HOUSTON Dec 17 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
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 - 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, 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 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.
ISOLATED OUT WEST
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, e stimated by the U.S. government to be the
biggest such reserve in the country. But ou tput has be en
dis appointing an d producers have struggled with geo logy that
differs from other fast-flowing rese rves.
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
The incentive is clear. Bakken was priced at around $82 a
barrel on Friday BAK-, while roughly similar quality ANS crude
from Alaska ASW- 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 - 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 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, 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
"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:
OF CARBON AND PERMITS
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
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)