HOUSTON (Reuters) - Two years on, a gusher of U.S. shale oil production is finally starting to seep into California, where refiners in the country’s most isolated fuel market are waging an increasingly desperate battle to curb costs.
It’s far from certain, however, that cut-priced light crude from eastern Texas or North Dakota will arrive quickly enough or in sufficient volume to revitalize California plants in the same way new domestic oil has rescued East Coast refiners.
The nation’s toughest permitting rules, complex new carbon emission limits and a lack of pipeline infrastructure might delay the flow of large-scale shipments until the end of next year or beyond. By then the big discounts on the glut of U.S. inland crude might have diminished, some analysts warn.
For some companies it’s a make or break moment. Niche refiner Alon Energy USA Inc ALJ.N - which mainly produces asphalt for which demand has slumped - shut its underutilized southern California refining system in October and November while it builds an offloading facility to bring in inland crude by rail late next year.
It is the only California refiner so far to seek permits to build a rail offloading facility, according to state and local agencies, but others are definitely looking.
Meanwhile, other companies are looking to profit from the price discrepancies that have emerged from the record boom in output from previously untapped shale deposits.
Kirby Corp (KEX.N), the nation’s largest tank barge operator, bought rival Penn Maritime last month in a $295 million deal to boost its coastal fleet. Kirby is “starting to discuss” the idea of expanding those operations to the West Coast, moving oil from railway terminals in Washington State to existing marine import docks in California.
Kinder Morgan Energy Partners LP KMP.N Chief Executive Richard Kinder said there was “very enthusiastic” interest in a project to convert part of an underused natural gas pipeline to move crude to Southern California. The potentially $2 billion project would transport as much as 400,000 bpd of crude from West Texas and experts say it would take at least a year, if not two to complete.
The race is on and the clock is ticking. Other big projects across the United States are well ahead and could shrink the big discounts by 2014, according to Bernstein Research.
“It’s entirely possible California refiners decide they can’t get this done in time to catch the arbitrage, so refiners wouldn’t get the benefit of low-cost crude from the Midcontinent,” said David Hackett, president of energy consultancy Stillwater Associates in Irvine, California.
California’s sheer distance from other markets east of the Rocky Mountains - where the big shale fields are located - already sets it apart. No major pipelines carry crude to the West Coast. No major waterways flow east to west into the state’s refining hubs. Even the nation’s major freight railroads thin out over the mountain range and on the West Coast.
The state’s refiners have long depended on crude from now-shrinking fields in California and Alaska as well as Canada, where export infrastructure also has not kept up with rising production. Imported crude from Argentina to Asia now meets half of California’s demand, up from just 10 percent in 1995.
Ironically, California has its own huge shale play, the Monterey shale, estimated by the U.S. government to be the biggest such reserve in the country. But output has been disappointing and producers have struggled with geology that differs from other fast-flowing reserves.
So instead, local refiners are angling to bring in oil from places such as the Bakken fields of North Dakota and the Eagle Ford and Permian Basin in Texas, turning to railways to tap into domestic production that is running at its highest in two decades.
The incentive is clear. Bakken was priced at around $82 a barrel on Friday, while roughly similar quality ANS crude from Alaska was nearly $106, according to Reuters data. That’s a steal, even accounting for the up to $15 a barrel cost of shipping the oil by rail from North Dakota to the West Coast.
Phillips 66, which runs refineries in Los Angeles and San Francisco, is “looking for everything we can find,” says Tim Taylor, executive vice president of commercial, marketing, transportation and business development.
Its West Coast plants already use rail to export refined fuels and have some capacity for unloading crude, he added.
At the moment, it is a trickle, however. While more than 40,000 barrels per day of Bakken crude from North Dakota is moving west to Washington, it struggles to move south.
Tesoro Corp TSO.N - poised to take control of more than a quarter of the West Coast’s refining capacity when it closes a $2.5 billion deal to buy BP Plc’s (BP.L) Los Angeles area plant - is taking “a few thousand barrels per day” of Bakken to its California system, Tesoro Chief Executive Greg Goff recently told analysts. He did not specify which plants.
NuStar Energy Lp (NS.N), a logistics company, is using manifest shipments - individual tank cars that are less economic than dedicated unit trains - to get some inland crude to its terminal just outside the San Francisco Bay area, the company says.
“We expect to see more of these movements west,” Goff told analysts. “Regardless of the origination, additional crude oil supply should improve the West Coast crude oil position.”
But dedicated terminals are going to be needed to deliver crude in meaningful volume.
For a FACTBOX on West Coast refiners see: [ID:nL1E8NE6BU]
The scramble for cheaper crude comes just as California implements a landmark global warming law that requires emissions to match 1990 levels by 2020. Refiners say it might require hundreds of millions of dollars in upgrades to meet the requirements, potentially forcing some of them to quit the market.
One component of that law might also affect efforts to use more domestic crude: The Low Carbon Fuel Standard, or LCFS, that requires California refineries to run crudes produced in environmentally friendly ways.
The regulations have yet to be finalized six years after the law was passed and are now tangled in the courts. But experts say the LCFS could possibly shut out Bakken crude because of associated natural gas flaring during production, or even cheaper Canadian crude because of their emissions.
John Auers, senior vice president and a refinery specialist at Turner, Mason & Co in Dallas, said the method of transport also is likely to play a part in the “carbon intensity,” or CI, scale that determines which crudes they are allowed to process. That could tilt the scales in favor of nearby domestic crude, in spite of the higher carbon cost of truck or rail transport.
“Conceptually, I would think that LCFS rules should advantage domestic crude movements to California. That doesn’t mean it will,” Auers said.
A more definitive obstacle is the permitting process to build new infrastructure. While small-scale deliveries are likely to keep trickling in, new facilities must be built to handle the larger unit trains of 100 tank cars or more.
More than a dozen such terminals have already been built in the past two years, with more than 500,000 barrels a day of crude now running on U.S. railways, according to the Association of American Railroads. Two years ago that was near zero.
But in California, progress is slow.
Alon Chief Executive Paul Eisman told analysts last month that it may take “up to a year” to get all the permits necessary to build the rail offloading terminal near its 94,000 bpd refining complex outside Bakersfield.
“We’ve been in the queue for a few months, so we think that the permit process at this point is less than a year away,” he said. But he added there was still “a lot of uncertainty.”
By contrast, Tesoro applied to Washington’s state clean air agency for a permit to build its rail facility in July 2011, during the early stages of the Bakken boom. Approval came four months later and shipments of 40,000 bpd began this September.
Hackett said he is confident California refiners will figure out how to tap the growing U.S. flows because it is so cheap compared with imports that they can’t ignore it.
“It’s not an if, it’s a when,” he added.
Reporting By Kirsten Hays. Editing by Andre Grenon