There are a number of reasons why certain U.S. refineries might want to include waxy crude oil from Utah’s Uinta Basin in their crude slates — the highly paraffinic oil has a lot of neat qualities. But waxy crude can be a hard sell, mostly because, like bacon fat, it needs to be kept warm to remain in a liquid, flowable state. As a result, the vast majority of the waxy crude produced is driven in insulated tanker trucks to refineries in nearby Salt Lake City. Uinta producers have been making progress of late, however, in sending regular shipments of waxy crude in coiled and insulated railcars to a couple of Gulf Coast refineries. Existing terminals would support incremental growth, and a proposed new railroad out of the basin would allow far larger volumes to be efficiently railed to market. In today’s RBN blog, we continue our look at the prospects for a most unusual type of crude oil.
The market dislocations of the past year and a half really took the wind out of the sails of many U.S. hydrocarbon plays. Not the Permian, of course. Sure, production there declined some in the spring of 2020, but has been on the rebound ever since — aside from a brief, Deep Freeze-related downward spike back in February, that is. But the recovery in many other leading production areas was short-lived. Production in the Bakken has stayed close to flat lately, and output in the Eagle Ford has been slipping. The same is true in SCOOP/STACK, which only a few years ago was hailed as maybe the next big thing. What happened? And is there hope for a comeback? In today’s RBN blog, we discuss the once-hot Oklahoma play and its prospects.
Producers of crude oil face historic insecurity about their market. Not only is there still uncertainty stemming from COVID, oil demand is also under pressure as governments and international organizations push to replace fossil fuels with energy forms free of hydrocarbons. Members of the Organization of the Petroleum Exporting Countries (OPEC) face special challenges from measures taking shape to discourage oil use. Their economies, more than most others, depend on oil sales and many members of the exporters’ group have limited sources of replacement income. Yet OPEC producers do not lack leverage in a market expected to grow at diminishing rates and eventually shrink. Many of them can produce crude oil much less expensively than counterparts elsewhere and some of them plan to profit from that advantage by increasing output, even as the market flattens, and are investing to raise production capacity to ‘get while the getting is good.’ In today’s RBN blog, we look at capacity-boosting plans within OPEC, explain why most members cannot take part in the effort, and describe how this developing priority might intensify market competition.
A long, long time ago — or, more precisely, in the spring of 2014, when WTI was selling for more than $110/bbl — a handful of exploration and production companies were convinced they were onto something big in southwestern Mississippi and east-central Louisiana. There, they believed, the Tuscaloosa Marine Shale (TMS) was poised to become the next Bakken, the U.S.’s premier shale play at the time, but even better for producers seeking more robust crude prices because of TMS’s very low gas-to-oil ratio — an oil cut north of 92%! –– and proximity to Gulf Coast refineries. While there had been a host of failed efforts by producers to wring out large volumes of premium-priced Louisiana Light Sweet (LLS) oil from the marine shale’s sedimentary silts and clays, the E&Ps felt in their bones that they were finally “cracking the code.” Then, at just the wrong time, came an oil price crash that set the whole industry back on its heels and activity in the TMS quickly slowed to a crawl. As we discuss in today’s RBN blog, an even smaller cadre of Tuscaloosa Marine Shale true believers is now banking on a production revival in the core of the play.
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.