There’s a lot to like about the unusual, waxy crude oil produced in the Uinta Basin in northeastern Utah. Low production costs, minimal sulfur content, next-to-no contaminants, and favorable medium-to-high API numbers. Oh, and there’s plenty of the stuff — huge reserves. The catch is that waxy crude has a shoe-polish-like consistency at room temperature, and has to be heated into a liquid state for storage and transportation. As you’d expect, refineries in nearby Salt Lake City are regular buyers; they receive waxy crude via insulated tanker trucks. They can only use so much though. Lately, a couple of Gulf Coast refineries have been railing in occasional shipments of waxy crude, but getting it onto heated rail cars involves a white-knuckle tanker-truck drive across a 9,100-foot-high mountain pass to a transloading facility. Now, finally, crude-by-rail access from the heart of the Uinta is poised to become a reality, offering the potential for much easier access to distant markets and, possibly, a big boost in Uinta production. In today’s blog, we provide an update on waxy crude and its prospects.
When fully loaded, a Very Large Crude Carrier (VLCC) sits so low in the water that it almost resembles an alligator swimming along the surface of a lagoon. Bearing the weight of 2 MMbbl of crude oil, plus ballast, fuel, crew, and provisions — not to mention the ship itself — two-thirds of an oil-laden VLCC is literally out of sight. You could say the same about the development of crude export terminal projects along the Gulf Coast: not much to see, maybe, especially during the disturbingly enduring COVID-19 era, but a lot is happening under the surface. In today’s blog, we discuss the status of onshore and offshore projects aimed at streamlining the shipment of U.S. crude oil to overseas buyers.
In the three years since Moda Midstream acquired Occidental Petroleum’s marine terminal in Ingleside, TX, the company has developed millions of barrels of additional storage capacity, connected the facility to a slew of Permian-to-Corpus Christi pipelines, and increased the terminal’s ability to quickly and efficiently load crude onto the super-size Suezmaxes and VLCCs that many international shippers favor. Moda’s fast-paced efforts have paid off big-time, first by making its Ingleside facility by far the #1 exporter of U.S. crude oil and now with a $3 billion agreement to sell the terminal and related pipeline and storage assets to Enbridge. The transaction, which is scheduled to close by the end of this year, will make Enbridge — already the co-owner of the Seaway Freeport and Seaway Texas City terminals up the coast — the top dog in Gulf Coast crude exports. Today, we discuss the Moda agreement and how it advances Enbridge’s broader Gulf Coast export strategy.
This summer’s resurgence of the COVID-19 pandemic in many parts of the world will wreck forecasts of demand for petroleum products and, therefore, for crude oil. Most oil-market forecasts published in the first half of 2021 didn’t anticipate the 75% jump in new weekly coronavirus cases that has occurred since mid-June, or new possibilities for travel limits and other restrictions of the type that clobbered economies — and oil demand — around the globe in 2020. Obviously, swerves away from expectations for oil consumption scramble the supply-demand balances widely used in oil-market analysis. But they do happen. In fact, deviation between forecast and actual demand is the rule, not the exception. It’s just not always as extreme as the balance adjustments likely to be needed after the latest COVID surprise. Even when there’s no deadly pandemic to worry about, demand can be tricky to define, difficult to measure, and frustrating to predict. In today’s blog, we discuss the intricacies of oil-demand assessment and explain why balance calculations, based on forecasts destined to be wrong, remain meaningful to analysts mindful of their limitations.
It’s often said that the offshore Gulf of Mexico is a different animal than its onshore counterparts, especially shale and tight-oil plays like the Permian and the Bakken. Decisions to invest in new production in the GOM aren’t based on crude oil demand and price forecast for the next two or three years; they’re based on expectations for the next two or three decades. Well, 30 years from now will be 2051, a year after Shell and a number of other energy companies have pledged to achieve “net-zero” carbon emissions. What does decarbonization mean for future development in the offshore Gulf, where the upfront capital costs are enormous and wells can be prolific producers for many, many years. In today’s blog, we discuss the final investment decision (FID) on Shell’s Whale project in the western Gulf of Mexico and the prospects for further development in the GOM.
For some time now, a handful of refineries in southeastern Louisiana, Mississippi, and Alabama have been able to receive steeply discounted, heavy sour crude from Western Canada by rail or barge — or, in rare cases, by pipeline from Cushing to Nederland, TX, to the St. James, LA, hub. Starting in a few months, though, this same crude also will be able to flow by pipe directly from Patoka, IL, to St. James on the soon-to-be-reversed Capline pipeline. Initially, the southbound volumes on Capline will be modest, but over time they could increase to several hundred thousand barrels a day. Will those barrels be loaded onto supertankers and shipped overseas, or will they be headed for refineries in Louisiana and its eastern neighbors? In today’s blog, we try to answer those questions.
As the outlook for crude oil in 2022 came into three-dimensional view this month, the market’s steadying mechanism managed to right itself again after another wobble. The Organization of the Petroleum Exporting Countries (OPEC) took its first formal look at next year in its July Monthly Oil Market Report (OMR), becoming the third of three widely watched prognosticators to do so. Among the other two, the International Energy Agency (IEA) began projecting 2022 oil-market data in its June Oil Market Report, and the intrepid U.S. Energy Information Administration (EIA) took its first analytical shot at next year way back in January in its Short Term Energy Outlook. The important third dimension that OPEC gave to the 2022 oil-market picture arrived on July 15 after two weeks of worry about whether production restraint by most of the group’s members and cooperating countries would survive. On July 18, though, the internal squabble driving that concern ended in a compromise that will result in production quota increases for several OPEC+ members. The 2022 projections by OPEC, IEA, and EIA, not to mention worry-driven elevation of crude oil prices prior to the compromise, make clear that the market needs OPEC+ to continue the orderly unwinding of its production cuts. In today’s blog, we compare the three forecasts and look at how the latest adjustment to OPEC+ supply management will affect the market.
In just a few months, heavy crude from Western Canada will start flowing south on the Capline pipeline from the Patoka, IL, hub to the one at St. James, LA. While the initial volumes will be modest, Capline’s long-awaited reversal will provide Louisiana refineries and export terminals with easier, lower-cost access to oil sands and other Alberta production. Flipping the pipeline’s direction of flow also means more changes for the St. James storage and distribution hub — one of the U.S.’s largest — which has already seen more than its share of evolution during the Shale Era. Today, we continue our Capline/St. James blog series with a look at St. James’s terminals and pipelines, the Louisiana refineries they supply, and the changes coming with the Capline reversal.
Crude oil is demonstrating yet again its penchant for what markets hate most: surprise. Last month, the Organization of the Petroleum Exporting Countries (OPEC) and collaborating governments were carefully easing the production cuts with which they steered the market through an oil-demand crisis caused by the COVID-19 pandemic. Demand was recovering as economies reopened after being locked down during most of 2020 and early 2021. And the near-month futures price for light, sweet crude on the New York Mercantile Exchange (NYMEX) — having closed below zero for the first time ever on April 20, 2020 — rose above $70/bbl for the first time since October 2018. Until mid-June, the market’s main concern was the potential for a supply surge if Iran escaped sanctions by agreeing with the U.S. to again suspend nuclear development. Surprise! Only days after his election as Iranian president on June 18, Ebrahim Raisi announced new limits on what his government would negotiate regarding nuclear work and said he would not meet with U.S. President Joe Biden. Suddenly, new oil supply from Iran looked less imminent than it did before Raisi’s election. Then July arrived. Surprise! OPEC members and nonmembers, collectively known as OPEC+, which had been voluntarily limiting production ended an important meeting without agreeing, as had been expected, to extend their phasedown of supply restraint. Suddenly, the market had to wonder whether the result would be too little supply or a price-crushing production spree if OPEC+ discipline collapsed. In today’s blog, we examine how these developments relate to each other in the twin contexts of a rebalancing oil market and of past oil-supply management.
After the crude oil price crash in the spring of 2020 and flat-at-$40/bbl oil last summer and early fall, prices for both WTI and Brent have been increasing steadily the past several months, and now stand at a kind-of-remarkable $75/bbl. This rise has been driven by a combination of demand recovery and supply restraint from both OPEC+ and U.S. producers — which begs the questions: what’s next on the supply and demand fronts, and how much more will oil prices increase from here? There’s been a lot of chatter lately that we might see $100/bbl crude prices sometime soon, and there are a lot of interested parties — many of whom don’t normally see eye-to-eye — who, for one reason or another, see their interests converge around the $100/bbl mark. The only problem is, it’s not showing up in the forward curve. Today, we look at the potential for “Benjamin-a-barrel” oil and how it might play out.
It’s been a challenging few years — some would say decades — for producers in northern Alaska. Crude oil production in the remote, frigid region peaked at just over 2 MMb/d in 1988 and has been falling ever since, dropping to about 450 Mb/d in 2020 and the first few months of 2021. It’s not that Alaska is running out of oil; far from it. Instead, the state’s energy industry has been battered by competition from shale producers in the Lower 48, thwarted by federal policies, and, more recently, ESG-related concerns and the Biden administration’s efforts to put the kibosh on new federal leases. Despite it all, the few producers still active in Alaska hold out hope for a revival. Today, we discuss the many hurdles that northern Alaska producers face.
The vast potential for permanently storing carbon dioxide underground by using it for enhanced oil recovery can only be realized if produced or captured CO2 can be economically transported long distances via pipeline. And the only way that can happen is if the CO2 is compressed into a “supercritical” or “dense-phase” fluid — a state that is somewhat compressible like a gas but flows and can be pumped like a liquid. When CO2 is in a supercritical state, much more of it can economically flow through a pipeline to the producing field. And when it gets there, the dense-phase CO2 can be injected into an oil production zone, where it has the unique ability to flow through permeable rock formations, bond with and “swell” trapped oil molecules, and free the oil to move to the production well, then up to the surface. Given that CO2-based EOR is destined to become a much more significant activity in the energy industry, it’s time for a fun-filled review of the thermodynamics of fluids as it relates to the transportation of CO2 and its use in the production of crude oil. (Wait! Don’t leave! This will be easy to follow! We promise!) Today, we continue our series on the rapidly evolving CO2 market and why it matters to crude oil producers.
Using carbon dioxide for enhanced oil recovery offers tremendous potential for CO2 sequestration. The problem is, most the CO2 used in EOR today is produced from natural underground sources, only to be piped to EOR sites and put underground again. Realizing the full promise of CO2-for-EOR would require sourcing more and more anthropogenic CO2, or A-CO2 — in other words, “man-made” CO2 that is captured from power generation and industrial processes. In addition to the environmental benefits, there are two other drivers for making this switch from natural CO2 to A-CO2: the first is that some of the natural sources of CO2 used today for EOR are dwindling, and the second is that the push to sequester man-made CO2 is backed by tax credits and other government-backed incentives. No matter the CO2 sourcing, CO2-for-EOR requires pipelines to transport the CO2 from where it is produced to EOR sites. Today, we continue our series on the rapidly evolving CO2 market and the huge opportunities that may await those who pursue them.
It’s been a mantra in the energy industry for a few years now: more Canadian and Lower-48 crude oil needs to move to the Gulf Coast, with its bounty of refineries and export docks. And that’s been happening, thanks to a slew of new and expanded pipelines and new tankage. Similarly, new export capacity has been developed, and a number of refineries in Texas and Louisiana revised their crude slates to take advantage of what looked like an ever-rising supply of North American crude. Yet another piece of the puzzle will slide into place in January 2022, when crude oil — most of it heavy Western Canadian — will start flowing south on the newly reversed, large-bore Capline pipeline from the Patoka hub in Illinois to the impressive collection of terminals in St. James, LA. Today, we continue our series on the market impacts of Capline’s upcoming reversal on St. James, Louisiana refineries and crude exports.
Much like the world at large, the crude oil market has been healing from the ravages of COVID-19. Overall, market conditions are far better than they were in April 2020, when global oil consumption, crushed by pandemic-related lockdowns, slumped to 80.4 MMb/d, a 17% decline from the start of last year and a 20% drop from April 2019. Demand has been rebounding in fits and starts for a full year now — recovering from downturns is what markets do. But this recovery has gotten a big assist: 10 members of the Organization of the Petroleum Exporting Countries (OPEC), acting in concert with 10 non-members, have restrained crude oil production in a program unprecedented in scale and duration. Now, oil prices are high enough to revive activity by some producers outside the so-called OPEC+ group. For at least the rest of this year, in fact, the market looks like a steel-cage match between crude supply subject to coordinated management and supply governed only by raw market signals. Today, we look at oil-market projections from three important agencies and estimate demand for oil not supplied by the OPEC+ exporters.