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.
Daily Energy Blog
Brace yourself for it. Over the next few weeks, there’s a good chance that a tsunami of crude oil will be released from the U.S. Strategic Petroleum Reserve (SPR), and it’s likely that much (if not most) of that oil will be piped to Gulf Coast export docks and loaded onto supertankers. If that happens, the export capacity of crude-handling terminals from Corpus Christi to coastal Louisiana will be stress-tested on their ability to send out much larger volumes than they’re used to dealing with. And that’s only the beginning. Over the next year or two, while U.S. E&Ps ratchet up production in response to higher prices as Europeans and others scramble to replace Russian crude oil, Gulf Coast export terminals may well be called upon to load and ship out even more oil (in addition to refined products) on a regular basis. In today’s RBN blog, we discuss the impending SPR releases and the ability of Gulf Coast ports and individual terminals to handle increasing volumes.
Efforts to limit the effects of greenhouse gas emissions on the climate while meeting growing energy demand rest largely on key partnerships between the oil and gas industry and emerging climate technology companies. The transition to responsibly sourced gas — natural gas that is produced, gathered, processed, transported and distributed utilizing methods that meet the highest environmental standards and practices — does more than just lower emissions as part of that net-zero goal. RSG helps upstream gas businesses and downstream customers demonstrate their commitment to sustainability measures in ways that resonate with investors, regulators and the general public. In today’s RBN blog, we look at the road to a net-zero world and how Project Canary assessments can help ensure that natural gas remains a part of that journey.
Production bottlenecks and global energy security concerns stemming from the Ukraine war have flipped the script on various aspects of the U.S. energy markets. One of them is the softening of Wall Street and regulatory resistance to investment in new hydrocarbon infrastructure. That’s been particularly good news for the swarm of LNG export projects looking to move forward. It’s also improved somewhat the prospects for the embattled Mountain Valley Pipeline (MVP), the last major greenfield project for moving natural gas out of the Northeast from the Appalachian Basin. A court vacated three of the project’s key federal authorizations earlier this year, but the project recently got a greenlight when the Federal Regulatory Energy Commission (FERC) approved MVP’s amendment certificate application. Equitrans Midstream said last week that it would pursue new permits and target in-service in the second half of 2023. But the prospect of more legal challenges looms, and the question is, will it get across the finish line before severe constraints arise? In today’s RBN blog, we provide an update on the Appalachian gas market.
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.
A tight coal market and record-high coal prices in the Eastern U.S. have suppressed gas-to-coal switching in recent months, despite the gas market also contending with a supply squeeze and gas prices trading at Shale Era highs. The coal-market constraints have contributed to record, or near-record, gas demand in the power sector, with gas gaining market share of total generation fuel demand — in spite of wind and solar increasing their share of the pie. Generation fuel dynamics were a driving factor in the tighter gas market balances this past winter and also play a role in how power grids balance cost and reliability during times of extreme customer demand, such as the record-breaking heat wave expected to hit Texas in the coming days. In today’s RBN blog, we take a look at power generation fuel economics, particularly the fuel-switching phenomenon and its underlying drivers.
The first Saturday in May is only a couple of days away, so brush off your seersucker jacket or find that Kentucky Derby hat, as it’s the only time of year most Americans watch an actual horse race. That’s kind of how it goes with the Permian natural gas market as well, with only intermittent interest from general gas market participants, usually when there’s a pipeline capacity issue leading to a noticeable impact on prices. Now is one of those times. Permian gas production is racing higher and the pipelines to get gas to market are quickly getting jammed up. Daily prices in the Permian are trading about 10% lower than those in Louisiana and the forward basis markets suggest they will deteriorate further in the months ahead. Naturally, midstream companies are quickly trotting out new pipeline projects, but sorting out the contenders is much like picking the winner on Saturday. You need data and at least a little luck, and we’re here to help out with the former. In today’s RBN blog, we lay out what we know and how we view the Permian gas pipeline derby.
The energy market has been in chaos for some time. Even before Russia’s horrific attack on Ukraine, the multinational push to decarbonize the global economy was slow-motion-crashing into reality. Of course, global supply shortages only got worse following the invasion and the widespread response to it. The disruptions highlight the critical need for a balanced energy policy, both in the U.S. and abroad. This became evident in Europe last year, when a heavy, early reliance on renewable energy, largely wind, left much of the continent short on fuel and scrambling for natural gas when the wind didn’t blow enough. The overall supply-demand balance caused prices to rise steadily as the global economy climbed out of its COVID-induced recession. Then the situation became more dire as embargoes on Russian crude oil and gas were planned and implemented. In the U.S., the Biden administration, eager to both “green” the economy and keep gasoline prices in check, has been giving mixed signals to E&Ps and their investors, telling them to both ramp up investments in production and expect to play a smaller and smaller role going forward. It’s a confusing world. In today’s RBN blog, we look at the current energy environment, the policy roller-coaster, challenges to the increased usage of renewables that remain unaddressed, and how the politics of decarbonization are making the ongoing energy transition a very difficult row to hoe.
Carbon-capture projects have been slow to take root in the U.S., but that may be changing as a number of companies are now advancing plans to capture the carbon dioxide that results from ethanol production in the Midwest. Ethanol plants are an obvious choice, given that the CO2 resulting from ethanol fermentation is highly concentrated, which makes capturing it more efficient (and less expensive) compared to many other industrial processes. But while the relative ease and economy of capturing those emissions might seem like a no-brainer, convincing the public to go along with those plans has been more difficult. In today’s RBN blog, we look at what’s being planned.
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.
Extreme blizzard conditions wreaked havoc on North Dakota energy infrastructure last weekend, taking offline as much as 60% of the state’s crude oil production and more than 80% of natural gas output, and leaving utility poles and power lines strewn across the landscape. On the gas side, the unprecedented supply loss is having a never-before-seen impact on regional and upstream flows and storage activity. It is also compounding maintenance-related production declines in other basins, leaving Lower 48 natural gas output at its lowest since early February. Moreover, the extent of the storm-related damage to local infrastructure could prolong the supply recovery. In today’s RBN blog, we break down the aftereffects of the offseason winter storm on regional gas market fundamentals.
It’s been more than two months since Russia invaded Ukraine, sending global energy markets into chaos as most of Europe tries to figure out a way to quickly reduce its reliance on Russian supplies. The initial response from the U.S. and its allies was a slate of economic sanctions, but those largely left natural gas out of the equation, as parts of Europe are so dependent on Russian gas that stopping the flows would pose serious threats to the continent’s economies and energy security. Now, with no sign of an end to military hostilities and continual increases in the scope of sanctions, Russia is responding by starting to shut off flows to European countries that refuse to pay for their gas in rubles. Where is this headed? In today’s RBN blog, we look at the latest escalation, what led to this point and where the market might go from here.
In response to Russia’s invasion of Ukraine, Europe is planning massive and rapid changes in its natural gas supply, including a significant increase in LNG deliveries from the U.S. But there are major challenges and implications associated with this shift. For example, how can the U.S. government prod U.S. exporters to send more LNG to Europe? How can LNG buyers — or sellers — collaborate without running afoul of European Union antitrust laws? Can the development of new LNG import terminals be fast-tracked? And can long-term contracts for Russian pipeline gas be breached without penalty now that Russia has suspended deliveries to Poland and Bulgaria for not paying in rubles? In today’s RBN blog, we discuss what U.S. and European efforts need to overcome.
Despite the highest natural gas futures prices in over a decade, its use for power generation in the Lower 48 has set records in recent months. This is in part by design: economics and environmental regulation have broadly favored gas-fired plants and pushed into retirement hundreds of coal-fired plants in the last decade or so, reducing price-driven fuel-switching capabilities between the two fuels. However, there’s more to it than that: a tight coal market, marked by low stockpiles, high export demand and record high prices, is limiting gas-to-coal switching even further, making gas burn for power much more inelastic to price. In today’s RBN blog, we take a closer look at this key intersection of the gas and coal markets.
The 43 large U.S. E&Ps that we monitor posted record earnings in 2021 and tripled their cash flow — an extraordinary turnaround from a very tough 2020. But as big a story, at least for investors, is how those oil and gas producers are allocating their surging cash reserves. Their dramatic strategic transformation from growth at any cost to maximizing returns is expected to result in 2022 yields approaching 10% for some E&Ps, rates higher than the much broader S&P 500 sector and more than double the payouts of the oil majors, the former dividend kings. In today’s RBN blog, we discuss the cash-flow allocation of the major E&P companies and explain what it means for investors.
