The West Coast is bringing in record amounts of crude from the interior of the U.S., cutting the price of foreign supplies and heralding the end of some overseas imports by next year.
California, the world’s ninth-largest economy, shipped via rail more oil than ever in February from North Dakota’s Bakken formation, while Russian imports to the region slid to 713,000 barrels from a June 2012 record of 6.53 million. The premium for Russia’s East Siberia-Pacific Ocean oil has retreated 60 percent against U.S. benchmark West Texas Intermediate since Feb. 20.
The drop in foreign purchases underscores the U.S.’s shifting needs as soaring output in states such as North Dakota and Texas put the country on course for energy self-sufficiency for the first time since Harry Truman was president in 1952. The West coast, home to 17 percent of the nation’s refining capacity, may be able to dispense with overseas light, sweet oil even as output from Alaska’s North Slope and California wanes.
“The crude supply on the West Coast is changing as we speak,” said Hege Dammen, a Weston, Connecticut-based solutions manager at Spiral Software, an oil-trading and refining software provider, and former crude trader for Norwegian Norsk Hydro ASA. “There’s been a lot of focus on getting oil by rail to the Gulf Coast, and the West Coast is moving forward now.”
ESPO crude, a light grade shipped by pipeline from fields in eastern Siberia to the Pacific port of Kozmino for export, dropped $1.79, or 1.7 percent, to $103.67 a barrel today, the lowest since June 13, data compiled by Bloomberg show. The oil has declined 12 percent from this year’s peak of $118.36 a barrel reached on Feb. 14.
The premium for Arab Light crude against WTI weakened to 85 cents a barrel, the lowest level since January 2011 and less than a 10th of what it was a year ago. It has averaged $10.56 this year.
Oil imports to the West Coast in the week ended June 14 averaged 1.2 million barrels a day, 9.5 percent below a year earlier, according to the Energy Information Administration, the Energy Department’s statistical arm. The western region, classified by the EIA as PADD 5, covers Alaska, Arizona, California, Hawaii, Nevada, Oregon and Washington.
California, PADD 5’s largest refiner, received an unprecedented 206,172 barrels of Bakken crude by rail in February, eight times the volume from a year ago. The state took in 94,695 barrels of Bakken crude in March, up from 70,706 a year earlier, according to the latest data available from the California Energy Commission.
Last year, Bakken oil began arriving in California on marine vessels for the first time, totaling 89,462 barrels, according to the commission’s data.
A complex along the Columbia River in Oregon, owned by Waltham, Massachusetts-based Global Partners LP, began in November off-loading trains of oil to send it by water to markets along the Pacific Ocean.
“Global Partners is getting some of this Bakken from rail-cars onto the water, and a number of California’s refiners are willing to buy it from them, just to get a taste of it,” Dave Hackett, president of energy consulting firm Stillwater Associates in Irvine, California, said by telephone. “It’ll back out the foreign stuff. That’s the first stuff that gets knocked out.”
Tesoro Corp. and Savage Companies, based in Salt Lake City, are planning a similar rail-to-water project at the Port of Vancouver in Washington that could move as many as 120,000 barrels of oil a day from railcars onto marine vessels.
Tesoro, based in San Antonio, is already using rail to bring 50,000 barrels a day of Bakken to its Anacortes refinery in Washington and 5,000 barrels to the Golden Eagle plant in Northern California. Alon USA Energy Inc., Phillips 66, BP Plc and Valero Energy Corp. are planning rail-offloading stations at their West Coast refineries.
Plains All American Pipeline LP, based in Houston, plans to start taking oil off railcars at a 140,000-barrel-a-day complex near Bakersfield, California, in the first half of 2014 and ship it by pipeline to refineries in the state.
The West Coast will more than double rail unloading capacity to about 600,000 barrels a day by the end of 2014 from 250,000 barrels a day currently, according to Andy Lipow, president of Lipow Oil Associates LLC in Houston.
The boom in oil production, driven largely by a combination of hydraulic fracturing and horizontal drilling, helped the U.S. meet 84 percent of its energy needs last year, the highest annual level since 1991, EIA data show.
Sending Bakken by rail to the West has proven so affordable that Kinder Morgan Energy Partners LP, based in Houston, suspended a proposal last month to build a pipeline that would have carried oil from Texas’s Permian Basin to California after failing to attract enough interest from shippers.
Carrying crude from the Bakken formation on railcars costs about $9.75 a barrel to Washington state, $13 to Northern California and $14 to the Los Angeles area, Tesoro Logistics LP estimated in a presentation June 7.
The increasing volume of domestic oil making its way to the West Coast will drive light oil imports out of the region by the end of 2014, Paul Y. Cheng, an analyst at Barclays Plc’s investment-banking unit in New York, said.
“The entire non-imported West Coast crude slate could undergo a $3- to $4-a-barrel downward shift as the marginal price-setting barrel switches from Alaska North Slope or imported light to Bakken crude rail on a spot basis,” Cheng said in a research note.
West Coast refineries, capable of running crudes more sour and heavier than the light, sweet oils coming out of U.S. shale plays, are blending Bakken and Canadian heavy in attempts to come up with Alaska North Slope “look-alikes,” said Dammen, the software solutions manager for Cambridge, England-based Spiral.
“When you blend them, you can actually come fairly close to ANS, maybe even having the same yield curve,” she said.
Alaska North Slope crude, about a 10th of California’s oil diet, is trading near a 16-month low against the U.S. benchmark West Texas Intermediate crude, according to data compiled by Bloomberg. The oil was unchanged versus WTI today at a premium of $9.40 a barrel.
California’s Kern River and Midway-Sunset grades both weakened to 18-month lows versus WTI futures last week.
Saudi Arabia, the largest oil exporter to the West Coast, supplied 207,000 barrels a day in March, the lowest for that month since 2010, EIA data show. Arab Light crude to the U.S. dropped $2.28, or 2.4 percent, to $94.44 a barrel today, a two-month low and down 12 percent this year, according to data compiled by Bloomberg.
Bakken crude for delivery at Clearbrook, Minnesota, was unchanged at $1 a barrel below WTI today, data compiled by Bloomberg show. North Dakota’s output of the oil climbed to a record 727,149 barrels a day in April, preliminary data compiled by the state’s Industrial Commission show. Production was up 33 percent from a year earlier.
West Coast refineries may eventually reach a limit to the amount of light, sweet domestic oil they can blend and run, according to Andrew Layton, a consultant with Walton-On-Thames, England-based KBC Advanced Technologies Plc.
Mixing the wrong kinds and percentages of light, shale oil with other crudes such as heavy Canadian can produce elements that damage plant equipment, a phenomenon known as “incompatibility,” Layton said. A “cocktail” of chemicals injected into crude blends can also corrode refinery equipment if not handled and monitored properly, he said.
“Individually, they may look innocuous,” Layton said. “Together, they may cause a problem.”
To push past the blending limits, the region’s plants could consider equipment upgrades, Hackett said. The refiners would have to weigh any long-term investments against increasing environmental regulation, particularly in California, he said.
The state’s cap-and-trade program regulates greenhouse-gas emissions from industrial plants including oil refineries with a goal of cutting pollution roughly 15 percent by 2020. California’s low-carbon fuel standard punishes fuel manufacturers who use crudes requiring more carbon to produce and transport than others.
“Investing in new equipment presumes that refiners still want to invest here,” Hackett said. “If they wanted to make changes to run more light, they could, but it’s kind of a bridge too far to say they will just yet.”