have ramped up and are increasingly making their way to the West Coast, which relies on imports given its lack of easy access to domestic shale crudes and limited regional output. In today's RBN blog, the second in a series, we‘ll examine where Guyana’s barrels are ending up and how they stack up against competing grades.
The permitting process for energy projects can drag on for years, resulting in multiple state and federal hurdles, environmental studies and judicial reviews. This is true not only of traditional energy projects involving oil and gas but also renewables like wind and solar and long-distance transmission, which are seen as key elements of the energy transition. Legislation proposed by a pair of influential senators aims to help move these projects along every step of the way but getting Congress to agree on anything — especially during an election year — figures to be a formidable challenge. In today’s RBN blog we examine the Energy Permitting Reform Act of 2024.
There’s been a frenzy of M&A activity in the Permian Basin the past couple of years, and in recent months many of the acquiring E&Ps have reviewed their expanded base of assets, determined which acreage, wells and future well sites are core to their business going forward, and initiated the process of divesting the rest. At the same time, others — including some producers that were part of the merger mania — are on the hunt for what they see as underappreciated assets with the potential to shine. Folks, we’re in the early stages of what you might call “The Great Permian Reshuffling” — a rapid-fire exchange of upstream assets in the nation’s most prolific shale play. In today’s RBN blog, we discuss a few of the most noteworthy “bolt-on” deals and what they tell us.
Crude-oil-focused wells in the Permian generate massive volumes of produced water, and E&Ps have made tremendous strides in dealing with it. Most important, a growing share of that water is being recycled for use in new well completions. But challenges remain. Deep disposal wells — a popular option for handling produced water — can spur seismic events, and shallow disposal wells can do the same and also negatively impact oil well integrity. As we discuss in today’s RBN blog, Permian E&Ps are taking an increasingly comprehensive, holistic approach to produced water management.
Guyana’s rise as a crude oil producer in recent years can only be described as meteoric. If forecasts from some of the most respected international agencies pan out, the South American country’s output may soon rival some of the world’s biggest offshore producers. But the developments there are not without some controversy: they’re the centerpiece of a dispute over the proposed Chevron-Hess merger, while neighboring Venezuela claims that much of Guyana’s oil reserves are actually within Venezuelan territory. In today’s RBN blog, we’ll take a deep dive into Guyana’s production, examining its grades, quality and export flows as it transforms into a major global supplier.
Over the past decade, the only significant growth market for U.S. crude oil and NGLs has been exports, with over 90% departing from the Gulf Coast. Exports via Gulf of Mexico ports have surged from about 1 MMb/d in 2016 to over 6 MMb/d last year. Great news for PADD 3 export facilities, right? Well, it’s not that simple. The distribution of barrels has been wildly uneven, resulting in significant winners, forlorn losers, and everything in between. And export volumes are still ramping up, as is the competition among marine terminals for crude and NGL export market share, with far-reaching consequences for producers, midstreamers and exporters. This is one of the core themes at our upcoming NACON conference, which is all about PADD 3 North American Crude Oil & NGLs and scheduled for October 24 at the Royal Sonesta Hotel in Houston. In today’s RBN blog, we’ll delve into the highly competitive liquids export landscape, consider some of the important factors driving flows one way or the other, and — fair warning — slip in some subliminal advertising for the NACON event.
Crude-oil-focused production in the Bakken still hasn’t fully recovered from its pre-COVID high, partly because the western North Dakota shale play continues to face takeaway constraints, especially for natural gas and NGLs. A couple of NGL pipeline projects in the works will certainly help, but will they be enough to enable the Bakken’s increasingly consolidated E&P sector to ramp up its crude oil production? And one more thing: How will the incremental NGLs flowing south on Kinder Morgan’s soon-to-be-repurposed Double H Pipeline find their way to fractionation centers in Conway and Mont Belvieu? In today’s RBN blog, we’ll look at the Bakken’s complicated production-vs.-takeaway conundrum and the ongoing efforts to address it.
In a refinery, crude oil is first distilled, which separates it into light, medium and heavy fractions. After that, refiners start performing chemical reactions to change the oil’s molecules from their natural form into those needed in modern fuels. But the catalysts used in that process aren’t only expensive, they essentially end up as hazardous waste at the end of their productive life. That helps to explain why there’s been a lot of interest in catalyst recycling, which advocates see as a way for refiners to improve both their profitability and their environmental performance. In today’s RBN blog, we continue our look into catalyst recycling — the technology, economics and trade-offs — and detail some of the pushback against it.