For the U.S. oil patch, exports are the lifeblood of today’s market. U.S. refineries are operating at more than 90% of their rated capacity and using as much domestically produced light-sweet shale oil as their sophisticated equipment will allow. That means that virtually all of the incremental U.S. unconventional light-sweet crude oil production will need to be piped to export terminals along the Gulf Coast, loaded onto tankers, and shipped to refineries overseas. In today’s RBN blog, we discuss what this undeniable link between crude oil exports and production growth means for U.S. E&Ps and midstream companies — and the future of the oil and gas industry.
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.
Memorial Day in the U.S. and the annual spring bank holiday in the U.K. put a wet blanket on Monday’s crude oil markets. Brent was off about $0.68/bbl as of mid-afternoon in thin holiday trading. That follows a rebound on Friday, when Brent moved $0.69/bbl higher to settle at $76.95/bbl and WTI was up $0.84/bbl to settle at $72.67/bbl.
May was a tough month for US oil and gas rig count, with producers ending the month with a fourth consecutive weekly decline (-44 vs April 28). Total US rig count was 711 for the week ending May 26, according to Baker Hughes. Rigs were added in the Permian (+1) and Eagle Ford (+1) this week, while the Anadarko (-5), Haynesville (-3), Gulf of Mexico (-1) and All Other Basins (-1) all posted declines. Total US rig count is down 42 in the last 90 days, and down 16 vs. this same week a year ago.
Daily Energy Blog
In the next few days, U.S. Energy Secretary Jennifer Granholm will hold an emergency meeting with leading energy executives to discuss steps E&Ps and refiners could take to increase crude oil production, refinery capacity and the production of gasoline, diesel and jet fuel, all with the aim of reducing prices. The prelude to the get-together was less than ideal, though. In a June 14 letter to the top brass of four integrated oil and gas giants and three large refiners, President Biden criticized them for “historically high refinery profit margins” and for shutting down refining capacity before and then during the pandemic. In addition to rejoinders from the companies, the American Petroleum Institute (API) and the American Fuel & Petrochemical Manufacturers (AFPM) defended their actions, discussed the complexity of refined products markets, and asserted that the Biden administration’s statements and policies have actually discouraged investment in refining and oil and gas production. Is there a middle ground here? In today’s RBN blog, we look at the high-level correspondence and discuss how at least some compromises might be possible.
If you want to get the energy world’s full attention, give it a global pandemic, a rush to decarbonize, and a brutal land war in Europe — all in quick succession. Bam! Bam! Bam! The past two-plus years have shaken the global oil, natural gas and NGL markets to the core, and forced just about everyone involved to rethink the expectations and plans they had before everything seemed to unravel. So what happens next? How do we provide energy security, put a lid on inflation, and save the planet? To answer those questions, a good place to start is to gain a better understanding of the fundamentals — how energy markets develop, work and interact. In today’s RBN blog, we discuss highlights from RBN’s recent School of Energy, a like-you-were-there replay of which is now available.
For several years now, no single topic has caused more angst in refiners’ quarterly earnings calls than the seemingly arcane topic of renewable identification numbers, or RINs, which can have a big impact on a refiner’s financial performance. RINs are a feature of the federal Renewable Fuel Standard (RFS), which requires renewable fuels like ethanol and bio-based diesel to be blended into fuels sold in the U.S. And depending on your point of view — farmer, refiner, blender, consumer, politician — you may have a very different perspective regarding RINs’ role as a tax and a subsidy. In today’s RBN blog, we dig into the fundamental aspects of RINs at the root of this long-running controversy and examine the role of RINs as a mechanism for forcing renewables into fuels.
Last month, in the U.S. Environmental Protection Agency’s (EPA) latest ruling in a long-running dispute with refiners over the Renewable Fuel Standard (RFS), EPA denied 36 petitions from refiners seeking exemptions to their obligation to blend renewables like ethanol into gasoline for the 2018 compliance year. At the core of this dispute are two contradictory premises about Renewable Identification Numbers, or RINs. One premise says the RINs system adds cost that hurts refiners’ profitability, while the other says refiners’ profitability is not affected. Can two seemingly contradictory premises be true? In today’s RBN blog, we begin an examination of the issues surrounding RINs and the degree to which the cost affects refiners’ and blenders’ bottom lines.
U.S. diesel inventories are at their lowest level for May since 2000 and East Coast stocks recently hit their lowest mark for any week or month since the EIA started tracking them in 1990. Crack spreads for diesel — and, more recently, for gasoline — have gone parabolic, giving refiners the strongest financial signal ever to produce more diesel and gasoline as we enter the summer travel season. More jet fuel too. The problem is, U.S. refineries already are running flat-out. And Europe? It’s facing big cuts in crude oil and refined-products imports from Russia as well as much higher prices for — and possible shortages of — oil and natural gas, the latter being the primary fuel for operating refinery hydrocrackers, which upgrade low-quality heavy gas-oils into high-quality diesel, gasoline and jet. It’s a mess, and not easily fixable, as we discuss in today’s RBN blog.
It took a while, but domestic air travel is finally returning to pre-pandemic levels and international travel to and from the U.S. is showing signs of recovering too. As a result, U.S. production of jet fuel has been rising steadily in recent months and, since most jet fuel needs to be transported long distances from refineries to airports, so have flows of jet fuel on U.S. refined products pipelines. All of that is good news, but as pipeline flows rise, so may the stresses on some elements of the U.S. refined products/jet fuel distribution network, including pipelines, storage facilities and “last mile” jet fuel delivery trucks. In today’s RBN blog, we continue our look at jet fuel, this time with a look at the extensive web of U.S. refined products pipelines.
Just over two years ago, the jet fuel market experienced an almost existential shock. In the space of only six or seven weeks, demand for the refined product plummeted by more than 70% as COVID-related lockdowns and air-travel restrictions were implemented. Fortunately, life in the U.S. has been returning to normal — albeit with some bumps along the way — and demand for jet fuel (a.k.a. “jet”) has been rebounding to near pre-pandemic levels. That re-emphasizes a nagging challenge, though, namely transporting large volumes of jet from refineries and import docks to hundreds of major and minor airports. In today’s RBN blog, we continue our look at jet fuel, this time with an examination of where it's produced and consumed, and how it gets from refineries to airports.
Over the past few weeks, many U.S. refiners reported even-stronger-than-expected first-quarter results, and it’s likely their good fortune will continue. Why? Despite the skyrocketing price of crude oil — refiners’ primary feedstock — the prices of the gasoline and diesel they produce have risen even more. And it’s that now-yawning gap between crude oil and refined-products prices that’s been driving refining margins — and refiners’ profits — to near-historic levels. Refining margins, like the character and capabilities of thoroughbreds like “Rich Strike” in Saturday’s amazing Kentucky Derby, are unique to each refinery because of their different sizes, equipment and crude slates (among other things), but there’s a tried-and-true way to estimate the refining sector’s general profitability, as we discuss in today’s blog on U.S. refiners’ sky-high crack spreads.
The jet fuel market has been on a wild ride the past two-plus years. First, demand for the refined product took an unprecedented, COVID-induced nosedive in February and March 2020. By May 2020, Gulf Coast prices for jet fuel had plummeted to less than 50 cents/gal (from just under $2 at the start of that year) and refiners had slashed production to 505 Mb/d (from just under 1.9 MMb/d). It was a tough few months — the recovery from the market’s bottom was neither quick nor consistent. Domestic air travel is finally back, but with international travel slower to rebound, total jet fuel supply and demand are still off of their pre-pandemic levels. Jet fuel prices are taking off, though, last week hitting their highest mark since July 2008. In today’s RBN blog, we discuss the jet fuel market: how it’s rebounding, how it works and how it’s changing.
Here’s an idea. Let’s start up a new company that does energy market fundamentals linked to rock & roll songs. Do it with practical, commercial insights. Keep the quality top notch. Then give it away for free! Sound crazy? Maybe so. But that’s how RBN Energy got started 10 years ago, and it’s worked out pretty well. Now, 2,540 blogs later and with 35,000 members receiving our morning email each day, it seems like we ought to celebrate in RBN style by telling a couple of backstories that shed light on our approach to energy markets, delving into the whole rock & roll thing, and of course divulging a few deep RBN secrets never before revealed. Until now, that is. And there’s more! You might end up receiving a free RBN 10th Anniversary Commemorative Mug. Warning: Today’s blog is a trip down memory lane for hard-core RBNers.
In the aftermath of the massive Winter Storm Uri in February of last year and its impact on the natural gas industry, there has been a blizzard of civil and regulatory litigation. Whether it’s someone not providing contracted gas supply, not taking expensive must-take gas supply, or saying “not that contract, but this contract” where there was a big difference in pricing between the two, lawyers are having a field day with the meaning of two words: force majeure. To what extent was one party to an agreement protected from being in breach of contract because their deal said some things could be force majeure, or beyond their control? The purchase and sale of natural gas at issue in these contracts is overwhelmingly done through a standard base contract produced by the North American Energy Standards Board, or NAESB (pronounced “Nays-be,” not “Nazz-be”). In today’s RBN blog, we discuss the standard contract used for the vast majority of natural gas supply deals in the U.S. and how its provisions relate to the issues raised by last February’s Deep Freeze.
California has a long history of leading the U.S. in environmental regulations and of taking federal environmental rules to the next level. Back in the 1960s, for example, the state became the first to regulate emissions from motor vehicles. In more recent decades, it has led the way in reducing greenhouse gas emissions. Many of these progressive regulations migrate to other states over time, which adds significance to a Northern California environmental agency’s recent decision to put stricter limits on emissions from refinery fluidized catalytic cracking units, or FCCUs. In today’s blog, we discuss the new regulation and its potential implications.
Oil and gas pipeline regulation have two things in common: They’re both regulated by the Federal Energy Regulatory Commission (FERC), and they were both brought under regulatory oversight in the first place by a Roosevelt — oil pipelines by Teddy Roosevelt and gas pipelines by Franklin Roosevelt. However, that’s where the similarities end. They’re regulated under different statutes, with wildly different histories that have led to very different types of oversight and rate structures. These rules tend to offer oil pipelines a higher degree of flexibility, but in doing so, they also make their rate structures less predictable. Today, we wrap up our review of oil and gas pipelines, and how their separate histories led to the current differences in pipeline rate structures, this time with a focus on oil pipeline ratemaking.
The uninitiated might be forgiven for thinking that oil and gas pipeline operations are similar. After all, they’re just long steel tubes that move hydrocarbons from one point to another, right? Well, that’s about where the similarity ends. While the oil and gas pipeline sectors are interlinked, they developed in quite distinctly different ways and that’s led to a vast chasm in both the way the two are regulated and how their transportation rates are determined. Bridging that gap between oil and gas can be a perilous and chaotic endeavor because you’ve got to consider how each sector evolved over time and the separate sets of rules that have been established to form today’s competitive marketplace. In today’s blog, we continue our review of oil and gas pipelines and how their separate histories led to the current differences in pipeline rate structures.
WTI crude finally closed above $70/bbl yesterday! Yup, change in energy markets is coming at us fast and furious. Whether it’s recovery from COVID, the return of Iranian supply, the changes in OPEC+ production, the majors being walloped by environmentalists, or a genuine upturn in crude prices, the big challenge is keeping up with what’s important, as it happens. That’s what we do at RBN, in our blogs, reports, conferences and webcasts. But many of our readers only know us through our daily blog, which confines us to only one topic each day. What if we had another no-cost service, where we would provide all our available info on energy news, market data, RBN analysis and just about anything that impacts oil, gas, NGLs, refined products, and renewables? Well, we’ve got that now. It’s called ClusterX Energy Market Fundamentals (EMF) channel. It’s an app for your phone or browser. It delivers to you everything our RBN team believes is important as soon as we can get the information into our databases. And all you need to get access to EMF is in today’s blog.