Most Popular Blogs of 2023

A year ago, as New Year’s Day approached, we were looking ahead into very uncertain market conditions, having lived through a pandemic, crazy weather events, collapsing and then soaring prices, and Russia’s horrific invasion of Ukraine. Our job was once again to peer into the RBN crystal ball to see what the upcoming year had in store for energy markets. We’ll do that again in our next blog. But another part of that tradition is to look back to see how we did with our forecasts for the previous year. That’s right! We actually check our work. And that’s exactly what we’ll do today: review our prognostications for 2023. 

Continued growth in Permian crude oil production can’t happen without sufficient infrastructure — not just takeaway capacity for crude, natural gas and NGLs but also the capacity to process the fast-increasing volumes of associated gas being produced in the Midland and Delaware basins. The incremental need for processing capacity is enormous, as evidenced by the ongoing, almost frenetic build-out of gas processing plants across the Permian. More than 1 Bcf/d of new capacity is slated to come online by the end of this year, with another 1.9 Bcf/d in the first half of 2024 and another 1.8 Bcf/d after that. In today’s RBN blog, we discuss the race to add processing plants in key locations in West Texas and southeastern New Mexico and the drivers behind it. 

There’s a lot of nitrogen out there — it’s the seventh-most common element in the universe and the Earth’s atmosphere is 78% nitrogen (and only 21% oxygen). And there’s certainly nothing new about nitrogen in the production, processing and delivery of natural gas. That’s because all natural gas contains at least a little nitrogen. But lately, the nitrogen content in some U.S. natural gas has become a real headache, and it’s getting worse. There are two things going on. First, a few counties in the Permian’s Midland Basin produce gas with unusually high nitrogen content, and those same counties have been the Midland’s fastest-growing production area the past few years. Second, there’s the LNG angle. LNG is by far the fastest-growing demand sector for U.S. gas. LNG terminals here in the U.S. and buyers of U.S. LNG don’t like nitrogen one little bit. As an inert gas (meaning it does not burn), nitrogen lowers the heating value of the LNG and takes up room (lowers the effective capacity) in the terminal’s liquefaction train. Bottom line, nitrogen generally mucks up the process of liquefying, transporting and consuming LNG, which means that nitrogen is a considerably more problematic issue for LNG terminals than for most domestic gas consumers. So as the LNG sector increases as a fraction of total U.S. demand, the nitrogen issue really comes to the fore. In today’s RBN blog, we’ll explore why high nitrogen content in gas is happening now, why it matters and how bad it could get.

Considerable time and effort has been spent tracking the federal government’s plan to spend billions of dollars to create a number of regional hydrogen hubs. News about the Department of Energy’s (DOE) hub-selection process has been hard to come by, especially since the potential applicants weren’t publicly disclosed at the time of the agency’s informal cutdown in late 2022 and many potential developers, for competitive reasons, have elected to play their cards very close to the vest. In today’s RBN blog, we’ll publish the DOE’s full list of 33 encouraged proposals for the first time, examine some of the plans that were combined in an effort to produce a stronger joint application, and share a little about the concept papers that didn’t make the DOE’s informal cut.

Just a couple of years ago, TC Energy finally threw in the towel on its long-planned, long-delayed Keystone XL pipeline project, which would have substantially increased the flow of Western Canadian heavy crude to Gulf Coast refineries and export docks. It was a bitter loss. Since then, however, two other companies headquartered north of the 49th parallel have assumed leading roles in the U.S. crude oil market or, more specifically, crude exports. First, Enbridge acquired the U.S.’s #1 oil export terminal — now called the Enbridge Ingleside Energy Center (EIEC) — and related assets for US$3 billion and then, on August 1, Gibson Energy announced that it had closed on the US$1.1 billion purchase of the nearby South Texas Gateway (STG), which is #2 in crude export volumes. In today’s RBN blog, we discuss the increasing role of Canada-based midstream companies along the South Texas coast.

Back in the early 2000s, the outlook for energy security in the U.S. was bleak. Domestic oil production had been on a steady decline since 1985 and gas production was also well off its apex in the 1970s. M. King Hubbert’s concept of peak oil ignited fears of eventual energy scarcity. Given fossil fuels’ ubiquity underlying our entire Western economic and industrial structure, it’s no wonder that folks were concerned. But then the Shale Revolution changed everything. It’s often been said that necessity is the mother of invention and, after many trials and with considerable ingenuity, U.S. producers learned to wring massive volumes of previously trapped hydrocarbons from shale and gave the U.S. energy industry a new lease on life. But there are still limits on how much crude oil, natural gas and NGLs can be economically produced — and concerns lately that the best of the U.S.’s shale resources may have already been exploited. In today’s RBN blog, we examine crude oil and gas reserves: how they are estimated and what they tell us about the longevity of U.S. production.

Global crude oil markets are undergoing a profound transformation. But it is mostly out of sight, out of mind for all but the most actively involved players in the physical markets. On the surface, it’s a simple change in the Dated Brent delivery mechanism: Starting May 2023, cargoes of Midland-spec WTI — we’ll shorten that to “Midland” for the sake of clarity and simplicity — could be offered into the Brent Complex for delivery the following month. This change has been in the works for years. Production of North Sea crudes that heretofore have been the exclusive members of the Brent club has been on the decline for decades. Allowing the delivery of Midland crude into Brent is intended to increase the liquidity of the physical Brent market, thereby retaining Brent’s status as the world’s preeminent crude marker, serving as the price basis for two-thirds or more of physical crude oil traded in the global market. So far, the new trading and delivery process has been working well. Perhaps too well. For the past two months, delivered Midland has set the price of Brent about 85% of the time. The number of cargoes moving into the Brent delivery “chain” process has skyrocketed, and most of those cargoes are Midland. Is this just an opening surge of players trying their hand in a new market, or does it mean that the Brent benchmark price is becoming no more than freight-adjusted Midland? In today’s RBN blog, we’ll explore this question, and what it could mean for both global and domestic crude markets.

Three new LNG export projects have reached a final investment decision (FID) in the past year or so — Venture Global’s Plaquemines LNG, Cheniere’s Corpus Christi Stage III expansion, and, most recently, Sempra’s Port Arthur LNG. What do these projects have in common? They are all being developed by companies that are already exporting North American LNG. These companies are arguably the “Big Three” of U.S. LNG, with Cheniere the reigning king, at least for now. Not only do they all have at least one operating terminal and at least one under construction, but all three have multiple pre-FID projects under development, including some that are decently close to FID. With their proven track records and deep balance sheets, being one of the big guys is a definite advantage when it comes to getting a project across the finish line. With a total of 43.5 MMtpa (5.8 Bcf/d) of capacity currently under construction and more than 100 MMtpa (13.4 Bcf/d) under development by these three, is there even room for anybody else? In today’s blog, we look at the pre-FID projects under development by the Big Three, starting with Sempra.

The headwinds facing producers in the Permian, the Eagle Ford and other shale plays are trimming the valuations of oil and gas assets and making it easier for deep-pocketed acquirers and private-equity-backed sellers to reach deals. For proof, look no further than the ongoing frenzy of M&A activity in South and West Texas, where large and medium-size E&Ps alike continue to gobble up smaller producers with complementary assets. Their goals are one and the same: increase scale, improve efficiency, cut costs and build inventory in highly productive plays with easy access to Gulf Coast refineries, fractionation plants, and export docks for oil, LNG and NGLs. In today’s RBN blog, we discuss the most significant deals in the Lone Star State so far this spring and what they mean for the acquiring companies.

It would be an understatement to say we’re sensing a trend here. Over the past couple of years, there’s been an absolute frenzy of producer M&A activity in the Permian, much of it involving big E&Ps getting bigger and private equity cashing in on assets they’ve been developing since the 2010s. The latest multibillion-dollar deal involves Ovintiv, whose recently announced plan to acquire the Midland Basin assets of three EnCap Investments-backed producers will nearly double Ovintiv’s oil and condensate output in West Texas, lower its per-barrel production costs, and add more than 1,000 well locations to its inventory. Oh, and via a separate but related deal, Ovintiv will exit the Bakken by selling its assets there to another EnCap affiliate. In today’s RBN blog, we look at what the M&A artist formerly known as Encana is up to.