Posts from Rusty Braziel

There’s never been any reason to question the drivers for energy infrastructure development — until now.  Historically, the drivers were almost always “supply-push.” The Shale Revolution brought on increasing production volumes that needed to be moved to market, and midstreamers — backed by producer commitments — responded with the infrastructure to make it happen. But now things seem to be different. U.S. energy infrastructure investment is soaring across crude oil, natural gas and NGL markets and, as in previous buildouts, midstreamers are bringing on new processing plants, pipelines, fractionators, storage facilities, export terminals and everything in between. We count nearly 70 projects in the works. But crude production has been flat as a pancake, natural gas is down, and lately NGLs are up — but as you might expect, only in one basin: the Permian. So what is driving all the infrastructure development this time around? In today’s RBN blog, we’ll explore why that question will be front-and-center at our upcoming School of Energy: Catch a Wave. Fair warning, this blog includes an unabashed advertorial for our 2024 conference coming up on June 26-27 in Houston. 

There’s never been any reason to question the drivers for energy infrastructure development — until now.  Historically, the drivers were almost always “supply-push.” The Shale Revolution brought on increasing production volumes that needed to be moved to market, and midstreamers — backed by producer commitments — responded with the infrastructure to make it happen. But now things seem to be different. U.S. energy infrastructure investment is soaring across crude oil, natural gas and NGL markets and, as in previous buildouts, midstreamers are bringing on new processing plants, pipelines, fractionators, storage facilities, export terminals and everything in between. We count nearly 70 projects in the works. But crude production has been flat as a pancake, natural gas is down, and lately NGLs are up — but as you might expect, only in one basin: the Permian. So what is driving all the infrastructure development this time around? In today’s RBN blog, we’ll explore why that question will be front-and-center at our upcoming School of Energy: Catch a Wave. Fair warning, this blog includes an unabashed advertorial for our 2024 conference coming up on June 26-27 in Houston. 

Growth for growth’s sake. In the early years of the Shale Revolution, that’s what it was all about. Backed by billions of dollars in Wall Street borrowings, E&Ps plowed vast piles of cash into increasing production. It was the era of “Drill baby drill!” And we all know what happened next. Rabid production growth contributed to oversupply and crude oil prices crashed. But resilient E&Ps clawed their way back by adopting what we now know as capital discipline, initially in fits and starts. Then, after the COVID price meltdown, they went all-in, elevating free cash flow generation to Job #1 and returning a significant portion of cash flow to shareholders. It worked! Financial markets started to think of E&Ps more as yield vehicles than growth plays. But it is in the DNA of oil and gas producers to grow. And now that U.S. crude prices are above $85/bbl, could we see a backslide toward organic growth — a 2024 rendition of “Drill baby drill”? In today’s RBN blog, we’ll explore the historical context of E&Ps’ transition to capital discipline and what it tells us about what’s coming next. 

Think energy markets are getting back to normal? After all, prices have been relatively stable, production is growing at a healthy rate, and infrastructure bottlenecks are front and center again. Just like the good ol’ days, right? Absolutely not. It’s a whole new energy world out there, with unexpected twists and turns around every corner — everything from regional hostilities, renewables subsidies, disruptions at shipping pinch points, pipeline capacity shortfalls and all sorts of other quirky variables. There’s just no way to predict what is going to happen next, right? Nah. All we need to do is stick our collective RBN necks out one more time, peer into our crystal ball, and see what 2024 has in store for us. 

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. 

Crude oil, natural gas and NGL production roared back in 2023. All three energy commodity groups hit record volumes, which means one thing: more infrastructure is needed. That means gathering systems, pipelines, processing plants, refinery units, fractionators, storage facilities and, above all, export dock capacity. That’s because most of the incremental production is headed overseas — U.S. energy exports are on the rise! If 2023’s dominant story line was production growth, exports and (especially) the need for new infrastructure, you can bet our blogs on those topics garnered more than their share of interest from RBN’s subscribers. Today we dive into our Top 10 blogs to uncover the hottest topics in 2023 energy markets. 

It’s the 10-year anniversary of a polar vortex winter that’s seared into the memories of every propaner who lived through it. Shortages. High prices. Government inquiries. Sure, there were difficulties during that winter in the markets for natural gas and fuel oil too, but it was particularly bad for propane. It seemed like a perfect storm hit the propane market right where it hurt the most — in the heart of propane country: the Upper Midwest and the Northeast. A lot has changed since then, but it’s important to look back at what went wrong, what’s been done to make a repeat of that chaotic winter far less likely, and what those events still mean for the propane market today. 

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. 

Well, thanks to you all, we reached another important milestone this week: 40,000 subscribers to RBN’s daily blog. We are quite proud of the achievement. That’s a lot of folks taking time out of their busy day to read a couple thousand words about what’s happening with oil, gas, NGLs and renewables — all in the context of a rock & roll song. We couldn’t have done it without you. Today, after posting a total of about 3,000 blogs over nearly 12 years, we pull back the curtain on the RBN blogosphere and discuss how and why it all happens — and how you help shape what we blog about. 

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.

There’s a lot going on in North American crude oil markets these days. Exports are running strong. Midland WTI is now deliverable into Brent (but only if it meets specs). Pipelines from the Permian to Corpus Christi are maxed out, pushing incremental production to Houston. The price differential between WTI at Midland and Houston is nearing zero. And the value of heavy Western Canadian Select (WCS) delivered to the U.S. continues to bounce all over the place. Are these unrelated, random events in the quirky U.S. physical crude market, or are they logical developments linked by the economics of refinery preferences, quality shifts, export demand, and logistics? As you might expect, we think it’s the latter. Believe it or not, crude markets sometimes do behave rationally — and, from time to time, even predictably. That’s what we explore in today’s RBN blog.

A great deal of attention has been heaped on the carbon-capture industry over the past couple of years, from its inclusion in major federal legislation such as 2021’s infrastructure bill and last year’s Inflation Reduction Act, plus all sorts of recently announced carbon sequestration projects. Still, there are plenty of concerns that the technology is not fully baked, that many of the projects are not ready for prime time, and that few have the practical know-how to deploy carbon capture and sequestration (CCS) at scale. But what if there was a company that has been doing carbon sequestration for a very long time — decades in fact? And what if that company has built out a huge carbon dioxide (CO2) collection, distribution and sequestration system on the Gulf Coast along with concrete plans for a massive expansion of this network to capture a lot more manmade, “anthropogenic” CO2, not in decades but in just a few short years? A company like that would be pretty much the ideal acquisition candidate for a cash-flush multinational with big ESG goals and strategies, right? As we discuss in today’s RBN blog, that is just what is happening with ExxonMobil’s acquisition of Denbury, a deal that will create today’s undisputed leader in CCS.

Crude oil exports hit 5.6 MMb/d last week, the second-highest level in EIA stats ever. Exports in the first six months of the year have averaged 4.1 MMb/d, 28% — or nearly 1 MMb/d — higher than the same period in 2022. And with Midland WTI crude now deliverable into global benchmark Brent, even more exports are on the way. Which makes it ever more important to understand how physical spot crude oil is priced at Gulf Coast export terminals.  After all, exporters only move crude off the dock when they can make money doing so — well, at least most of the time. And that depends on what it costs to get a given crude grade to the dock, what it’s worth when it gets there, the cost of shipping to overseas destinations, and the price realized when the cargo lands there. To shed more light on those export economics, in today’s RBN blog, we continue our exploration of crude oil pricing in the markets for physical U.S. and Canadian crudes. 

There is no debate about it: The CME/NYMEX domestic sweet (DSW) crude oil futures prompt-month contract at Cushing, OK, is the most closely followed benchmark in U.S. energy markets. It’s the price quoted in nightly news reports and general media publications. And now, with U.S. exports of WTI deliverable on the Brent contract, domestic sweet at Cushing is arguably setting the price for crudes around the world. But the fact is, most crudes traded in physical markets across North America are not priced at the DSW-at-Cushing benchmark but instead at a differential to Cushing — higher or lower on any given day based on each crude’s unique quality, location, and supply/demand characteristics. In today’s RBN blog, we discuss how the behavior of differentials from the Cushing benchmark can go a long way to explain what is happening with crude oil production, transportation volumes, storage and, of course, exports.

Crude oil exports are hitting record volumes. Geopolitical dislocations, regional capacity constraints, and transport cost aberrations are upending global trade flows. These developments have a direct impact on U.S. export grades, prices, and the utilization of pipelines and terminals. Petroleum product exports have an equally formidable set of challenges. U.S. surpluses of refined products are growing as domestic demand falls and biofuel penetration increases. The impact will translate directly into shifts in flows between PADDs, the repurposing of infrastructure, and more exports from the Gulf Coast. We’ll be exploring these and many more developments at our upcoming conference, xPortCon-Oil 2023, to be held in Houston on June 8, 2023. In this blatantly advertorial blog, we will introduce the major topics to be covered at the conference, who will be participating, and why we believe this will be the most important industry gathering for crude and products markets this year.