As crude oil exports have become an integral part of US/Canadian trading, the market has evolved to accommodate this profound transformation. But the mechanisms used to price many of the most significant export grades are obscure and little understood outside a small cadre of professional traders and marketers. This is particularly true for the most liquid grades that employ a trading approach known as “exchange trading” or “spread trading,” in which volumes at regional hubs are valued in buy-sell transactions against domestic sweet crude at Cushing. In this context, “exchange trading” does not mean trading on a regulated exchange. Instead, it means trading via an exchange of barrels between buyer and seller. In today's RBN blog, we delve into some of the most complex aspects of this trading mechanism.
Last August, we titled our review of Q2 2022 E&P financial results Camelot after rising oil prices and surging natural gas realizations drove revenues, profits and cash flows to levels that seemed like an unrealizable dream for producers that had teetered on the brink of financial instability just two years before. Recent year-end results revealed the strongest returns in the industry’s history, much of which were distributed to long-suffering shareholders. But dreams fade and prices retreat, and Q4 2022 results suggest a far less idyllic 2023. In today’s RBN blog, we review the record 2022 performance and more sobering Q4 results.
Trading in the highly integrated US/Canadian crude oil market is undergoing a profound transformation, driven mostly by the pull of exports off the Gulf Coast. But the shifts in flows, values and even the trade structures being used today are not well understood outside a small cadre of professional traders and marketers. Consider a few examples: Domestic sweet oil traded at Cushing on NYMEX is not West Texas Intermediate — WTI at Cushing has averaged a hefty $1.80/bbl over NYMEX for the past year. Most spot Houston and Midland crudes trade as buy-sell swaps. WTI in Houston trades at a discount to Corpus Christi and sweet crudes in Louisiana. Crude in Wyoming trades at a premium to Cushing. And the Gulf Coast is the highest-value market for Canadian heavy crude. This is not your father’s (or mother’s) oil trading game. Our mission in this blog series is to pull back the curtain on physical crude trading in North America, explain how it works, what sets the price, and who is doing the deals.
In small steps and giant leaps, Enbridge has been building out two “supersystems” for transporting crude oil to refineries and the company’s own export terminals along Texas’s Gulf Coast, one moving heavy crude all the way from Alberta’s oil sands to the Houston area and the other shuttling light oil from the Permian to Enbridge’s massive terminal in Ingleside on the north side of Corpus Christi Bay. There’s nothing quite like it — first, an unbroken series of pipelines from Western Canada to Enbridge’s tank farm in Cushing, OK, (via the Midwest) and from there to Freeport, TX, on the twin Seaway pipelines; and second, the Gray Oak and Cactus II pipes from West Texas to the U.S.’s #1 crude export terminal. And the midstream giant is far from done. New projects and expansions are in the works, as we discuss in today’s RBN blog.
Over the past couple years of energy market turbulence, pretty much everyone has come to acknowledge that the U.S. — and the rest of the world — will continue to require refineries and refined products for decades to come. It’s also likely, though, that U.S. refiners, like their European counterparts, will be required to do more to reduce the volumes of carbon dioxide (CO2) and other greenhouse gases (GHGs) generated during the process of breaking down crude oil and other feedstocks into gasoline, diesel, jet fuel and other valuable products. And, thanks to new federal incentives, it might even make sense for refineries to capture and sequester at least some of the CO2 they can’t help but produce. In today’s RBN blog, we begin a series on refinery CO2 emission fundamentals, the differing policies that are applied here in the U.S. and abroad, and how those policies might ultimately influence refining competitiveness.
The wave of M&A activity in South Texas apparently hasn’t crested yet. Over the past couple months, Chesapeake Energy announced two deals totaling $2.825 billion that will almost complete its planned departure from the Eagle Ford — and signal UK-based INEOS’s arrival in the basin and a more than doubling of WildFire Energy’s production there. Just as important, Western Canada’s Baytex Energy a few days ago unveiled a $2.5 billion plan to acquire Ranger Oil, a pure-play Eagle Ford E&P, and thereby triple its South Texas production and gain its first operating capability in the U.S. And international interest in the basin doesn’t end there — Spanish energy giant Repsol, which had previously acquired the share of an Eagle Ford partnership held by Norway’s Equinor, recently bought basin assets held by Japan’s INPEX. (How’s that for multi-national M&A?) In today’s RBN blog, we discuss the latest round of E&P acquisitions and sales in South Texas, where production has been on the rebound.
For the first 10 years of the Shale Revolution, it was a foregone conclusion: High prices stimulated more drilling, and more drilling meant higher production. It worked in both directions. When prices crashed, so did production. The correlation was great. The relationships were right on cue in 2014-15 when $100/bbl crude crashed to $30, rebounded to $60 by 2019, and wiped out in 2020 when the COVID meltdown hit. But then the market shifted. As prices ramped up in 2021 — eventually to astronomical levels in 2022 — the phenomenon of producer discipline kicked in, with E&Ps capping their drilling programs and returning a significant slice of their rising free cash flow to their shareholders. The near-term market implications of this new dynamic have been extensively documented in the RBN blogosphere. But what does it mean for the future? Especially for intrepid energy analytics companies (like RBN) that, by necessity, must project producer behavior far into the future to determine what production will look like next year, next decade and even further over the horizon. In this new RBN blog series, we will examine that dilemma, the assumptions RBN makes, and what our forecasts for the next few years look like.
The numbers don’t add up. Literally. The most closely watched energy statistics in the world have a problem, and it’s been getting worse over the past two years. We’re talking about EIA’s U.S. crude oil supply, demand and inventory balances, which are published each week and then trued up about 60 days later in monthly data. The problem is that the balances don’t balance. EIA uses a plug number alternatively called “adjustment” or “unaccounted for” to force supply and demand to equate. That would not be an issue if the plug number was small and flipped frequently from positive to negative, likely due to timing inconsistencies with the input data. But that’s not the case. The number is mostly positive, meaning more demand than supply. And the difference can be mammoth: last week it was 2.3 MMb/d, or 18.4% of U.S. crude production. It seems like barrels are somehow materializing out of nowhere. But now we know where, because EIA just finished a 90-day study of the crude imbalance that reveals the sources of the problem and what it is going to take to fix it. In today’s RBN blog, we will delve into what has been causing the problem, what it means for interpreting EIA statistics, and what EIA is doing to address the issues.
Oil and gas production in the Shale Era is a refined, controlled process — and a far cry from the early days of wildcatting a century ago. Modern drilling typically involves multiple wells on a single well pad, with each well going through a four-stage process to produce hydrocarbons that are then separated into distinct components. In today’s RBN blog, we look at how drilling-and-completion techniques have evolved over the years, from old-school vertical wells to the highly complex strategies targeting shale areas today, and how they set the stage for hydrocarbon production and recovery.
Production of waxy crude in the Uinta Basin is up by more than half since mid-2021 and E&Ps there would like to produce more — the dense, slippery hydrocarbon is in high demand, not just by refineries in nearby Salt Lake City but also by at least a few of their Gulf Coast counterparts. Producers seem to have a handle on transporting increasing volumes of the stuff to market by truck and rail. The problem is, waxy crude emerges from Uinta wells with associated gas that needs to be piped away, the gas pipelines out of the play are nearing capacity, and addressing the takeaway constraints is a very complicated matter. In today’s RBN blog, we discuss the northeastern Utah play’s gas-takeaway concerns and the prospects for continued growth in waxy crude production.
Russia’s invasion of Ukraine in February 2022 set off a wave of repercussions in energy markets and economies the world over. The hope of the U.S. and its allies has been that international pressure and mounting sanctions would cause Russia to swiftly end the war — or at least make it very difficult to finance. But while the war rages on and Russia seems to be coping with the short-term impacts reasonably well, the long-term effects on its energy sector could be much more significant. In today’s RBN blog, we look at how Russia’s twin challenges — finding buyers for its crude oil and its refined products — are more different than they might seem and why Russia’s oil-and-refining sector is in the early stages of a sustained slowdown.
For several years now, almost all the Permian’s incremental crude oil production has moved to export markets along the Gulf Coast. Due to new pipeline capacity and shipping cost advantages, Corpus Christi has enjoyed a disproportionate share of those volumes. But the market is shifting. Pipelines to Corpus are filling up, and that is pushing more oil to Houston for export — and to Beaumont for ExxonMobil’s new 250-Mb/d refinery expansion. Unless the pipes to Corpus expand their capacity, much more oil supply will be targeting Houston, with important implications for pipeline capacity, dock capacity, and regional price differentials. In today’s RBN blog, we explore these issues and what could throw a curveball into the whole Gulf Coast crude oil market.
Times are good indeed in the Uinta Basin in northeastern Utah, where one of the world’s most unusual — and, in many ways, most desirable — crude oils is being produced with increasing efficiency and in fast-rising volumes. Yes, production of the Uinta’s trademark waxy crude is up by more than 50% in the past year and a half, to record-shattering levels, and demand for the dense, slippery hydrocarbon, with its minimal sulfur content, next-to-no impurities and favorable medium-to-high API numbers, is up too. Waxy crude may be a pain in the butt to transport and store — it needs to be kept warm to remain in a liquid state — but it is a staple at the five refineries in nearby Salt Lake City, and at least a handful of Gulf Coast refineries want as much of the stuff as they can get their hands on because of its desirable qualities. But without infrastructure enhancements, there may be limits to how much Uinta production can grow from here, as we discuss in today’s RBN blog.
Over the next couple of years — and the next couple of decades — global supply/demand dynamics in refined products markets will be driven by two critically important factors. The first is the understandable reluctance of refiners to expand capacity in the face of climate policy and ESG headwinds. The second is a growing gap between policymakers’ aggressive energy-transition goals and the global pivot to a renewed focus on energy security brought about by the Russia-Ukraine war and worries about China’s global ambitions. These factors, which will fuel the prospects for constrained supply and higher-for-longer demand, have far-reaching implications, not only for refinery owners but also for E&Ps, midstreamers, exporters, energy industry investors and policymakers, all of whom need to gain a clearer understanding of what’s just ahead — and what’s over the horizon, just out of sight. In the encore edition of today’s RBN blog, we discuss key findings in “Future of Fuels,” a new, in-depth report by RBN’s Refined Fuels Analytics practice on everything you need to know about U.S. and global supply and demand for gasoline, diesel, jet fuel and biofuels over the short-, medium- and long-term.
It’s been an awesome run for the Port of Corpus Christi’s crude oil export business, which captured about 60% of total U.S. volumes in 2022, up from only 28% in early 2018. But the rate of increase has slowed way down, even though shipping economics give Corpus a distinct advantage. The problem? Pipeline capacity, or more accurately, a lack thereof. The pipelines from the Permian to Corpus that were the driving force behind the Corpus export success story are filling up. The only questions are, how much time is left before the pipes are truly maxed out and what is likely to be done about it? In today’s RBN blog, we examine the data to see what it reveals about the looming capacity constraints.