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.
Global demand for propylene is rising, but lighter crude slates at U.S. refineries and the use of more ethane at U.S. (and overseas) steam crackers has reduced propylene production from these plants. That has led to the development of more “on-purpose” propylene production facilities — especially propane dehydrogenation (PDH) plants — in both the U.S. and Canada. More than 2 million metric tons/year of new PDH capacity has come online in North America since 2010, another 1.6 MMtpa is under development, and propane/propylene economics may well support still more capacity being built by the mid-2020s, maintaining the U.S. and Canada’s position as propylene and propylene-derivative exporters. Today, we begin a series looking at “on-purpose” production of propylene by PDH plants and what the development of these facilities will mean for U.S., Canadian and overseas markets.
With Petróleos Mexicanos’ (Pemex) refineries struggling to operate at more than 30% of total capacity, gasoline pumps across Mexico are more likely to be filling up tanks with fuel imported from the U.S. than with domestic supply. This arrangement works well for U.S. refiners, who are running close to flat-out and depending on export volumes to clear the market. But now, the Mexican government has shut a number of refined products pipelines to prevent illegal tapping, and that’s had two consequences: widespread fuel shortages among Mexican consumers and a logjam of American supplies waiting to come into Mexico’s ports. Today, we explain the opportunities and risks posed to U.S. refiners that have ramped up their involvement with — and dependence on — the Mexican market.
The implementation date for IMO 2020, the international rule mandating a shift to low-sulfur marine fuel, is less than 12 months away. It’s anyone’s guess what the actual prices of Brent, West Texas Intermediate (WTI) and other benchmark crudes will be on January 1, 2020, or how much it will cost to buy IMO 2020-compliant bunker a year from now. What is predictable, though, is that the rapid ramp-up in demand for 0.5%-sulfur marine fuel is likely to affect the price relationships among various grades of crude oil, and among the wide range of refined products and refinery residues — everything from high-sulfur residual fuel oil (HSFO, or resid) to jet fuel. The refinery sector is in for an extended period of wrenching change, and today we conclude our blog series on the new bunker rule with a look at the structural pricing shifts needed to support the availability of low-sulfur marine fuel.
While U.S. refineries are again running hot and heavy after the end of this year’s seasonal fall maintenance period, Mexico’s refineries have continued to struggle to operate at more than 30% of their capacity, a decline that is exacerbated by that country’s tumbling oil production. In recent years, Mexico’s dismal refinery utilization rate has been a boon for U.S. refiners on the Gulf Coast who can ship, pipe or truck gasoline to America’s southern neighbor in short order. Now, Mexico’s new president, Andrés Manuel López Obrador (AMLO), is pushing to solve Mexico’s refinery problems by building a new one. Today, we discuss Mexico’s growing dependence on U.S. gasoline, and whether building a new refinery south of the border will change things.
The IMO 2020 rule, which calls for a global shift to low-sulfur marine fuel on January 1, 2020, is likely to require a ramp-up in global refinery runs — that is, refineries not already running flat out will have to step up their game. Why? Because, according to a new analysis, the shipping sector’s need for an incremental 2 MMb/d of 0.5%-sulfur bunker less than 13 months from now cannot be met solely by a combination of fuel-oil blending, crude-slate changes and refinery upgrades. The catch is, most U.S. refineries are already operating at or near 100% of their capacity, so the bulk of the refinery-run increases will need to happen elsewhere. Today, we continue our look into how sharply rising demand for IMO 2020-compliant marine fuel may affect refinery utilization.
The planned shift from 3.5%-sulfur marine fuel to fuel with sulfur content of 0.5% or less mandated by IMO 2020 on January 1, 2020, will require a combination of fuel-oil blending, crude-slate changes, refinery upgrades and, potentially, increased refinery runs, not to mention ship-mounted “scrubbers” for those who want to continue burning higher-sulfur bunker. That’s a lot of stars to align, and even then, there’s likely to be at least some degree of non-compliance, at least for a while. So, what’s ahead for global crude oil and bunker-fuel markets — and for refiners in the U.S. and elsewhere — in the coming months? Today, we continue our analysis of how sharply rising demand for low-sulfur marine fuel might affect crude flows, crude slates and a whole lot more.
The planned implementation date for IMO 2020 is still more than a year away, but this much already seems clear: even assuming some degree of non-compliance, a combination of fuel-oil blending, crude-slate shifts, refinery upgrades and ship-mounted “scrubbers” won’t be enough to achieve full, Day 1 compliance with the international mandate to slash the shipping sector’s sulfur emissions. Increased global refinery runs would help, but there are limits to what that could do. So, what’s ahead for global crude oil and bunker-fuel markets — and for refiners in the U.S. and elsewhere — in the coming months? Today, we discuss Baker & O’Brien’s analysis of how sharply rising demand for low-sulfur marine fuel might affect crude flows, crude slates and a whole lot more.
Refineries along the U.S. Gulf Coast (USGC), which account for half of the country’s total refining capacity, are generally among the most sophisticated and complex anywhere, with configurations that enable them to break down heavy, sour crude oil into high-value, low-sulfur refined products. However, over the past eight years, the USGC has been flooded with increasing volumes of light, sweet crudes produced in the Eagle Ford, the Permian and other U.S. shale plays as new pipelines were constructed or reversed to the coast for domestic refining or export. Still more pipelines will be coming online over the next year. Today, we evaluate how much domestic crude oil has been absorbed into the USGC refining system, the implications to the overall crude slate qualities, and options for increasing domestic crude oil processing in the near term.
Phillips 66 loaded its first Panamax tanker for export to Mexico over the weekend. Late on Sunday night, the SCF Prime signaled that it was headed for Pajaritos, Mexico, after loading at Phillips' terminal in Beaumont, TX. Mexico is making history with this pivotal first purchase of Bakken crude from Phillips 66 at the U.S. Gulf Coast (USGC). Up until now, the crude oil trade between the U.S. and Mexico had been a one-way street, with oil moving from Mexico to the U.S. and not the other way around. But now, as Mexico’s state-run oil company Petróleos Mexicanos (Pemex) faces dwindling oil production and refinery outputs, importing light, sweet crude from the U.S. is a new avenue to revive Mexico’s refinery utilization. Today, we examine the new shift in the traditional flows of crude oil across the Gulf of Mexico.
When Philadelphia Energy Solutions (PES), owner of the East Coast’s largest refinery, recently announced it was seeking Chapter 11 bankruptcy protection, it begged a question: What happened? The answer requires a look back at the company’s original vision — namely, to capture the upside of the Shale Revolution by processing price-advantaged light, sweet crude oil produced in the U.S. — as well as a review of market developments that undermined its plan. Today, we look at the factors that drove PES’s hopes and why, in the end, they weren’t realized.
Over the past few years, rising production in the Canadian oil sands and U.S. shale plays such as the Bakken, Permian and Eagle Ford has given refiners new options for sourcing their crude, causing changes in oil pipeline utilization and prompting the development of new pipelines — or the reversal of existing pipes. A prime example of all this is playing out in Memphis, TN, where a Valero Energy refinery will be shifting from mostly U.S. Gulf Coast-sourced light crude to light crude that will flow in on the new Diamond Pipeline from the Cushing, OK, crude storage hub. Valero’s change in crude sourcing will be yet another blow to the 1.2-MMb/d Capline Pipeline, which for decades has moved crude north from the Gulf Coast to Patoka, IL, and other points along the way, including western Tennessee. Today, we look at the thinking and economics behind Valero’s plan and at the latest news on Capline.
California’s 12 remaining refineries don’t feel much love from their native state. The refinery fleet is particularly sophisticated — capable of refining mostly heavy and sour crude oil into the ultra-clean transportation fuels that state rules require. But state regulators seem to treat refiners like unwanted guests, to the point that rules have been put in place to actively encourage the shift from petroleum-based fuels to lower-carbon alternatives. The reward for refiners’ pain comes in the form of higher refining margins — particularly during unplanned outages. Today we weigh the rewards of higher gasoline and diesel prices today against a questionable future for refining in the Golden State tomorrow.
California refiners are under siege. State regulators seem to view crude oil refining as a nasty habit that needs to be broken. There’s an important catch, though: car-happy California is not only the nation’s largest consumer of gasoline — and second to Texas in diesel use — it allows only special, superclean blends to be sold within its boundaries. And California’s 12 remaining refineries need to meet tougher emission standards, too, making it difficult for them to expand their business or even modernize their plants. Today we discuss the irony that sophisticated refineries producing the cleanest fuels in the U.S. are faced with a shrinking market and no real hope of expansion.
On November 17, 2016, Tesoro Corp., the second-largest independent refiner in the Western U.S., announced an agreement to acquire Western Refining for an estimated $6.4 billion. This is the second acquisition that Tesoro has made this year, following the purchase of the MDU Resources/Calumet Specialty Products Partners’ joint venture refinery in North Dakota. And—ironically, considering the name of the company Tesoro is buying—the Western Refining deal will expand Tesoro’s footprint further east than ever. Today we evaluate the legacy assets of Tesoro and Western Refining and discuss how the two companies will likely fit together.