Will Texas Ship Crude to California?

Texas is eyeing the possibility of shipping its excess crude oil to California, a state that historically imports from the Middle East and Ecuador.

In September 2013, Texas produced its highest monthly rate of natural resources on record – pumping 2.7 million barrels of crude per day, the highest average of oil output in over 32 years, according to data from the U.S. Energy Information Administration. With this excess crude, Texas might become a supplier of oil to California if the trade is profitable.

Once an oil exporter, the Golden State now depends on imports for more than 60 percent of its oil supply. About a quarter of California’s imports are from Alaska, with the rest coming from the Middle East and Ecuador, according to the U.S. Energy Information (EIA).

However, because of California’s history as an oil producing and exporting province, its refining industry was originally built to process local crudes. The state’s refineries have evolved from processing California oil to processing a mix of California crudes, Alaska North Slope, Arab heavy and Ecuador Oriente, among others, according to Gregory D. Croft, University of California, Berkeley.

“As the state continues to witness declining domestic production and the Kern County fields lessening, given the technology and the geology, it’s really not viable that California will be a major producer for quite a while,” stated Christopher Guith, vice president for policy at the U.S. Chamber of Commerce’s Institute for 21st Century Energy to Rigzone.

Should the Jones Act be Modified or Abolished?

Until now, a U.S. policy, the Jones Act, made domestic shipping more expensive, as California imported oil from the Middle East, Ecuador and Alaska’s North Slope. If a shortage of qualifying ships can be overcome, Texas crude could become affordable on the West Coast as the highest domestic output creates a surplus of light oil while driving prices down.

“It always comes down to economics,” Guith stressed. “Traditionally, Alaska had been the source for a huge chunk of California’s resources, and that’s still the case, but if you look at the economics, it’s significantly cheaper, both from the initial price per barrel, as well as transportation costs, to move Canadian Albertan crude or Texas crude.”

“Both Middle Eastern, as well as African imports, are going to erode pretty quickly,” Guith stated. “When this comes on line, there is no way that Middle Eastern crude can compete both at a per barrel cost, plus knowing that a lot of U.S. is trading at a discount to WTI, plus cheaper transport costs.”

Transporting and the Jones Act

With the lack of infrastructure from Texas to California, industry players are petitioning the government for a repeal of the Jones Act, a maritime act in place since the 30s, which demands for U.S.-flagged only vessels to transport goods between U.S. ports. This repeal would allow for domestic sweet crude to move economically between ports, displacing foreign sweet imports, while maintaining the crude oil export moratorium for the United States (except Alaska).

Historically, shipping between U.S. ports have cost more than international voyages, but currently, the economics are already working on U.S.-flagged vessels. Platts reported that the majority of U.S.-flagged tankers are dedicated solely to Alaska through the California route of Alaska North Slope (ANS) crude, but this is already changing as ANS production continues to decline and the need to transport domestic crudes such as Eagle Ford via tanker increases.

A qualified tanker’s rates may still beat the cost of transporting oil by train, depending on the situation, Guith remarked.

“There are two options. The preferable option is rail the whole way, with the secondary option being to get the crude to Washington either by rail or pipeline, and then ship it via Pacific Ocean, down to California,” he said. “Traditionally, that’s how California gets the bulk of its imports, coming down from Alaska. But the economics are significantly cheaper for rail and/or tanker.”

Rail costs to Washington State from North Dakota’s Bakken field cost about $9 a barrel, while Alberta, Canada to California costs $13 to $15, Valero Energy Corp. said in a Nov. 13 presentation.

Overall, domestic light sweets are finding additional demand on the U.S. West Coast, as the infrastructure to receive Bakken in California is beginning to emerge, according to a Platts special report, “New Crudes, New Markets”. Alon USA plans to bring in Midcontinent crude by rail to resell into the Los Angeles market, rather than use for its own 68,000 barrels per day idled refinery in Bakersfield, California. At the time of publication of this said report, Alon was 8 to 10 months away from receiving shipments of Midcontinent crude by rail. Those supplies would likely be shipped by pipeline into the Los Angeles market, Platts reported.

Tesoro is receiving Bakken at its Anacortes, Washington refinery, and Alon USA is building infrastructure to receive Bakken and midcontinent crudes at its Bakersfield refinery. It is projected that this facility could then be a rail offloading hub for Bakken to move to Los Angeles.

“The owners of refineries that operate in California have already been beneficiaries of domestic production, and especially in the mid-Atlantic, so they’ve seen this all coming and they’ve started to invest in the infrastructure to make it happen,” Guith stated.

With no existing infrastructure from Texas to California, rail or tankers are the two only options to transport the needed resources.

“Refiners are willing to pay a premium for rail delivery because one, it doesn’t lock them into a 20-year commitment and more importantly, it gives them flexibility as far as what the terminus is.”

The country’s second-largest natural gas pipeline operator, Kinder Morgan, recently announced a deal to buy APT New Intermediate Holdco LLC and State Class Tankers II LLC from private-equity firms Blackstone Group LP and Cerberus Capital Management LP for $962 million in cash. This deal will give Kinder Morgan five Jones Act tankers and four more under construction, with each able to carry 330,000 barrels, the company said in a Dec. 23 statement.

“I feel that transporting by tanker than rail will probably be cheaper,” said Foster Mellen, senior oil and gas analyst at Ernst & Young, to Rigzone. “It will depend on the size of the tanker, the tolls through the Panama Canal and the time it’ll take, but I suspect yes, it’ll happen given the ability to transport bigger volumes at a time.”

Kinder Morgan has been in discussion with customers that would use Jones Act tankers to move production from out of Texas, through the canal and then to California, Richard Kinder, chairman and chief executive officer, said on a Jan. 15 conference call.

When asked about the status of any firm projects, Richard N. Wheatley, a Kinder Morgan spokesman, stated, “It is up to the customers to determine.”

The company is also looking to convert existing natural gas pipelines between Texas and the West Coast into a crude pipeline that would move Permian grades from west Texas to Southern California refiners. The project, Freedom Pipeline, has the potential to move 250,000 to 400,000 barrels of crude. Kinder Morgan is said to be in discussions with shippers to ascertain interest, but if it is a go, would take one to two years to complete the pipeline reversals pending regulatory approval, Platts reported.

The organization predicted that while light sweet crude imports were 275,000 barrels per day into PADD V at its peak in 2012, domestic sweet crudes would likely be a cheaper alternative to heavier grades from Asia and the Middle East.

As the West Coast continues to import 1.25 million barrels a day, its reliance on imports will only increase in the near future but its dependence on foreign supplies could slowly decline.

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