Editor Rene Gonzalez editor@petroleumtechnology.com tel: +1 713 449 5817 Managing Editor Rachel Storry rachel.storry@emap.com Editorial Assistant Lisa Harrison lisa.harrison@emap.com Graphics Peter Harper Business Development Director Paul Mason Paul.Mason@petroleumtechnology.com ptq PETROLEUM TECHNOLOGY QUARTERLY Vol 30 No 5 Q4 (Oct, Nov, Dec) 2025
Refining industry shifting investments
I t is widely accepted that traditional refining for gasoline production is in struc - tural decline in the US, Europe, and elsewhere. Some of the strategies refiners are pursuing to diversify away from gasoline and distillate production include biomass-based co-processing, petrochemical-grade naphtha, renewable diesel (RD), SAF, and olefins production. Refineries built for heavy crude (common in Canada, Mexico, Venezuela) are now adapting to rising volumes of domestic light shale oil, but this requires multi-year, multi-hundred-million-dollar retrofits. For example, Exxon spent approximately $2 billion in Beaumont, and Chevron spent $475 million in Pasadena on retro- fits. Refiners are hesitant to fund major conversions due to uncertain long-term oil demand and shifting politics, prompting cautious decisions on such investments. In the short term, many refineries, like those on the US Gulf Coast, have debottle - necked crude/vacuum units, added preflash capacity, upgraded desalters, installed condensate splitters, and tweaked hydrocrackers/FCCs and reformers to handle lighter, sweeter slates. Against this backdrop, US crude oil production is mainly light shale crude, while high-complexity facilities have been designed to process low API gravity crudes from across the world, such as Western Canadian Select (20° API, 3.5% S), Mexican Maya (21°API, 3.3-3.8% S), and Arab Heavy (27° API, 2.8-3.5% S), which ideally requires a different complexity and configuration vs shale crudes. More than 70% of US processing capacity is configured to run heavier grades, and shifting the setup to increase shale crude processing can be lengthy and costly. Instead of expanding fossil fuel processing, certain refiners are investing heav - ily in RD, SAF, hydrogen, and biorefineries/co-processing. Indeed, according to a recent Reuters report, Marathon and other refiners are shifting as much as 50% (or more) of their yearly Capex towards co-processing-related projects. Refiners competing in emerging markets, such as Asia, are adjusting opera - tions to produce more naphtha, propylene, and reformate. These serve as chemi- cal feedstocks towards increasing olefins conversion from FCC units. This also includes butylene production to provide high-octane additives and alkylation unit feedstock, as some markets, such as India, are seeing increased gasoline demand. Other FCC units, previously optimised for gasoline, are targeting more light olefins (propylene) by using catalysts and operating conditions designed for higher olefin yield, and extracting olefin-rich fractions as chemical feedstocks. Typical olefin out - put still caps at 10-15%, though tweaks can increase yields. PTQ ’s FCC study, The FCCU in Transition to 2030 , provides a detailed look at the FCC processing and operational developments to coincide with market dynamics. For example, Asia is set to account for much of the global growth in FCC capacity, boosting petrochemi- cal yields from refining assets, including crude oil-to-chemical refinery types. In pursuit of higher margins petrochemicals, some refineries are collocating steam crackers and polymerisation units with traditional refinery operations. For example, ExxonMobil’s Baytown (Texas) complex houses three steam crackers with an eth- ylene capacity of ~3.6 million tpa, in addition to downstream polymer units. Other growth drivers include feedstock for aromatics units (such as paraxylene). In summary, traditional refining capacity is in structural decline, driven by gasoline and distillate alternatives, stricter regulations, and ageing plants. Big retrofits for shale integration are underway, but selectively, where feedstock flexibility is critical. The bulk of future investment is in renewable fuels, chemicals, and hydrogen. By 2030 and beyond, the refining landscape will centre on lean, efficient, hybrid assets, linking fossil refining with sustainable energy platforms tied to petrochemicals. Rene Gonzalez
tel: +44 7841 699431 Business Development Luke Massingham Luke.Massingham@ petroleumtechnology.com Managing Director Richard Watts richard.watts@emap.com Circulation Fran Havard
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PTQ Q4 2025
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