Earlier this month, US Midstream logistics firm Targa pulled out of a crude by rail marine dock project at the Port of Tacoma, WA. The plan was to rail crude from the Bakken to barges and tankers for shipment to refineries in Washington State and California. Other rail projects in California like the Valero Benecia terminal have been delayed by permitting issues. Some folk are questioning whether these setbacks mean that crude- by rail to the West Coast has gone off the boil. Today we begin a two part review of West Coast rail prospects.
Targa planned to use the Port of Tacoma site to build a rail yard and tank farm to receive 100 car unit trains with crude oil from the Bakken as well as biofuels such as ethanol and biodiesel. The facility would have provided marine barge and tanker loading to ship fuels to Puget Sound and California refineries. Targa was apparently unable to identify an “economic path forward for the project” and terminated their lease. Targa also dissolved an agreement with Phillips 66 to deliver 30 Mb/d of crude to that company’s Ferndale, WA refinery that would have been shipped through Tacoma.
Not being privy to Targa’s internal analysis of their project, we can’t say for sure why they got cold feet. Our analysis indicates that there are still plenty of crude by rail terminals being built on the West Coast and we will update the status, timing and expected capacity of those terminals in Part 2 of this series. First though we take a look at how the economics of moving crude to the West Coast by rail have changed since the start of 2013. We looked at those economics in April (2013) when we surveyed crude by rail (see West Coast Destinations). In that analysis we noted a growing number of rail terminals in the Northwest designed to feed Puget Sound area refineries as well as a smaller number of terminal plans developing to feed California refineries. Most of those terminals were being developed with the idea of shipping Bakken crude from North Dakota by rail to the West Coast.
For Bakken producers and shippers, the economics of moving crude from North Dakota to the West Coast by rail are governed by the price spread between Bakken crude and the West Coast benchmark Alaska North Slope (ANS). So far this year those economics have been favorable.
The chart below shows crude prices this year for ANS sold on the West Coast (at Long Beach CA), posted prices for Bakken light sweet crude in North Dakota and prices for West Texas Intermediate (WTI) – the benchmark Midwest crude at the Cushing, OK trading hub. You can see that the ANS price (purple line) is the highest, with WTI (red line) in the middle and the Bakken posting (green line) at the bottom. Bakken posted prices are set by crude gatherers in North Dakota at a discount to WTI at Cushing (see The Bakken Buck Starts Here). ANS prices are set by international competition to supply refineries on the West Coast as well as the relative price of California grades (see After The Oil Rush). Although differences between the qualities of these crudes are also important influences on their price, rail movements generally become economic when ANS premiums to Bakken postings are sufficient to cover rail transport costs from North Dakota to the West Coast. And that has been the case throughout this year so far. The average ANS premium to Bakken postings year to date (September 24, 2013) was $22.49/Bbl and the average in September was $16.31/Bbl. Our conservative estimate of rail shipment costs from North Dakota to Washington State (including gathering and terminal fees) is $15/Bbl. A Bakken producer would have received an additional ($16.31 - $15) or $1.31/Bbl more to ship their crude to the West Coast in September or an average ($22.49 - $15) or $7.49/BBl year to date.
Source: Alaska Department of Revenue, Plains Crude Posting
The US crude market evolved considerably this year as the WTI discount to coastal crudes such as ANS narrowed from $16/Bbl in January to $4-$5/Bbl today. That narrowing discount reflected the unwinding of a supply logjam in the Midwest that pushed WTI prices down relative to coastal crudes like ANS. Nevertheless the economics of shipping crude to the West Coast remained favorable. When we did the math in July - calculating netback prices for crude from North Dakota to the East, West and Gulf Coasts as well as Cushing, the results showed that netbacks for sending crude by rail to the West Coast were second only to shipping to the Gulf Coast by pipeline (see Netback, Netback, Netback to Where You Started From).
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Comments
The ANS (alaskan north slope), WTI and Bakken chart shows a remarkable correlation.
WTI-ANS: I understand that there is an arbitrage working between pacific bassin and atlantic bassin help by Bakken pushing down the spread.
RBN I'm curious to see heavy-light spreads, WCS Crack Carbob with the North Slope 3-2-1 Carbob crack spread for both Diesel and gasoline because If we push the H/L spread elastic too far, logically : demand for WCS and Heavies will rebound, heavies/WCS crack margins will become more appealing, pushing down lights. This is what happened on the second chart.
Unlike WCS that is a blend of oil sands crude diluted with light hydrocarbons to ship by pipeline, refiners with heavy crude capacity prefer “raw” oil sands bitumen crude. That crude can only be shipped to market in insulated and coiled railcars from Alberta in the same way that we described in the “Go Your Own Way” series.
Do Californian refineries have a configuration for western canadian select and what is the % of the north american rail car fleet that can accomodate WCS with special rail tanks.
Targa was apparently unable to identify an “economic path forward for the project” and terminated their lease.
Let me explain this, California is an island ( RBN did a nice blog about California Crude Supply options).
- If you want to ship gasoline to california, Gasoline imports are locked by CARBOB tight green laws + RINS.
- If you want to ship oil such WCS, you will have limitation because of cali' refinery complex or a limitation for heavy demand, ANS has an advantage because WC refineries built in the 70's were meant to handle its ideal characteristics).
Market Works.
It is interesting that Chevron and Valero use more and more their Cali Refineries for clean products exports off the WC to S. America, Canada, ( exactly the reverse than the traditional USGC->Panama->USWC Flow).
http://jacquessimon506.wordpress.com/
Simon
The comparative economics of Bakken and WCS to ANS may hold true for rail delivered directly to a refinery, but is missing an additional waterborne shipping from a third party terminal. On Jones Act ships or ocean-going barges, that is a substantial cost.
Bill Osmer from Tesoro Maritime Company recently said in a panel that they are ready to ramp-up Bakken at Anacortes WA. They have an access to WCS via Trans Mountain.
Refiners have plans to supply Light crude by Railcars from Bakken to blend and refine a Synthetic ANS (BP Amoco Cherry Point Refinery, Conoco Philips Ferndale Refinery, Tesoro Anacortes Refinery, Shell Anacortes Refinery)
It will be good for jones act tankers owners, not necessarily negative for refiners, about 3-4$ freight cost per Bbl. (yes this is ridiculously enormous) but
http://jacquessimon506.wordpress.com/2013/04/21/jones-act-the-impacts-on-freight-and-energy-markets/
the real risk/opportunity is the H/L spread.
Take a look at Turner Mason's LP model based on a synthetic ANS(55% bakken, 45% WCS blend). Itcould yield +13 to up 20$/bbl, minus your Jones Act tanker cost to Cali, you still do +12$/Barrel easy.
http://jacquessimon506.wordpress.com/2013/10/03/remember-2007s-golden-age-of-refining-watch-the-golden-age-of-fuel-oil-and-the-golden-age-of-blending/