Weak refining margins, rising regulatory compliance costs, softening demand for gasoline and the push for lower-carbon alternatives like batteries and renewable diesel have each contributed to a steady decline in California’s refining capacity the past few years. Now, Phillips 66’s plan to idle its 139-Mb/d Los Angeles Refinery in Q4 2025 will leave the Golden State with only seven conventional refineries producing gasoline, diesel and jet fuel — a couple of dozen fewer than it had 40 years ago. In today’s RBN blog, we’ll put P66’s recent announcement in context and discuss the likelihood of additional refinery closures.
Daily Energy Blog
Oxygen-containing gasoline additives called oxygenates, including ethanol, have provided an octane boost to the U.S. gasoline pool since 2000. This has allowed refineries to reduce the octane of refinery-produced gasoline, which increases their gasoline production capacity and efficiency while simultaneously helping achieve the goals for cleaner, lower-carbon fuels derived from domestic renewable feedstocks. A new approach to gasoline formulation promises to take this “sharing” of the octane load much further to exploit the unique octane-enhancing qualities of ethanol, although there are some real-world challenges to wider implementation. In today’s RBN blog, we explain what’s behind the concept of “hydrogen-rich” gasoline.
As the Atlantic hurricane season churns out storms that regularly threaten the U.S. Gulf Coast, it can be easy to forget that the East Coast — an important refining center and refined-products market — is not immune from their impact. A dozen years ago this month, Superstorm Sandy roared ashore in New Jersey, wreaking havoc with storm surges and fierce winds that stretched for 1,000 miles. While the East Coast lacks the Gulf Coast’s concentration of energy infrastructure, it is home to the critical New York Harbor (NYH) market. In today’s RBN blog, we will examine how storms have affected the refining sector on the East Coast.
There’s been a lot of speculation about whether the pace of electric vehicle (EV) adoption has slowed, with JD Power now expecting EVs to make up 9% of U.S. new-car sales in 2024, down from its earlier estimate of 12.4% but still up from 7% in 2023. The group remains bullish on EVs in the long term, expecting market share to reach 36% by 2030 and 58% by 2035. The forecast from RBN’s Refined Fuels Analytics (RFA) group forecast has been — and continues to be — more conservative than most but still anticipates EVs will reach 50% of U.S. new-car sales by the early 2040s. In today’s RBN blog, we’ll look at what drives these forecasts and the anticipated impacts on gasoline demand.
Thousands of unionized dockworkers walked off the job at ports along the U.S. East and Gulf coasts October 1 in the first work stoppage for those regions since 1977. Three days later, they’re heading back to work with a tentative deal on wages in hand and an agreement to continue negotiating on other issues through mid-January. The strike didn’t threaten liquid exports like crude oil and LNG but imports of action figures and exports of plastic pellets used to make them — as well as other dry containerized products and feedstocks — hit a brief standstill. In today’s RBN blog, we’ll examine the potential fallout avoided by the labor agreement.
It now seems likely that Elliott Investment Management’s Amber Energy will acquire CITGO Petroleum for $7.3 billion in mid-2025, thereby ending a yearslong legal drama about the fate of CITGO’s three large U.S. refineries and related pipelines and terminal assets. So what exactly is Amber buying and how will the refineries in question fare in the increasingly competitive global market for refined fuels? In today’s RBN blog, we’ll summarize the long legal battle that led to Amber’s selection by a federal court’s “special master” as the preferred buyer, examine the assets to be acquired, and assess what’s ahead for CITGO’s refineries, which have a combined capacity of more than 800 Mb/d.
The hype around low-carbon-intensity (LCI) hydrogen that captivated many energy transition fans over the past four years has lost some momentum of late as industry players recalibrate their investment plans in the face of spiraling costs. Still, the U.S. government is moving full speed ahead — the Bipartisan Infrastructure Law (2021) and Inflation Reduction Act (2022) promise to flow billions of dollars into LCI hydrogen infrastructure via tax credits and other incentives. Which raises this question: Will LCI hydrogen make economic sense or not? In November 2021, the Department of Energy (DOE) asked the National Petroleum Council (NPC) to take a deep dive into the topic. In today’s RBN blog, we begin a review of the issues at hand.
Californians love their cars. Be it a lemon-yellow Lamborghini whizzing around Los Angeles freeways or a Jeep cruising the Pacific Coast Highway, getting behind the wheel is not just about coming of age — it’s a life goal in the Golden State. California also typically has the costliest gasoline in the U.S. (except when Hawaii holds that title), exacerbated by occasional price spikes and supply squeezes. The state responded in 2023 with a new law — SB X1-2 — designed in part to increase gasoline price transparency and assess potential ways to ensure consistent and affordable supply. In today’s RBN blog, we’ll examine the California Energy Commission’s (CEC) first assessment of the law’s impact.
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.
Some U.S. refiners report lower-than-market gasoline profit margins in the summer, which are often attributed to summer volatility specifications. But that is not always the primary issue; rather, some refiners have trouble generating enough octane-barrels due to the strong demand during the summer months, which can help drive price spikes. In today’s RBN blog we explain why, with a focus on octane, the primary yardstick of gasoline performance, quality and price, and show how refiners use a PIANO analysis to optimize their production.
More than a decade ago, several U.S. refiners brought new hydrocracking capacity online, wagering that rising demand for middle distillates made such major investments necessary. They were good bets. Demand for jet fuel is expected to continue to grow, and while diesel demand is seen as relatively flat in the U.S. over the next few years, it will continue to climb globally through 2045, according to RBN’s recently released Future of Fuels report. In contrast, the report also sees domestic gasoline demand declines accelerating post-2026 and peaking globally by about 2030, as more consumers turn to electric vehicles (EVs). These contrasting trajectories for middle distillates vs. gasoline will put a growing premium on distillate-centric hydrocracking capacity. In today’s RBN blog, we’ll examine trends incentivizing hydrocracking capacity and how these units will allow U.S. refiners to maintain their competitiveness in a rapidly changing product market.
The last few years have been filled with often-spirited debate about the global energy transition and the move away from fossil fuels to fully embrace renewables and alternatives to keep the lights on, fuel vehicles and power the world’s economy. But there are a growing number of signs that a swift shift from petroleum is not realistic, which has implications in many areas, including which refinery expansion projects move forward (and where), when oil demand might peak, and which of the many forecasts for gasoline and distillate production will prove to be the most accurate. In today’s RBN blog, we discuss highlights from the new Future of Fuels report by RBN’s Refined Fuels Analytics (RFA) practice, including RFA’s expectations for how a slower transition might affect producers, refiners and consumers.
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.