Sept 18 (Reuters) - The mothballed Hovensa refinery, once the largest in the Western hemisphere, could be the latest “zombie refinery” to come back to life, revived by the U.S. shale boom.
Hess Corp and Venezuela’s state-run Petroleos de Venezuela (PDVSA) have found an interested buyer for their 350,000 barrel per day (bpd) Hovensa refinery in the Virgin Islands, sources close to the deal told Reuters on Wednesday, confirming a local news report that said the plant would use U.S. crude.
Refining at the plant has been halted since 2012, but its owners have been using it as a terminal. The Virgin Islands government has sought a buyer who will return the plant to its former status as an active refinery, according to a person familiar with refinery sales.
The identity of the buyer was not known, but sources told Reuters it would be a private equity firm. PDVSA declined to comment and Hess was not immediately available to comment.
Cheap U.S. crude and natural gas, available because of the shale boom, have created an advantage for U.S. refiners who have access to relatively inexpensive feedstock needed to fill refineries and a cheap furnace fuel to power them.
A four-decade ban on exporting U.S. crude has made it lucrative to produce gasoline, diesel and other refined products domestically, which can then be exported legally.
Restarting Hovensa on an island considered to be part of the United States could be a bet on the law remaining in place, even as it is being hotly debated from Texas to Washington.
Several “zombie refineries” on the East Coast have been restarted or saved from shutdown, according to Paul Sankey at Wolfe Research who coined the term, since the start of shale revolution.
Zombies that have reopened include the Delaware City refinery, which PBF Investments bought and restarted in 2010 after Valero shut it down, and the idled 185,000 barrel-a-day Trainer, Pennsylvania, refinery rebooted by Delta Airlines in 2012.
Hovensa’s ability to benefit from plum U.S. refining conditions might prove more challenging, according to industry analysts and consultants. Hovensa is oil-fired and does not benefit from vast U.S. gas fields.
Using cheap light sweet crudes from booming U.S. producing regions such as the Eagle Ford in Texas could be profitable, but also a challenge, because Hovensa was configured to run heavy Venezuelan and other foreign crudes.
“There’s no technical reason why you couldn’t process U.S. crude at that refinery,” said Neil Earnest, president of consultancy Muse Stancil.
But the input to the refinery would be reduced by more than 10 percent, Earnest said. Additionally, he cautioned that there would be significant costs associated with purchasing enough oil to restart the refinery, restaff it, and address any issues that had cropped up at the shuttered facility.
“The state of the process units likely varies,” he said.
Certain units, which were mothballed several years ago are probably in worse shape than those that were shut in 2012. The restart would take more than a few months, even under the best conditions, Earnest added.
A lighter diet would imply partially restarting the refinery, but not specialized units such as the delayed coker and the fluid catalytic cracker, traders said.
Hovensa had been buying up to 115,000 bpd of Venezuelan heavy Merey 16 and 155,000 bpd of medium Mesa 30 through long-term supply contracts. It also used to buy West African crudes.
The buyer would also need to sign agreements with several U.S. producers to guarantee a 200,000 to 300,000 bpd crude supply and meet the goal of reaching 350,000 bpd of processing, the same volume it was running when it was shut.
“I think the refinery can be profitable running cheap light crude, even if it operates at only 50 percent to 60 percent of its full capacity,” said one person familiar with the plant.
Hovensa can process a maximum of 500,000 bpd.
And shipping the U.S. crude to the islands might be less costly than sending it to foreign plants.
The Virgin Islands are not considered to be a “coastwise point” and are specifically exempt from the Jones Act, a shipping restriction that requires ships to be U.S. built, owned and crewed, said one lawyer with expertise in maritime affairs.
Charter rates have soared for the limited fleet of Jones Act vessels, making them around three times more expensive than foreign-flagged ships. But shippers would be able to use cheaper, more plentiful foreign-flagged ships to transport the crude.
The lawyer also pointed out that bringing crude to Hovensa and shipping refined products back to the United States would not require Jones Act vessels since the oil would have been processed into a “new and different product” at the refinery.
In the late 1970s, the refinery was at the center of a court case, American Maritime Association v. W. Michael Blumenthal, which questioned whether the Jones Act applied to U.S. oil refined or otherwise processed at an intermediate point before being brought back to the United States.
The lawsuit was successful and Hess was permitted to bring crude oil from Alaska to the Virgin Islands on foreign-flagged ships.
It is not immediately clear if shippers would need to obtain a license under the U.S. crude oil ban to ship domestically produced oil to the U.S. territory.
Alaska, which has an exception to the crude oil export ban, used to ship small amounts of crude to the Virgin Islands and Puerto Rico before oil output started falling. According to Energy Information Administration records, the U.S. last sent oil to St. Croix in 1997. (Reporting By Jessica Resnick-Ault in New York, Marianna Parraga in Houston, Tim Gardner in Washington D.C., and Anna Louie Sussman in New York; Editing by Josephine Mason)