Crude oil quality has been a hot topic lately. With the increase in waterborne activity along the Gulf Coast, a high-quality barrel is desired now more than ever. Permian WTI exports have continued to increase as production rises and refining capacity remains relatively stagnant (outside of ExxonMobil’s recent Beaumont expansion). This has resulted in more scrutiny on Permian quality and more concerns rising to the surface — both from the pockets of lower-quality WTI produced at the wellhead and from blending by market participants, as many midstream providers and traders have become efficient at capturing arbitrage opportunities. Recent WTI quality concerns have primarily been around metal content, hydrogen sulfide (H2S) and mercaptans, while nitrogen has become a major issue in the natural gas market. In today’s RBN blog, we look at the issue of mercaptans in WTI.
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.
Saudi Aramco reduced its June LPG Contract Price (CP) for propane on May 30 to $450/MT (86.4 c/gal), down $105/MT (20.1 c/gal) from the May CP. As shown on the chart below, the Saudi CP for propane (black line) has been cut by 43% or $340/MT (65.3 c/gal) since February 2023 and was last lower in November 2020.
An agreement reached over the weekend between President Joe Biden and House Speaker Kevin McCarthy to raise the U.S. debt ceiling seeks to expedite completion of the long-delayed Mountain Valley Pipeline but also includes language intended to improve the pace of permitting for energy-related projects and could open the door to further legislation on permitting reform.
A few of the key provisions:
Daily Energy Blog
Mexican demand for motor gasoline and diesel has plummeted this spring due to COVID-19 — so has demand for LPG. So far, Pemex — Mexico’s state-owned energy company and by far the country’s largest supplier of these commodities — has responded by slashing how much gasoline, diesel and LPG it is importing from the U.S. and holding its own production steady, despite the fact that Pemex’s refining margins are now deep in negative territory. What does Pemex’s focus on money-losing refining mean for U.S. exports to Mexico going forward? Today, we begin a short series on the ongoing competition between U.S. refiners and Pemex for market share south of the border.
COVID-19 has created a number of challenges across the energy value chain, including lower demand for motor gasoline and jet fuel and, subsequently, surplus crude oil. However, even with diminished demand, the facilities that produce and process these fuels have to keep operating at some level, as do petrochemical plants. Workers in the energy industry are considered essential due to the importance of having fuel available to power vehicles and manufacturing facilities, natural gas to enable continued operation of power industries, and logistical infrastructure to ensure that feedstock supply can make it to processing facilities and eventually consumers. Given the need for round-the-clock operations, COVID-related social distancing measures have presented a unique challenge for refinery and petrochemical facilities. To maintain adequate staffing while protecting personnel from the coronavirus, these facilities have been making major adjustments. If, as we all hope, things begin moving back toward “normal” in the coming months and refinery and petchem utilization ramps up, these efforts to keep workers safe will only gain in significance. Today, we discuss staffing issues in these key industry sectors during the pandemic.
The COVID-19-induced social isolation and subsequent economic slowdown have caused major drops in U.S. refined products consumption, especially gasoline and jet fuel, which have experienced declines of as much as 44% and 70%, respectively, relative to similar periods in 2019. Diesel fuel consumption has been off as much as 20% on the same basis, and given that COVID is a global crisis, product exports have also fallen. As a result, U.S. refinery utilization has dropped to less than 70% for the last few weeks, the lowest levels since September 2008 during Hurricane Ike. All this presents refiners with two challenges: (1) reduced total demand; and (2) the disproportionate decline in gasoline and jet fuel. Each refinery is configured differently and has a varying degree of flexibility to react to these challenges. Today, we discuss what refiners can do to adjust operations and product yields, and examine the point at which some refineries might be forced to shut down completely.
Sharply declining refinery demand for crude oil was a key driver in the historic collapse in near-term futures prices for WTI at Cushing earlier this week. With stay-at-home directives in place in most of the industrialized world, U.S. — and global — demand for motor gasoline and jet fuel has plummeted to levels not seen in decades. These changes in refined-products demand, which may continue for months, already are having significant impacts on U.S. refineries — not just in how much crude oil they need but in operators’ decisions on whether to adjust their crude slates and ramp down or alter their operations. Their urgent challenge is to revise their yields to something close to the appropriate volumes of gasoline, diesel and jet fuel. Today, we begin a blog series on the U.S. refining sector and what refiners can — and can’t — do to adapt to these extraordinary times.
The collapse in crude oil prices and COVID-19’s very negative effects on global gasoline, jet fuel and diesel demand are putting an unprecedented squeeze on U.S. refiners. Even before the initial coronavirus outbreak in Wuhan, China, started to grab headlines around New Year’s Day, refineries had already been incentivized to shift their refined products output toward diesel, which can be used to help make IMO 2020-compliant low-sulfur bunker. Now, with the COVID-19 pandemic spreading to Europe and North America and stifling consumer transportation fuel demand, the price signals are even stronger, pushing refineries to do everything they can to minimize their gasoline and jet fuel production and enter what you might call “max diesel mode.” Today, we discuss how there are challenges and limits to what they can do, and a number of refineries may need to shut down due to lower demand, at least temporarily.
Over the weekend, PBF Energy closed on its acquisition of Shell’s Martinez, CA, refinery, marking the first completed U.S. refinery transaction of 2020. The closure of that deal may seem unremarkable, but it’s rare for more than two to three transactions involving individual refineries to take place in the U.S. in a given year, and there are as many as eight other refineries on the market. These include two each in the Philadelphia area, the Midcontinent and the Rockies, and one each in Washington state and Alaska. Why are so many refineries on the block? Today, we continue our series with a look at the facilities said to be on the market in PADDs 4 and 5.
It was reported earlier this month that Shell is seeking a buyer for its Washington state refinery, which is located just outside Seattle in Anacortes. That brings to eight the number of U.S. refineries said to be up for sale by a variety of sellers, from integrated major oil companies to independent merchant refiners — plus another refinery that is already under contract. That’s an unusually high number — refineries rarely change hands in the U.S. and when they do, it’s typically for large sums of money to sophisticated and vertically integrated buyers. Today, we discuss the facilities on the block in the East Coast and Mid-Continent regions and the market drivers that could be impacting the decisions of potential buyers and sellers.
Texas consumes far more diesel fuel than any other state and almost as much gasoline as car-crazy California, which also has 10 million more people. The long-distance distribution of refined products within the Lone Star State is handled largely by tanker trucks, but in the past couple of years, midstream companies have been adding a lot of new refined products pipeline capacity, not just to help deliver diesel and gasoline within Texas — including the diesel-hungry Permian Basin — but also to move motor fuels to the Mexican border for export. And more diesel and gasoline pipe capacity is on the way. Today, we discuss the new and expanded refined products pipelines criss-crossing Texas.
It’s been more than three years since the International Maritime Organization (IMO) fully committed to the January 1, 2020, implementation of IMO 2020, a rule that slashes the allowable sulfur content in bunker fuel used in the open seas around most of the world from 3.5% to only 0.5%. There’s been a lot of angst in the interim, most of it regarding the changes in crude slates, refinery operations and fuel blending needed to meet a flip-of-a-switch spike in global demand for low-sulfur bunker. Also, shippers worried that prices for rule-compliant fuel would go through the roof. Well, it turns out that the transition period in the months leading up to the IMO 2020 era has been largely drama-free. Supplies of very low-sulfur fuel oil (VLSFO) and marine gasoil (MGO) — the bunker most ships will now use — have been building in most places, prices are up but moderating, and while there may be a few hiccups as ships shift to new, cleaner fuels, life will go on. Heck, life will likely be even better for most complex U.S. refineries, which can churn out large volumes of low-sulfur refined products and which will have access to price-discounted high-sulfur “resid” as an intermediate feedstock. Today, we take a big-picture look at the global bunker market as IMO 2020’s implementation day approaches.
In February 2019, the U.S. Treasury Department announced new sanctions on Petróleos de Venezuela SA (PDVSA), the national oil company of Venezuela, which halted imports of Venezuelan crude oil into the U.S. Since then, refineries that relied on Venezuelan crude have had to backfill their import requirement with alternative sources of oil. This adjustment has had ramifications not only on the refiners that processed Venezuelan crude, but also on the entire U.S. Gulf Coast crude oil market. Today, we discuss the quality adjustments made to the U.S. crude oil diet.
Refined product supply in Petroleum Administration for Defense District (PADD) 1, which comprises Atlantic Coast states from New England to Florida, has been in trouble all year. Maintenance issues beset refineries during the first quarter, and then in June, the region's largest refinery, a 355-Mb/d plant owned by Philadelphia Energy Solutions (PES), was shuttered after a fire. The loss of the PES output would've been manageable if imports had taken up the slack. But although gasoline imports increased, distillate shipments have actually been lower than normal since June. As a result, the PADD 1 distillate market has been drawing an average 163 Mb/d from inventory since mid-August, according to weekly Energy Information Administration (EIA) reports, leaving stocks in the region at a 10-year low. That storage deficit versus previous years will increase when the weather turns colder and heating oil demand kicks into high gear. With stocks at historical lows and market prices not attracting new supplies, the shortage may well foreshadow price spikes this winter. A potential strike by unionized workers at the Phillips 66 Bayway refinery in northern New Jersey could make matters worse. Today, we look at what's behind the PADD 1 distillate shortfall.
For a few years now, Buckeye Partners’ plan to revise the current east-to-west refined products flow on its Laurel Pipeline across Pennsylvania has pitted Midwest refiners against their Philadelphia-area brethren — and gasoline and diesel marketers in western Pennsylvania. Each side has good arguments. Midwest refiners note that westbound volumes on Laurel have been declining through the 2010s, and assert that making the western part of the pipeline bidirectional would result in higher utilization of the line and enhance competition in central Pennsylvania, Maryland and eastern West Virginia. Pittsburgh-area marketers counter with the view that allowing refined products to flow east on a portion of Laurel would hurt competition in Pirates/Steelers/Penguins Country, while Philly refiners — their ranks now thinned by the planned closure of the fire-damaged Philadelphia Energy Solutions (PES) facility — say Buckeye’s plan would further threaten their economic viability. Amid all this, might there be a “perfect-world” solution? Today, we provide an update on this still-in-limbo project and discuss a few possible paths forward.
Independent refiner PBF Energy on June 11 announced its plan to acquire Shell Oil’s Martinez, CA, refinery for about $1 billion; the deal is expected to close by the end of 2019. The purchase will give PBF its sixth U.S. refinery and add 157 Mb/d to the company’s existing 865-Mb/d refining portfolio, pushing its total capacity past 1 MMb/d. Post-acquisition, PBF will retain overall fourth place in the U.S.
Philadelphia Energy Solutions (PES) announced last week (on June 26) that it was shutting down its 335-Mb/d refinery in Philadelphia, PA. This announcement came just five days after a major fire destroyed a portion of the refinery, which turned out to be the last straw for the facility that has been struggling financially for many years. Today, we consider the various market impacts that will likely follow the closure of the PES refinery, including its effect on fuel supply, where the closure leaves refinery production capacity in the region and how the refined product supply will need to adjust in response.
For some time, U.S. motor fuel exports to Mexico had been increasing at a healthy pace, reliably filling the void created by a series of production setbacks at Pemex’s refineries south of the border. From 2014 to 2018, U.S. gasoline exports to Mexico soared by more than 160%, from an average of 197 Mb/d five years ago to 517 Mb/d last year. Diesel exports rose by nearly 130%, to 279 Mb/d, over the same period. But that export-growth momentum has since sagged — in fact, export volumes for both gasoline and diesel actually declined in the first few months of 2019, primarily due to logistical challenges within Mexico. Also, Mexico’s new president has proposed ambitious plans to boost state-owned Pemex’s refining capacity, possibly posing a longer-term threat to U.S. exporters. So, is the boom in refined-product exports to Mexico over? Today, we examine what’s behind the downshift, and what the Mexican government’s effort to reinvigorate Pemex’s existing refineries — and build an entirely new one — may mean for U.S. gasoline and diesel exports in the 2020s.