When the Philadelphia Energy Solutions refinery closed this year after an explosion and fire, there was concern that taking out the East Coast’s biggest refinery right ahead of the introduction of IMO 2020 could be one more factor that could lead to fuel problems for the market and particularly the East Coast.
That has not happened so far. It is true that total distillate production in PADD 1, the energy-designated area that includes the East Coast, was consistently above 300,000 barrels/day for most of the year through June, but more recently it has been around 250.000 b/d or less following the PES closure. But total distillate inventories in PADD 1 have been running either side of 45 million barrels; that is not low by historical standards.
And now coming to the “rescue” is a quasi-new refinery: Limetree Bay Refining, at St. Croix in the U.S. Virgin Islands. Limetree Bay Refining is a venture between private equity company ArcLight Capital Partners and Freepoint Commodities. It bought the shuttered Hovensa refinery in 2016. Hovensa had been a joint venture between Hess Oil and Venezuelan state oil company PDVSA. But it found itself challenged to compete against U.S. refineries that were able to benefit from cheaper domestic crude as the shale boom kicked in, and it closed in 2012, taking a refinery with a whopping capacity of 650,000 b/d off the market.
That peak capacity is still there, embedded in the plant, but Limetree Bay says it will launch the refinery toward the end of this year with 200,000 b/d. Late last year, the company announced an agreement with BP (NYSE: BP) to feed the plant with crude and other feedstocks and take off most of the output.
Morningstar energy analyst Sandy Fielden recently put out a report on the refinery and what it might mean to the market. As Fielden observes, Limetree Bay has several advantages. First, although St. Croix is a U.S. territory, shipments of crude to it are not subject to the Jones Act. So the U.S. crude export capability that has grown up since Hovensa was closed in 2012 can feed it competitive U.S. crudes without paying exorbitant Jones Act freight rates. Second, the refinery is configured to produce fuels that are compliant with IMO 2020. Finally, since 2012 the refining centers of the Atlantic Basin and the Caribbean have suffered not only the loss of PES but the collapse of the Venezuela refining industry, knocking out competitors.
But as Fielden noted, the advantage of Limetree Bay is not just that it can take in crude without being shipped in on Jones Act ships. It’s that it can also export its products to the U.S. East Coast–which is already net product deficient, only getting wider after PES closed–without sending it on a Jones Act ship. And that is an advantage over U.S. Gulf Coast refiners, which must ship their intra-U.S. “exports” to the East Coast on a Jones Act vessel. (In June, according to the Energy Information Administration, shipments of all distillates on the water between the U.S. Gulf Coast–PADD 3–and PADD 1 were about 139,000 b/d.)
“(Jones Act) vessels can cost as much as 3 times more to operate than non-U.S. flagged tankers,” Fielden’s Morningstar report said. “Not having to be Jones Act compliant makes Limetree Bay shipments competitive with Gulf Coast shippers moving refined product to PADD 1 using costlier U.S. flagged vessels. Although effectively a legal loophole, this advantage was an important element of the legacy Hovensa refinery market and could benefit East Coast consumers in light of the PES closure this year.”
The Limetree Bay refinery has a coker, a complex refining unit that can perform what is known as “deep conversion:” and produces higher quantities of lighter fuels–like distillates–and lesser quantities of heavy fuel oil. With IMO 2020 on the horizon, mandating low-sulfur marine fuels, that leaves Limetree Bay well-suited to take advantage of the new rule, according to Fielden.
Fielden cites a separate estimate that the southern Caribbean market for marine fuels, sitting in the middle of major ocean-going lanes, is a little less than 300,000 b/d.
“Replacing those supplies with low-sulfur alternatives will challenge existing local refineries, which don’t have tertiary processing capacity to break down heavy fuel oil to lighter, low-sulfur products,” the Fielden report said. “The Limetree refinery coker unit is designed for just that purpose.”
Stand-alone refiners in the U.S. without a retail or wholesale distribution network have been burdened by the need to meet renewable fuel standards by purchasing RINs, which is a government-created credit that allows a company to avoid blending ethanol. Ethanol, because of certain characteristics, can’t be blended at a refinery. So a refinery without a distribution network is at the mercy of the RINS market to meet its obligations under the Renewable Fuel Standard.
Limetree Bay would fall in that category. But part-owner ArcLight also owns Transmontaigne Partners, which is a major system of wholesale terminals throughout the U.S. It also owns the Gulf Oil retail network. Between that and the BP offtake deal, it sets up Limetree to be an independent refiner that lacks a distribution network but can potentially partner with others to dodge the RINs burden. (By contrast, PBF Energy, a major independent refiner, incurs annual RINs expenditures measured in the hundreds of millions of dollars).
Limetree Bay has one burden that hurt other Caribbean refiners: its fuel source. As U.S. natural gas prices fell from the shale boom beginning about 10 years ago, U.S. refiners increasingly turned to that fuel, rather than fuel oil, to power their plants. Caribbean refiners had no such option and many of them cited that disadvantage as they closed, one after the other.
It’s a problem, Fielden concedes. But the growth of the world LNG market, and in particular supplies out of the U.S., may help solve it. “If Limetree can harness LNG fuel priced at a differential to U.S. benchmark Henry Hub prices, the refinery will be better equipped to compete with Gulf Coast rivals in the long term,” he writes.