Russia’s invasion of Ukraine and Europe’s subsequent pivot away from Russian natural gas caused a huge resurgence in interest in U.S. LNG. That led to nearly 60 MMtpa (7.9 Bcf/d) of new U.S. LNG capacity reaching a final investment decision (FID) in 2022-23. But regulatory delays at the Federal Energy Regulatory Commission (FERC), the Biden administration’s pause on non-free-trade-agreement (non-FTA) export licenses, and legal challenges to the FERC approval process have essentially halted LNG development in the U.S. There are several LNG projects with enough commercial momentum to move forward that are stuck in regulatory or legal limbo, but even projects that have reached FID are not safe from legal challenges. In today’s RBN blog, we conclude our series on LNG delays by looking at recent court rulings and other regulatory issues and their impact on U.S. LNG development.
Daily Energy Blog
The long-delayed rules around the federal government’s Hydrogen Production Tax Credit (PTC), also known as 45V, had been the subject of heated debate — and lobbying — since passage of the Inflation Reduction Act (IRA) way back in August 2022. But after more than a year of speculation — and with the Biden administration in its last days — the final rulemaking has at last been published. In today’s RBN blog, we’ll look at how the final rulemaking compares with the initial guidelines established in December 2023, detail the key areas where the rules have been made more lenient, and explain why clean hydrogen still faces an uncertain future, while also previewing our first Drill Down report of 2025.
At first glance, you might think that Phillips 66’s newly announced, $2.2 billion plan to acquire the EPIC NGL pipeline system, two fractionators near Corpus Christi and other NGL-related assets in Texas is just another logical step in the expansion of P66’s “well-to-market” NGL strategy — and you’d be right. But the story is actually much more interesting, involving a long list of well-known midstream players and a long-running, still-evolving effort to dilute the Mont Belvieu NGL hub’s dominance. In today’s RBN blog, we spill the tea.
In 2024, more than 9 billion gallons of propane were delivered to U.S. consumer markets, primarily for residential heating and cooking, with substantial volumes supporting the commercial, industrial, agricultural and transportation sectors. It is a physically complicated business because, unlike electricity and natural gas, which are delivered through wires and pipelines, respectively, the vast majority of the propane used by U.S. consumers is delivered by some combination of pipelines, rail cars and, ultimately, trucks. How does that complicated supply chain work in real life? In today’s RBN blog, we begin a detailed look at the U.S. propane market.
Alaska North Slope (ANS) crude oil production has been sliding for years — decades really — but that is poised to change in the second half of the 2020s. Two long-planned ANS projects — Pikka and Willow — are slated to start up in 2026 and 2029, respectively. By the early 2030s, these and other projects in the works could return North Slope production to levels not seen since the turn of the century. In today’s RBN blog, we’ll discuss these projects and our new, long-term forecast for ANS oil production — a topic in our upcoming Future of Fuels report.
The Marcellus/Utica is a natural-gas-and-NGLs play, right? Almost entirely, yes. But a handful of dogged, innovative E&Ps have been producing fast-rising volumes of superlight crude — better described as condensate — in the Utica Shale’s “volatile oil window” in eastern Ohio. In today’s RBN blog, we discuss recently ramped-up drilling-and-completion activity in that swath of the Buckeye State, the potential for more growth through the second half of the 2020s, and the impact of increasing output on Midwest midstreamers and refiners.
After a decade-long odyssey and a cost-per-mile that must make public-sector accountants in Ottawa wince, the Canadian government-owned Trans Mountain Expansion Project (TMX) — which nearly tripled the capacity of the original Trans Mountain Pipeline (TMP) from Alberta to the British Columbia (BC) coast — finally came into service in May 2024. As one of Canada’s most anticipated energy infrastructure projects in many years, the 590-Mb/d TMX pipeline — built alongside the long-standing 300-Mb/d TMP — was widely touted by its advocates as a surefire way to boost exports of Western Canadian crude and reduce the nation’s near-complete reliance on exporting crude oil to — and through — its primary customer, the U.S. In today’s RBN blog, we discuss some of the surprising (and not so surprising) market developments since the expansion project started.
Are you ready for Trumpian turmoil? Regardless of your opinion of the president-elect, you’ve got to acknowledge he’ll be shaking things up. In fact, with talk of a tariff blitz poised to disrupt global trade, mass deportations on deck, notions like reclaiming the Panama Canal, buying Greenland and even annexing Canada, the turmoil is already well underway. And of course, energy markets will be front and center, with “Drill, baby, drill” the stated oil and gas policy du jour. With so much uncertainty ahead, it’s impossible to predict what will happen in 2025, right? Nah. All we need to do is stick out our collective RBN necks one more time, peer into our crystal ball, and see what the new year has in store for us.
As 2023 wrapped up one year ago, it seemed there were a lot of moving parts out there in energy markets. Capacity constraints were back on the radar screen, and while prices appeared stable, they were overshadowed by the looming threat of escalating conflicts in Ukraine and the Middle East. Opportunities abounded for energy projects, including natural gas storage, export terminals, and just about any pipeline that moved supply to the Gulf Coast. However, challenges kept popping up, from project delays like those faced by Canada’s Trans Mountain Expansion Project (TMX) to concerns about excessive nitrogen in Permian natural gas and what eventually evolved into the Biden administration's LNG “pause.”
Many of this year’s most popular RBN blogs gravitated toward familiar energy market themes — rising exports, shifts in oil production, weak natural gas prices, surprising NGL pricing dynamics and the like. However, we also noted a significant uptick in interest in topics beyond the traditional energy realm, including hydrogen, carbon capture and sequestration (CCS), electric vehicles (EVs) and even the role of artificial intelligence (AI) and data centers. It’s not that RBNers have shifted their focus away from oil, gas and NGL markets. Rather, it reflects a growing recognition that the renewable and alternative energy landscape — fueled by regulations, subsidies and tax incentives — is reshaping the energy world. For anyone in the energy business, staying one step ahead (or maybe three steps) means understanding how these trends intersect with traditional energy markets. In 2024, our readers made it clear: The interplay between renewable and conventional energy commodities is becoming increasingly important.
As crude oil production in the Permian continues to grow and pipelines from West Texas to the Gulf Coast edge closer to full utilization, it’s becoming a challenge for producers and shippers alike. Amid this capacity crunch, one pipeline stands out as the only one with a detailed expansion plan: the 850-mile, 900-Mb/d Gray Oak Pipeline from West Texas to Corpus Christi and Sweeny, TX, which started up in late 2019 and became fully operational in early 2020. In today’s RBN blog — the latest in our series on Permian crude oil pipelines — we discuss Gray Oak Pipeline’s dynamic story, including its shifting ownership, strategic connectivity and expansion plans.
A primary objective of the federal Renewable Fuel Standard (RFS), when it was expanded back in 2007, was to stimulate by 2022 the production of at least 16 billion gallons/year of gasoline and diesel made from cellulosic biomass in conversion plants resembling small refineries. After getting lots of headlines in the early days of renewable fuels, that vision faded into the background and attention shifted to the use of ethanol in gasoline and the production of diesel from soybean oil, but cellulosic biofuels — non-food crops and waste biomass like animal manure, corn cobs, corn stalks, straw and wood chips — are back in the spotlight thanks to a regulatory quirk. In today’s RBN blog, the first in a series, we review the unusual history of the D3 Renewable Identification Number (RIN), the subsidy designed to stimulate cellulosic biofuel production, and the recent impact on heavy-duty trucking.
The pace of data center development accelerated in 2024, raising questions about how to power these energy-hungry behemoths. Natural-gas-fired plants are a go-to approach to helping local utilities provide the reliable, around-the-clock electricity that large-scale data centers need. Now, two giant oil and gas companies, ExxonMobil and Chevron, want to do something they’ve never done before: build gas-fired plants and sell power exclusively to data centers. And some utilities are partnering with big-tech companies on power plants of their own. In today’s RBN blog, we’ll discuss data center power needs and the unusual notion of building big gas plants to serve those customers.
Negative natural gas prices have been breaking hearts in the Permian Basin for many years, with pipeline development struggling to keep pace with rapid increases in associated gas production, but 2024 has shattered all previous records for the severity and length of negatively priced periods. The Matterhorn Express Pipeline, which started partial service at the beginning of October, is helping to stabilize the market for now, but with more production gains on the way, additional takeaway capacity will be needed. And after this year’s run of negative prices, producers have been willing to commit to new capacity.
The U.S. is now the world’s #1 supplier of LNG and the new liquefaction/export capacity slated to come online over the next few years suggest it will hold that position into the 2030s. To control more of the LNG value chain and become more familiar with the inner workings of the U.S. natural gas market, a small-but-growing number of LNG buyers and suppliers have been acquiring gas production assets close to LNG export terminals along the U.S. Gulf Coast — in other words, buying slices of the American gas-supply pie. In today’s RBN blog, we discuss the LNG market players pursuing this strategy, what they’ve been buying, and how their acquisitions may benefit them.
