Daily Energy Blog

Back in the early 2010s, U.S. crude oil and NGL exports were minimal and LNG exports were non-existent, but there were omens that the U.S. would soon regain its status as an energy production juggernaut. Now the U.S. is a critically important global supplier of oil, gas and NGLs, with exports crucial to managing supply and demand as infrastructure rushes to keep up and industry players simultaneously explore alternative energy possibilities. How all these moving parts interconnect was the focus of RBN’s 18th School of Energy last week and it’s the subject of today’s RBN blog, which — fair warning! — is a blatant advertorial for School of Energy Encore, our newly available online version of the recent, action-packed conference. 

That the Supreme Court overturned the Chevron Deference, a key foundation of modern administrative law for 40 years, in its June 28 ruling in Loper Bright Enterprises v. Raimondo (Loper Bright) was no surprise, although it does not make it any less disruptive. The order follows a steady drumbeat of Supreme Court decisions issued during this term and in recent prior ones curbing the regulatory enforcement capabilities of Executive Branch agencies. But while this is a landmark case and would be expected to lead to a host of new legal challenges, its practical effect might end up being more nuanced. In today’s RBN blog, we revisit the Chevron Deference, why the Court said it had to go, and what it might mean for economic and environmental regulations impacting the energy industry. 

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. 

Refinery distillation units separate crude oil into light, medium and heavy fractions. After that, refiners start performing chemical reactions using catalysts — materials that accelerate chemical reactions — to change the oil’s natural molecules into the forms needed in modern fuels. In recent years, refiners have stepped up their efforts to recycle those catalysts to improve their profitability and environmental performance. In today’s RBN blog, we explain how catalysts, which were formerly disposed of as hazardous waste, are increasingly being recycled and reused in refineries. 

The March appropriations bill passed by Congress and signed by President Biden to fund the federal government mandated the emptying of the federal gasoline reserve in fiscal year 2024, which concludes September 30, followed by its eventual closure. That means about 1 MMbbl — 42 MM gallons — of gasoline will find its way to the market in the next few months, or in as little as a few weeks. The Department of Energy (DOE) is planning to distribute those barrels by the end of June to help keep a lid on gasoline prices ahead of the July 4 holiday and into the heart of the summer driving season. In today’s RBN blog, we look at the decision to close the reserve and the potential impact of those barrels hitting the market. 

The federal Renewable Identification Number (RIN) and California’s Low Carbon Fuel Standard (LCFS) have long served as tools to force renewable fuels like ethanol into the U.S. fuel supply. They are environmental credits that subsidize production of renewable fuels that would not otherwise be economically justified. Nuances embedded in the design of these credit systems have again kicked in to surprise the markets, this time with a hit to renewable diesel (RD) margins. Today’s RBN blog zeroes in on two root causes for that hit. 

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. 

How can a business survive and thrive while spending $5.30 to make a product that sells for $1.90? That’s what’s happening in the booming renewable diesel (RD) market, where government subsidies allow RD to compete directly with petroleum diesel even though RD is inherently more costly to produce. But as new plants keep coming on stream, RD profit margins are coming under closer scrutiny. In today’s RBN blog, we analyze RD profit margins and show how they are changing as the market continues to expand. 

The new 650-Mb/d Dangote refinery in Nigeria instantly became Africa’s largest and the world’s seventh-largest by capacity when it finally began processing crude into diesel and aviation fuels in January after years of delays and cost overruns. Long touted as Nigeria’s ticket to ending refined fuels imports by supplying its own markets — with plenty to spare for exports — the Dangote facility could substantially impact trade flows and global supply if it lives up to years of homegrown ballyhoo. In today’s RBN blog, we will examine Dangote’s long road to production, and why we see a slow ramp-up to full capacity through 2026. 

The boom in renewable diesel (RD) production has triggered a race to secure the dozen different bio-feedstocks suitable for refining into diesel fuel. It’s an interesting story that impacts both the oil and agriculture industries, with twists and turns that will take years to play out. In today's RBN blog, we describe the current state of the market and highlight recent happenings in supply chains for two of those increasingly important bio-feedstocks — soybean oil and used cooking oil. 

One of the most anticipated and potentially impactful refinery startups in North America in years is the Dos Bocas project (officially the Olmeca Refinery), a 340 Mb/d plant under development by Mexico’s state-owned Petroleos Mexicanos (Pemex) in the southeastern state of Tabasco. The project was seen as the cornerstone of Pemex’s plans to reduce Mexico’s dependence on the U.S. for refined fuels. Construction began in 2019 with startup originally scheduled for 2022, but that timeline was never really feasible, and the Mexican government has issued multiple public statements since mid-2023 proclaiming that construction was complete and startup was imminent. However, almost a year has passed and there is no indication that any meaningful operations have occurred. So how close is Dos Bocas to startup and, more importantly, full (or close to full) production? In today’s RBN blog, we’ll provide our views on those vitally important questions. 

The Biden administration recently announced a very ambitious — to say the least — rule on tailpipe emissions. But while the rule’s legal and political standing might be a bit uncertain — it’s seen by many as a de facto ban on conventionally fueled cars and trucks and is likely to face several court challenges — doubts also remain about whether it matches up with the realities of today’s energy world. In today’s RBN blog, we look at the new rule, what it would mean for U.S. consumers and automakers, and how it conflicts with the views of RBN’s Refined Fuels Analytics (RFA) practice on the future of global oil and refined products demand and the rate of electric vehicle (EV) adoption. 

The Environmental Protection Agency (EPA) has approved a request by governors from eight Corn Belt states to remove a summertime waiver for Reid Vapor Pressure (RVP) included in the Clean Air Act (CAA) for E10 gasoline, a 90/10 blend of petroleum-derived gasoline blendstock and ethanol. The motive for the governors’ request was a desire to increase sales of E15 gasoline and, by extension, boost ethanol/corn demand by putting it on the same summertime footing as E10. In granting the approval, the EPA conceded that the distribution system wasn’t ready for the change. In today’s RBN blog, we look at the decision and the impact it will have on refiners, retailers and drivers, and how it is likely to work against the Biden administration’s plans to keep a lid on gasoline prices. 

There’s always a risk when you take a new approach to doing or making something that your expectations won’t pan out — that something you hadn’t figured on happens and messes things up. But oh, the satisfaction that comes when the stars align exactly as you foresaw. The folks who developed Project Traveler, a recently completed Houston-area plant that produces high-value, octane-boosting alkylate from ethylene, isobutane and other widely available and low-cost feedstocks, know that good feeling, as we discuss in today’s RBN blog on the project’s economics.