Kinder Morgan Energy Partners LP (KMP), the pipeline operator that’s buying U.S. oil tankers, said it’s in talks to ship Texas crude to California through the Panama Canal. The 4,500-mile voyage would cost about $10 a barrel, broker Poten & Partners Inc. estimates, making Texas crude competitive with imports traveling 11,400 miles from Saudi Arabia, the West Coast’s largest supplier, data compiled by Bloomberg show.
Until now, a U.S. law that makes domestic shipping more expensive left Californians buying oil from the Middle East instead. If a shortage of qualifying ships can be overcome, Texas crude will become affordable on the West Coast as the highest domestic output in a quarter century creates a surplus of light oil and drives down prices.
“The West Coast has been short crude over the last couple of decades with Alaska North Slope and California oil production down,” Andy Lipow, president of Lipow Oil Associates LLC in Houston, said by telephone. “Getting more crude from other areas of North America into the West is going to help refiners, and if you have a big glut of light, sweet crude on the Gulf Coast, tankers will load.”
The posted price for light crude from Texas’s Eagle Ford shale formation has climbed 0.5 percent in the past year to $93.75 a barrel, according to the marketing division of Plains All American Pipeline LP. (PAA) That compares with $98.79 for light Saudi Arabian crude and $96.29 for the equivalent Iraqi grade, plus $3.38 for shipping to the U.S. West Coast, according to data compiled by Bloomberg.
Shipping between U.S. ports costs more than international voyages in part because a 94-year-old law called the Jones Act requires domestic cargoes to travel on U.S.-built, -owned and - crewed vessels. A qualifying tanker commands record rates close to $100,000 a day, according to MJLF & Associates, a broker. That’s about 10 times more than a tanker of the same size that doesn’t meet the requirements, according to data from Clarkson Plc (CKN), the world’s largest shipbroker.
Using a Jones Act tanker may still beat the cost of transporting oil by train, Court Smith, head of research at Poten in New York, said Jan. 17. He has since left the company.
Rail costs to Washington State from North Dakota’s Bakken field run at about $9 a barrel, while Alberta, Canada, to California costs $13 to $15, Valero Energy Corp. (VLO), the world’s largest independent refiner, said in a Nov. 13 presentation. The company said it would consider the trade if it’s economical.
Crude-by-rail operations are facing more regulatory scrutiny after the derailment of a train carrying oil that killed 47 people in Quebec in July and a Dec. 30 explosion in North Dakota involving a train carrying Bakken crude.
“Rail is the most expensive, it takes a long time and obviously you can see clearly what happened over the last few weeks and few months of accidents,” Fadel Gheit, a New York-based energy analyst for Oppenheimer & Co., said in a Jan. 21 interview on Bloomberg Radio.
Kinder Morgan, the country’s second-largest natural gas pipeline operator by market value, agreed to buy APT New Intermediate Holdco LLC and State Class Tankers II LLC from private-equity firms Blackstone Group LP (BX) and Cerberus Capital Management LP for $962 million in cash. Once final, the deal will give Kinder Morgan five Jones Act tankers and four more under construction, each able to carry 330,000 barrels, according to a Dec. 23 statement.
“Increasingly we’re talking to people, no firm commitments, who think that they will use Jones Act tankers, that have to be Jones Act, to take production out of Texas and move it through the canal and back up to California,” Richard Kinder, the company’s chairman and chief executive officer, said on a Jan. 15 conference call. Richard Wheatley, a spokesman, declined to elaborate.
Kinder Morgan’s net income will rise 31 percent to $1.3 billion this year, according to the average of 11 analyst estimates compiled by Bloomberg. Its shares will rebound from a 12 percent decline in the past year to gain 9.1 percent to $86.56 in 12 months, the average of nine estimates shows.
The oceangoing Jones Act fleet of about 85 ships is fully booked, with no tankers available for one-time cargoes, said Pat Calahan, a broker and project consultant at MJLF in Stamford, Connecticut. The ships Kinder Morgan is buying from American Petroleum Tankers are all booked for several years on long-term contracts, according to a Dec. 23 company statement. The State Class ships are scheduled for delivery in 2015 and 2016.
The vessels are able to cross the Panama Canal, even before the $5.3 billion expansion that will double the waterway’s capacity. The project is scheduled to finish next year, with contractor Sacyr SA (SCYR) pledging to continue construction after threatening to suspend work unless the canal authority paid for cost overruns. The parties will continue talks until Feb. 1. The expanded canal could allow larger tankers to reposition from Alaska, according to Poten.
The Texas-to-California trade will be more feasible when there are surplus Jones Act tankers, Calahan said. There are 32 oceangoing tankers and 42 barges, plus 11 dedicated to shuttling between Alaska and the West Coast, and 16 more under construction, according to MJLF.
“There needs to be more length built into the Jones Act fleet before the industry takes a look at shipping to the West Coast,” Glenn Simpson, general manager of crude and international supply at Phillips 66 (PSX), said Jan. 22 during a conference in Houston. Phillips 66 runs three refineries in California and Washington state that can process a combined 315,000 barrels a day. The company has used Jones Act tankers to send Eagle Ford oil to its 238,000-barrel-a-day Bayway refinery in New Jersey.
Kinder Morgan has tried to move Texas oil to California before. The company shelved plans in May to build a pipeline that would have carried 277,000 barrels a day from West Texas’s Permian Basin to California’s refiners by late 2016. Citing lack of customer interest for the pipeline, Kinder Morgan said at the time that it would focus on rail projects instead.
There are no pipelines linking the Gulf and California. The last time a ship carried crude between the Gulf and West Coasts was in August 2012, Energy Department data through October 2013 show.
In the past six months, two U.S.-flagged tankers crossed the Panama Canal. Chevron Corp. (CVX)’s California Voyager left Freeport, Texas, on Jan. 9 and was anchored near San Francisco, ship-tracking data compiled by Bloomberg show. The S/R American Progress, a Jones Act tanker owned by Exxon Mobil Corp. (XOM)’s SeaRiver Maritime Inc., left Los Angeles on Jan. 5 and is anchored near Beaumont, Texas, signals show.
Spokesmen for Chevron and SeaRiver declined to comment.
The West Coast imports about 1.25 million barrels a day, with 24 percent coming from Saudi Arabia, according to October data compiled by the Energy Information Administration, the Energy Department’s statistical arm. Ecuador supplies 16 percent, with another 15 percent from Canada and 13 percent from Iraq, data show.
California’s daily output dropped from as much as 1.1 million barrels in 1986 to 547,000 barrels in October, Energy Department data show. Alaskan production slumped to 521,000 barrels a day from more than 2 million barrels a day in 1988. The state’s supplies are poised to rebound as the repeal of a production tax triggers investments that may boost output by at least 90,000 barrels a day within four years.
The West Coast’s reliance on imports contrasts with the country as a whole, which is meeting the largest share of its own energy needs since 1986, Energy Department data show. Nationwide production topped 8 million barrels a day in November and rose to the highest since 1988 as hydraulic fracturing and horizontal drilling unlock resources in shale rocks deep underground.
Because West Coast fuel producers can’t get that oil, their refining margins of $13.64 a barrel are lower than the $15.21 on the Gulf Coast, data compiled by Bloomberg show. A gallon of regular gasoline costs $3.486 on the West Coast and $3.092 on the Gulf Coast, according to the Energy Department.
The Gulf Coast may even have more domestic oil than it can handle because refineries are configured for heavier grades. The glut is leading to calls -- from Senator Lisa Murkowski, the top Republican on the Energy and Natural Resources Committee, to the American Petroleum Institute, the oil industry’s lobbyist -- to lift the ban on most crude exports. Moving Texas oil to California would provide another outlet.
“The West Coast is struggling through a decline in oil production and having that additional Eagle Ford oil there -- what are the disadvantages at this point?” Taryn Slimm, an oil and gas analyst who covers U.S. unconventional plays for London-based GlobalData, said by telephone from New York. “It is an opportunity for the West Coast, and it’s going to relieve the projected glut that we have on the Gulf.”
Valero, which runs refineries in the San Francisco and Los Angeles areas, doesn’t ship crude through the Panama Canal to its California plants, “although we would certainly consider it if it made economic sense,” Bill Day, a spokesman at the company’s headquarters in San Antonio, said by e-mail Jan. 16.
The company is planning a complex at the 170,000-barrel-a-day Benicia refinery in Northern California that would allow the plant to unload as much as 70,000 barrels of crude a day from rail cars. The project is pending city approval.
Tesoro Corp. (TSO), the largest refiner on the U.S. West Coast, leases space on Petroterminal de Panama SA’s Trans-Panama pipeline, Tina Barbee, a spokeswoman at company headquarters in San Antonio, said by e-mail. The 131-kilometer (81-mile) line can carry as much as 800,000 barrels of oil a day. She declined to comment on the Tesoro’s future strategies.
“Someone might say right now, ‘Let’s see if we can make this work,’” said David Hackett, president of oil consulting firm Stillwater Associates in Irvine, California. “Straight up, on a freight basis, Eagle Ford to California works.”
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