With confirmation of a steady increase in domestic crude oil landing in West Coast refineries via rail transport (see Shale Daily, June 10), the corresponding increase in rail oil terminal projects in the region is not surprising, although the buildout so far is concentrated in the Pacific Northwest, according to the California Energy Commission's (CEC) senior oil analyst.

How this building boom actually plays out carries ramifications for various Midcontinent shale producers seeking to broaden their market options with shipments west.

California has more than a half-dozen rail oil terminal proposals in various stages of development and permitting, but only a few actually operating. Some of that activity comes in manifest trains with mixed cars as opposed to the unit trains including 80 to 100 crude oil tank cars coming in one train.

One of the projects at a now-closed refinery in Bakersfield, CA, wants to bring in two unit trains daily of imported U.S. crude, and it has gained the permitting to start construction.

Increasingly, more rail-shipped crude oil from the Midcontinent finds its way to California refineries, but it comes indirectly from the Pacific Northwest through subsequent shipments in marine barges along the coast, according to Gordon Schremp, the CEC lead analyst watching oil supplies in the state.

"In the grand scheme of things, only about 1% of the overall oil supply refined in the state comes directly in here by rail," Schremp said, adding that the state's newest rail oil facility was opened last November near Bakersfield, CA, by Plains All American Pipeline in Taft, CA. It is designed to handle one 80- to 100-car unit train daily and is being challenged by litigation alleging the county did not do a thorough environmental review.

"The full [65,000 b/d] capacity is not necessarily what they are receiving since the project became operational," Schremp said. "It has to do with the relative economics for bringing in crude by rail at any given time." It depends on where the supplies are coming from (Utah, New Mexico, Bakken or Canada) and how wide the spread is between WTI and Brent oil prices, he said.

Even with the state's relatively arduous permitting process and these economic variables, Schremp listed six different pending rail oil terminal proposals and an existing terminal that has effectively been closed down in California amid the ongoing surge in overall rail shipments west.

The Sacramento Valley Railroad (SAV) Patriot rail oil terminal at a business park on the former McClellan Air Force Base property has had its operating permit withdrawn by county air quality regulators. It was offloading rail-shipped crude into tanker trucks for delivery to Northern California refineries like a similar rail oil terminal in Richmond, CA, still is doing, Schremp said.

"So now the only unit-train, all-purpose importing rail facility in the one near Bakersfield." He listed a half-dozen permitted, pending and planned projects that potentially could process 500,000 b/d combined. "They are still in various stages of the permit process." Existing rail receipt capacity is 133,000 b/d (including the 10,000 b/d Sacramento facility that lost its permit), he said.

California's proposed new crude-by-rail terminals include:

  • Valero Energy Corp.’s Benicia, CA, refinery project, to handle a unit train daily (70,000 b/d), for which a recirculated draft environmental impact report (DEIR) could be published in July;
  • WesPac Midstream LLC's proposed 50,000 b/d facility is seeking a local permit from the city of Pittsburg, CA in the East San Francisco Bay area, and is still awaiting a recirculated DEIR;
  • Targa Resources, a midstream logistics company, has a proposed a 70,000 b/d facility in the Port of Stockton, CA, to operate a combination rail and marine facility with barges ultimately taking the rail-shipped crude to refineries in Northern California;
  • Phillips 66 refinery in Santa Maria, CA, in northern Santa Barbara County, has a proposal for a 40,000 b/d rail oil terminal, in addition to the crude currently coming via pipeline or tanker truck;
  • Alon USA has a permitted project for revitalizing an idle Bakersfield refinery because of poor economics and have a permit to construct a two-unit train/day (150,000 b/d) offloading facility on the refinery property; and
  • Valero dropped previous plans for a rail oil terminal at it Wilmington refinery in the Los Angeles/Long Beach port area, and Questar Pipeline has preliminary plans for a rail oil terminal in the desert east of the Palm Springs area for a unit-train/d, but nothing formal has been submitted yet.

"I characterize the Alon project as being at the headwaters of the California crude pipeline distribution system, emanating from Kern County [in the southern end of the central San Joaquin Valley], so they would be able to get into the three major pipelines going north and the two major ones going south," Schremp said. "So far there has not been any announcements on construction."

Schremp said it was hard to speculate on how long it will take the various proposed new projects to get to a final permitting decision. "There is a lot of local, organized opposition to any of the rail oil terminal projects, including the ones with operating permits," he said. "All of them have done a lot of work and have prepared documentation, but all of them need more documentation."

By comparison, Washington state, which began crude-by-rail projects before California, today has more than 300,000 b/d of rail receipt capacity operational. In Oregon along the Columbia River at the deepwater port in Clatskanie, rail shipments of crude are received and put on barges for shipment to California and elsewhere.

"In 2013, we had a little bit more crude oil coming in by water from North Dakota than by rail," Schremp said, which is why Tesoro is pursuing a joint venture for a more than 200,000 b/d project at the Port of Vancouver in the Columbia River to bring crude by rail and then ship it in marine vessels primarily to California and to a lesser extent to Pacific Northwest refineries (see Shale Daily, Nov. 10, 2014).