U.S. refiners will likely replace just over half of the 500,000 b/d of Venezuelan imports with Canadian crude by rail and potentially some crude from the Arab Gulf but may still lower USGC refinery throughput for a few weeks. Venezuela will have a harder time adjusting, as China and India will only take a portion of the displaced volume. Venezuela’s 100,000 b/d of imports of naphtha, diesel, and gasoline from the US will need to be diverted to other destinations or could encourage slightly lower runs in the Gulf Coast. Lower naphtha exports and perhaps marginally less blending of shale with heavy crude will put a bit more pressure on U.S. crude production.
As a result of yesterday’s sanctions by the US Treasury, US persons are now prohibited from engaging in transactions with PdVSA, including its subsidiary CITGO. The U.S. can continue to import crude from PdVSA but will have to put the payment in an account for new president Guaidó. Venezuela will not sell crude for free, so this will stop U.S. imports of 500,000 b/d of Venezuelan crude, prevent exports of 100,000 b/d of product from the US to Venezuela, and force CITGO to put its money in escrow if it is to keep operating.
US refiners will have to adjust crude slates and possibly cut runs. From April to October 2018, US refiners – including CITGO, Valero, Chevron, and Paulsboro – imported more than 500,000 b/d of Venezuelan crude. 400,000 b/d of that is around 16 API and most of the remaining 100,000 b/d is even heavier, around 12 API. Refiners will use several options to avoid significant disruption from the import ban. First, US Gulf Coast crude imports by rail from Canada have the capacity to increase by as much as 250,000 b/d in the next couple months. There are few other options to source crude that heavy: one possibility is Kuwait, which produces over 100,000 b/d of extra heavy. Latin America provides the majority of crude 20 API or less to these refiners, and other producers are not in a position to raise production. Mexico’s Maya blend, at 22 API, is lighter than the Venezuela Orinoco exports, Ecuador’s Napo blend is contracted to China, and Colombia does not have the capacity to raise production significantly. From these options, refiners are likely to be able to replace most but not all of the banned 500,000 b/d of extra-heavy sour crude. Still short some heavy crude, US refiners will also likely adjust crude slates to run more medium, cut back throughput, and reduce coker utilization.
Venezuela will find it difficult to sell this displaced crude and may have to shut in production. Besides the US, India and China are the main purchasers of Venezuela’s extra-heavy crude. In 2018, India imported 350,000 b/d of Venezuelan crude, mostly to the Jamnagar and Vadinar refineries, while China imported 330,000 b/d. These volumes are a combined 150,000 b/d lower than the import levels of 2017, so Venezuela may be able to sell more there. There are few other refineries, however, able to process significant volumes of heavy oil.
U.S. will stop exporting 50,000 b/d of naphtha, 30,000 b/d of diesel, and 20,000 b/d of gasoline to Venezuela. The naphtha, used to dilute the heaviest crude, can be replaced with imports from Russia. The gasoline and diesel imports will either be re-sold from the US through traders or imported from Europe. The gasoline glut should make spot purchases easy, but getting diesel, also likely from Russia, will be more challenging. Meanwhile, U.S. exporters will have to shift their sales to other countries and lower naphtha exports. Marginally less blending of shale with heavy crude may put a bit of pressure on U.S. crude production.