Like an aging pop star, price benchmarks have to re-invent themselves from time to time to maintain their status. The Dated Brent marker –– as much a survivor as Cher, still going strong at 76 –– has had successes and setbacks in the past and will undergo yet another transformation by June 2023, courtesy of price reporting agency Platts. You definitely need to pay attention to this change, because Dated Brent is used as a pricing reference not only for several crude oil streams sold around the world, but also for other commodities such as LNG, fuel oil and other refined products and petrochemicals — oh, and financial derivatives too. Also, the latest version of the price marker will include an adjusted price for the U.S.’s prolific West Texas Intermediate (WTI). In today’s RBN blog, we discuss the details and implications of Dated Brent’s latest makeover for traders, refiners and other market participants.
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Daily energy Posts
Refining margins today — whether in the U.S. Gulf Coast (USGC), Rotterdam or Singapore — are at record highs. Given current high crude oil prices, gasoline and diesel prices at the pump everywhere are also at unprecedented levels, making refinery profits a major topic of conversation — and not just for politicians. While some of the explanations of refining margins are just political talking points, several others are well-established and accepted, and still others consider factors that are less frequently cited, even by those familiar with energy markets. One such factor is the price of natural gas and how it’s impacting refinery operations and competitiveness around the world. Today’s RBN blog discusses the crucial role natural gas prices play in refinery operating expenses and refining margins, and examines how favorable natural gas prices in the U.S. are providing a substantial competitive advantage for domestic refiners.
As the world economy tries to dust itself off after COVID, increased demand for transportation fuels coupled with tight supplies has become a pain. The shortage escalated to crisis levels this spring and summer when, in response to Russia’s invasion of Ukraine, sanctions eliminated Russian exports of crude oil and intermediate feedstocks to the U.S. and severely reduced flows to Europe. While Russia has been able to find some alternate markets, its overall product exports are down significantly. Adding to these product-supply reductions are policy decisions by Putin’s allies in China to reduce their product exports to a trickle. Chinese exports had been an important part of regional supply in recent years, but authorities there have decided to decrease the number and size of export quotas issued, leaving many refineries in China operating at rates well below their capabilities. In today’s RBN blog, we take a closer look at how developments in Russia and China have played a major role in the current global shortage of refined products.
When you boil it down, there are only two energy-related responses to Russia’s war on Ukraine. First, there’s a big push to find sources of crude oil, refined products, natural gas and NGLs to replace Russian supplies as quickly as possible. Second, governments on both sides of the Atlantic are scrambling to reaffirm and even expand commitments to lower-carbon energy sources to delink from Russian hydrocarbons as well as meet energy transition goals. Both raise the same question: How fast can the world bring online any new sources of energy on the scale needed? Policymakers would like to believe the answer can be found through the stroke of a legislative pen invoking aspirational language. No one doubts the power of that pen to create incentives or impediments. But the answer to that question is dictated by the realities of the physical world. In today’s RBN blog, we discuss the options for accelerating the availability of the minerals, metals and other materials needed to build the required machinery for the energy transition.
The global reaction to Russia’s invasion of Ukraine was swift, with calls of condemnation and plans quickly surfacing for the U.S. and other countries to stop their purchases of Russian crude oil and natural gas immediately, or at least as soon as practical. The strategy has been to make the situation as politically and financially painful as possible for Russia, which has not been shy about using its energy supplies as a weapon, before or after the invasion. But those plans haven’t worked as well as hoped, and some impacts are bringing back memories of the 1973 oil embargo which, though driven by a far different series of events, may provide insight into the current situation. In today’s RBN blog, we look at the many parallels to today, including weaponized oil, regional supply shortages, price spikes and well-intentioned (if sometimes ill-conceived) government responses.
We often tend to focus on the U.S. refining picture, but, just like crude oil, refined products trade globally, and international closures ultimately have the same effect as domestic ones on the worldwide products market. Recent international closures have been distributed throughout the world — concentrated in developed countries, including several in Europe, as well as Japan, Singapore, Australia and New Zealand, but also in some developing economies like South Africa and Sri Lanka. Most of these capacity reductions were driven by the same forces as in the U.S., namely, poor economics as a result of the pandemic-lockdown-driven demand plunge in 2020 and 2021, as well as expectations that margins would take a long time to recover post-COVID. Of course, worries that the energy transition and policies to that end would suppress demand in the long-term also played a key role, as did some fundamental competitiveness issues at individual facilities. In today’s RBN blog, we take a closer look at the more than 2 MMb/d of international capacity closures since 2019.
Just two years ago, the onset of the pandemic slashed the share prices of many oil and gas producers and the idea of parking cash in a U.S. E&P seemed to make as much sense as leaving your Porsche on a midtown street with the keys in it and the motor running. But times — and commodity prices — have changed, and hydrocarbon producers have transformed themselves into cash-flow-generating machines that attract the sagest investors. Want proof? Warren Buffett’s Berkshire Hathaway recently purchased another 10.4 million shares of Occidental Petroleum (Oxy) for over $500 million, bringing its stake in the company to a substantial 16.4%. In today's RBN blog, we detail how the major U.S. E&Ps are allocating their cash flow to keep investors happy.
Gasoline and diesel prices are skyrocketing. Refineries are running near maximum capacity. The Biden administration is asking refiners to bring more capacity online to relieve refining constraints. And as the economy recovers from the COVID meltdown, it looks set to get worse before it gets better. So the timing could not be better to launch our new team focused on refineries and refined products: RBN Refined Fuel Analytics. We readily admit that this is an advertorial but stick with us, it will be worth it. We’re building out a whole new approach to the understanding of refined fuel markets –– both traditional hydrocarbons and renewable fuels –– from feedstocks through refining processes to final products. In today’s RBN blog, we’ll introduce the who, what and how of this important initiative.
As concerns about energy security have come to the forefront, some in the mainstream have begun to pump the brakes on the idea of energy transition at any cost and reevaluate the practicality of some proposed solutions. But that hasn’t changed the long-term outlook for energy transition nor the fact that numerous individual projects focused on alternative fuels, carbon capture, hydrogen and renewable energy are in the works, gaining in prominence and attracting a prodigious amount of investment. There is still an anticipation among investors that the market will increasingly demand greener production methods — they just need to be well-conceived, planned and executed. The good thing for Fidelis New Energy — a Houston-based firm focused on climate-impact infrastructure, including low-carbon, sustainable fuels — is that, among renewable producers, they’re building a sustainable cost advantage through efficient, integrated design. In today’s RBN blog we look at what Fidelis calls the Grön Fuels GigaSystem.
Carbon-capture projects have begun to pick up steam in recent months, especially in the Midwest and Great Plains, with three major developments already taking shape and the potential for more. At the same time, the need to move natural gas east from the Rockies has declined over time and Tallgrass Energy Partners — a leading midstream player in that space — is looking for ways to make fuller use of its Rockies Express and Trailblazer gas pipelines. In today’s RBN blog, we look at an agreement between Tallgrass and Archer Daniels Midland (ADM) to capture and sequester carbon dioxide (CO2) emissions from a corn-processing complex in Nebraska, how that deal relies on the planned conversion of the Trailblazer Pipeline from natural gas to CO2, thought to be the first of this scale, and why Tallgrass sees potential in carbon-capture projects across the region.
Increasing scale. Improving efficiency. Expanding into a fast-growing production area. These are only a few of the many reasons that midstream consolidation has remained an ongoing phenomenon in U.S. oil and gas basins — nowhere more so than in the Permian. The slew of acquisitions, mergers and joint ventures announced in the past couple of years is resulting not only in more concentrated ownership of midstream assets in West Texas and southeastern New Mexico, but in large, smooth-running systems for gathering, treating and processing hydrocarbons and transporting them to market. In other words, in magnificent molecule-moving machines. With today’s RBN blog, we begin a short series on the latest round of midstream M&A activity in the U.S.’s hottest production area.
Way back in 2019, just about everyone in the refining world was talking about IMO 2020, the International Maritime Organization’s soon-to-be-implemented rule requiring much lower sulfur emissions from most ocean-going ships. A lot of forecasters were anticipating that major market dislocations would result — things like $50/bbl-plus diesel crack spreads, oversupply of high-sulfur fuel oil, and ultra-wide differentials between light and heavy crude oils. They did, but only briefly, in the last few months of 2019. The implementation of IMO 2020 turned out to be pretty much a non-event, and for much of 2020 and 2021, people didn’t think much about the new bunker fuel rule. Lately, things have been changing, as we discuss in today’s RBN blog.
Europe’s push to reduce and eventually eliminate its reliance on Russia for natural gas has pushed LNG imports back into the forefront of Europe’s long-term energy plan. This year, with European natural gas prices trading above Asian prices, the continent has been able to attract an incredible amount of LNG, with imports at record levels this winter and sitting just shy of those records this spring. That helped mitigate some of the risks to energy reliability from Russian aggression, at least until the Freeport LNG outage and the latest Russian gas curtailments, but import capacity in Europe was maxed out last winter and more LNG imports can’t happen in the long term without more import capacity. Most of the LNG terminals in Europe are operating at full capacity or don’t have enough market access on the other side of the pipe to take more. While plans to build new import terminals are underway, those take time, and lots of it, so Europe is also pursuing a more immediate option, floating storage and regasification units (FSRUs) — basically, an LNG import terminal on a ship. In today’s RBN blog, we take a look at all things FSRU, from what and where they are to the recent deals with European offtakers.
We’ve written a lot lately about how U.S. E&Ps, whipsawed over the last decade by extreme price volatility and negative investor sentiment, have adopted a new fiscal discipline that de-emphasizes production growth and prioritizes generation of free cash flow to reduce debt and reward shareholders. But what about midstreamers? They too have been buffeted in recent years by volatile commodity prices, eroding investor support, shifting upstream investment patterns, and finally, a global pandemic. Midstream companies face a different set of challenges than oil and gas producers in repairing their balance sheet and restoring investor confidence, however, mostly because midstream investment decisions are determined both by downstream market changes and by E&Ps’ development and production activity — including producers’ ever-increasing focus on the Permian at the expense of other basins. In the encore edition of today’s RBN blog, we discuss highlights from RBN and East Daley’s Spotlight Report on Western Midstream Partners and how the master limited partnership has been working to reduce its debt and make the most of its strong base in the Permian’s Delaware Basin.
In its landmark West Virginia v. EPA decision, the Supreme Court on Thursday scaled back the powers of the Environmental Protection Agency — and, it would seem, other federal administrative agencies — to implement regulations that extend beyond what Congress specifically directed in its authorizing legislation, in this case the Clean Air Act. The ruling didn’t go as far as throwing out the long-standing deference of courts to federal agencies’ interpretations when it comes to acting under statutory law where there’s any ambiguity — the so-called “Chevron Deference” doctrine. But it does impose a threshold roadblock to the use of the doctrine, based on the “Major Question” doctrine. Yep, we have a duel of the doctrines here. The end result here is to hamstring the EPA and the Biden administration from reinstating emissions-limiting rules similar to the ones the Obama EPA put forth a few years ago in the “Clean Power Plan,” at least not without legislative approval. Most of the oil and gas industry and a lot of the power industry are likely to welcome the check on this particular regulatory authority, and certainly most of the oil and gas industry welcomes some restraint on the EPA in general. However, the broader implications of the ruling could make life more difficult in the near-term for industries like oil and gas that rely on a stable, or at least semi-predictable, regulatory environment for making long-term plans. In today’s RBN blog, we explain what was at stake in this case and what the decision could mean for the oil and gas industry.
Canadian gas storage levels concluded the most recent heating season at multi-year lows, especially in the western half of the nation, which hit a 16-year low at the end of March. Though storage sites have been refilling at a steady rate so far this summer, storage in the west, a region vitally important for balancing the North American gas market during high winter demand, remains unusually low for this time of year. In today’s RBN blog, we examine the latest developments in Canadian natural gas storage and explain why storage levels in Western Canada may start the next heating season at critically low levels.