Rapidly rising prices for goods and services have plagued the economy since the onset of the pandemic — and led the Federal Reserve to ratchet up interest rates to help cool things off. Despite strong signs that overall inflation is receding, the negative impacts are far from over. Like every other sector, the U.S. E&P industry faced soaring costs as it struggled to restore production after widespread shut-ins in the spring of 2020. However, in recent Q2 2023 earnings calls E&P executives provided guidance that suggested that costs had not only plateaued but might actually decline in 2024 and beyond. In today’s RBN blog, we discuss updated 2023 capital spending guidance for U.S. oil and gas producers and their early outlook for 2024 investment.
Analyst Insights are unique perspectives provided by RBN analysts about energy markets developments. The Insights may cover a wide range of information, such as industry trends, fundamentals, competitive landscape, or other market rumblings. These Insights are designed to be bite-size but punchy analysis so that readers can stay abreast of the most important market changes.
Enbridge is floating an open season to solicit interest from potential shippers for an increase in service as part of an expansion project on Algonquin pipeline. The project, Project Maple, would expand capacity on the Algonquin gas system by up to 750 MMcf/d, 500 MMcf/d at the Ramapo, N.Y., rec
Overall U.S. LNG feedgas dropped last week, as Cove Point LNG shuts for annual maintenance.
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Daily Energy Blog
Over the past three-plus years, Corpus Christi has dominated the U.S. crude oil export market, largely because of the availability of straight-shot pipeline access from the Permian to two Corpus-area terminals at Ingleside — Enbridge Ingleside Energy Center (EIEC) and South Texas Gateway (STG) — that can partially load the huge 2-MMbbl VLCCs (Very Large Crude Carriers). But capacity on the pipes to Corpus is now nearly maxed out and, with Permian production rising and exports strong, an increasing share of West Texas crude output is instead being sent to Houston on pipelines with capacity to spare. The catch for Permian shippers with capacity on Permian-to-Houston pipes is that the Midland-to-MEH (Magellan East Houston) price differential for WTI has been depressingly low —$0.22/bbl on average this year, compared to almost $20/bbl for a few months in 2018 and averaging $5.50/bbl as recently as 2019. However, the Midland-to-MEH WTI price spread looks to be on the verge of a rebound of sorts, as we discuss in today’s RBN blog.
Clean ammonia, which is produced by reacting clean hydrogen with nitrogen and capturing and sequestering the resulting carbon dioxide (CO2), is gaining momentum. In just the past few months, several more new clean ammonia production projects have been proposed along the U.S. Gulf Coast, many of them made possible by commitments from Japanese and South Korean companies that see the low-carbon fuel as an important part of the Far East’s future energy mix. Taken as a group, the dozen-plus projects now under development have the potential to produce tens of millions of tons of clean ammonia annually, and to create yet another massive energy-export market for U.S. producers. In today’s RBN blog, we discuss the new projects moving forward — and one being put on hold — and what’s driving the clean ammonia market.
The U.S.’s effort to prioritize low-carbon energy entails some bumps and bruises along the way, an indication that the energy industry’s trilemma of availability, reliability and affordability can conflict with today’s economic realities and environmental priorities, even in a state like California with abundant financial and clean-energy resources and a commitment to decarbonization. In today’s RBN blog, we look at the state’s lofty goals to phase out fossil fuels, why it has been forced to put its transition away from natural gas and nuclear power on hold, and some of the biggest challenges ahead for the Golden State.
Is the glass half-full or half-empty? The answer to that age-old question usually indicates whether a particular situation is a cause for optimism or pessimism. That question is particularly appropriate when trying to place in perspective the cyclical movement of the earnings and cash flows of U.S. exploration and production (E&P) companies, including returns that have steadily declined with commodity prices over the last year. In today’s RBN blog, we analyze Q2 2023 E&P earnings and cash flows and provide some perspective on the past and future profitability of U.S. oil and gas producers.
A draft environmental impact statement (DEIS) tied to a key water crossing along the Dakota Access Pipeline (DAPL) has finally been completed and made public, thereby ending another chapter in the long-running drama about the ultimate fate of DAPL, which is by far the largest crude oil pipeline out of the Bakken. While the DEIS doesn’t finish the story, the document provides hints about possible outcomes — and an opportunity to review just how important the 750-Mb/d pipeline really is to Bakken producers and shippers. In today’s RBN blog, we discuss the latest developments regarding DAPL and Bakken production.
It’s no secret that the past several months have been challenging for the wind power industry, especially when it comes to offshore projects. Major developers have sought to renegotiate power-purchase agreements (PPAs) signed years ago, delayed work on some projects, and walked away from others, despite severe financial repercussions in some cases. On top of all that, only one of three offshore tracts available in the U.S.’s first Gulf of Mexico lease auction for wind power attracted any bids. It all amounts to a major setback in the Biden administration’s goal for the nation’s electricity to be 100% carbon-free by 2035. In today’s RBN blog, we look at the significant challenges being faced by wind power developers, what they mean for the projects currently under development, and some changes that could eventually help bring more of the renewable power online.
The CME/NYMEX Henry Hub prompt natural gas futures prices have been relatively rangebound this injection season and have averaged around $2.60/MMBtu since June — a third or less of where prices stood during the same period last year, in the $7-$9/MMBtu range, and at or below most natural gas producers’ breakeven costs. Yet, this is a much rosier scenario than it could have been considering that the first quarter of 2023 was one of the most bearish in over a decade and led to a massive storage surplus vs. last year that persisted through much of the summer. Since setting the year-to-date monthly average low of $2.19/MMBtu in April, prompt futures rose to an average of nearly $2.50/MMBtu in June, ~$2.65/MMBtu in July and August, and have mostly stayed in the $2.50-$2.75 range in September to date. In today’s RBN blog, we break down the factors that kept prices from unraveling this injection season to date and the implications for the rest of the shoulder season.
The M&A boom in the Permian and Eagle Ford continues unabated. Lately, a multitude of E&Ps have built scale and increased profitability by acquiring other producers that control acreage and produce crude oil, natural gas and NGLs themselves. But it’s also possible for an E&P to boost its holdings by acquiring incremental working interests in its operated assets or by having an affiliate acquire royalty and mineral interests in acreage the producer plans to develop. In today’s RBN blog, we discuss the most recent M&A activity in two of the U.S.’s leading production areas, including Viper Energy Partners’ planned $1 billion purchase of mineral and royalty interests in the Permian; Crescent Energy’s plan to acquire incremental working interests in South Texas; and an old-school, bolt-on acquisition by Magnolia Oil & Gas, also in the Eagle Ford.
While the weather-related headlines might still scream “summer” in some places — from stifling heat to powerful hurricanes to downpour-induced mud bogs at Burning Man in the Nevada desert — we’ve actually turned the corner into meteorological fall. Oil and gas prices have moved up from their Q2 2023 lows and supply issues, particularly for oil, are the chief concerns as the heating season approaches. Long-term production by the Diversified E&P peer group, whose production streams are weighted 40%-60% for gas and oil, respectively, are a major factor in U.S. supply. In today’s RBN blog, we analyze the crucial issue of reserve replacement by the major diversified U.S. producers.
The Permian is in the midst of an NGL infrastructure boom as midstream companies are investing to keep up with the strong production growth projected over the next several years — but until these new projects are up and running, NGL pipeline capacity to the Gulf Coast is only going to get tighter. In today’s RBN blog, we look at five pipeline projects that are under construction or in the planning process that would significantly boost NGL takeaway capacity out of the Permian.
After being relegated to the back burner during the shale boom, the natural gas storage market is showing signs of a comeback. Market participants are clamoring for storage solutions, storage values are rising, and storage deals and expansions are bubbling up. However, that won’t necessarily lead to a widespread build-out of new storage capacity like the one that transpired in the pre-shale storage heyday of the mid-to-late 2000s. That’s because the world has changed, and what’s driving storage values today is vastly different than what drove the last big capacity build-out. In today’s RBN blog, we look at the emerging developments in the storage market, what’s driving them, and the implications for Lower 48 storage capacity.
What a difference a year makes! The summer of 2022 was a golden age for U.S. E&Ps that embraced a dramatic shift in their business model from prioritizing growth to a focus on maximizing cash flows and emphasizing shareholder returns. Oil prices over $90/bbl and gas prices hovering about $7/MMBtu filled their coffers and funded lavish increases in share repurchases and dividends. But those golden days quickly faded as oil prices retreated and gas prices plunged 66% to just above $2/MMBtu. In today’s RBN blog, we explain how E&Ps are scrambling to sustain shareholder return programs in the face of shrinking cash flow.
Permian producers are churning out ever-increasing volumes of associated gas, all of which needs to find a home. New or expanded takeaway pipelines to Gulf Coast markets are an obvious option — and a few projects are in the works — but locking in capacity requires long-term commitments that many producers are loathe to make. As a result, the balance between Permian takeaway capacity and the volumes of gas that need to exit the basin is always on a knife’s edge, often resulting in a Waha basis so ugly that producers are essentially giving their gas away. But what if there was a way to put more Permian gas to good, economic use within the basin, and ideally very close to where it’s produced? Better yet, what if the producers could garner some environmental cred in the process? In today’s RBN blog, we discuss a trio of Permian projects — a couple of them involving top-tier E&Ps — that would use local gas to make gasoline, sustainable aviation fuel (SAF) and electricity.
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.
For many years now, the U.S. has been buying — and piping or railing in — virtually all of the crude oil Canada has been exporting, in part because Canadian producers have only very limited access to coastal ports. More recently, greater pipeline access from the Alberta oil sands to the U.S. Gulf Coast (USGC) has created an attractive pathway — a “Carefree Highway,” if you will — for Canadian crude oil to be “re-exported” to overseas customers. This year, much stronger international demand has sent re-export volumes to record highs — and provided Alberta producers very attractive price differentials for their oil sands crude. That overseas demand appears to be sustainable, but with the looming startup of the 590-Mb/d Trans Mountain Expansion Project (TMX), which will increase the capacity of the Trans Mountain Pipeline system to 890 Mb/d and enable much more Alberta crude to be exported from docks in British Columbia, the re-export surge from the USGC may be in for a pullback, as we discuss in today’s RBN blog.