California is a better market for Trans Mountain-transported crude than Asia

  • TMX’s terminal port cannot receive super tankers, reducing competitiveness in Asia
  • California’s heavy crude output is declining
  • Albertan crudes will become increasingly competitive against Mexico’s Maya in PADD 5
  • Blending with Bakken crudes would let Albertan crudes replace declining Alaskan output
  • Californian fuel standards give oil sands operators that are lowering carbon intensity an edge
  • WCS in pole position to become new heavy sour benchmark in the U.S.

March 08, 2017

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California, not Asia, will be the most attractive market for Albertan heavy crude following Kinder Morgan’s Trans Mountain Pipeline expansion (TMX) from 300,000 b/d to 890,000 b/d. Lacking a deep water port, TMX’s Burnaby terminal on the British Columbian coast cannot handle carriers larger than an Afromax, making shipping costs less competitive than those of Middle Eastern sellers.

The decline of Californian and Alaskan crude is creating a more lucrative market nearer to home. Crude production in California has declined to just over 500,000 b/d from its 1985 peak of 1.1 million b/d, making its refiners increasingly dependent on imports, which now account for 52 percent of feedstock. The U.S. government forecasts a continued decline to about 300,000 b/d by 2040.

The Mexican Wave

Canada will have to compete against Mexico, which has started shipping Maya, a heavy crude benchmark, to California for the first time since 2008. Petroleos Mexicanos (Pemex) plans to ship an average of 30,000 b/d of Maya in 2017 from a recently remodeled Salina Cruz terminal on the Pacific coast. The shipments began in late November with a 23,000 barrel spot cargo to Royal Dutch Shell’s Martinez refinery near San Francisco, which for a subsequent December spot shipment paid US$1.45 per barrel more than Pemex’s European buyers would have.

But by 2020, when TMX is scheduled to be operating, Maya may be less competitive against Canadian heavy crudes. Three factors are reducing the amount of crude that Mexico sells to the U.S.: First, Mexico’s output has declined for more than a decade and the new foreign upstream investment is unlikely to reverse this for several years. Secondly, it is also refining more in the domestic market, which is expected to drop total crude exports in 2017 to an average of between 1 million and 1.1 million b/d, from just over 1.2 million b/d last year. Lastly, Mexico is also selling more to Europe and Asia – in the first 11 months of 2016, it exported 48 percent of its crude to the U.S., down from 69 percent in 2014. This trend will accelerate if the U.S. government imposes a border tax on Mexican oil, which would make it 20 percent more expensive. Canada is less likely to face the tax. Western Canadian Select (3.5pc sulfur and 20 API) already sells at a sustained deep discount of against Maya, despite the two grades being nearly identical in quality. A further Trump-induced differential would boost Canada’s market share in the U.S.

Furthermore, WCS may replace Maya in the U.S. as a heavy sour benchmark. Mexico’s government, not a market, sets Maya’s price, using a formula based on the price of West Texas Sour (WTS) crude at Midland, Texas and the illiquid 3 percent sulfur fuel oil market at the Gulf coast. The result is a benchmark that distorts price discovery.

In contrast to Maya’s declining output, the Canadian Association of Petroleum Producers forecasts Western Canadian heavy crude production to increase by 670,000 b/d to 3.21 million b/d between 2015 and 2020. Volumes of WCS – which is blended by CNRL, Cenovus, Suncor and Respsol – may also increase. The consistent quality of WCS, and the increasing ability to deliver it by pipeline and store it in the Houston area is creating an active pipeline spot market for heavy sour crude where the heavy/light spread can be seen with differences of timing and location removed. Argus’ new WCS at Houston price is in a pole position to become the benchmark for heavy sour crudes in the U.S. Its midpoint price on March 6 was US$ 47.64, at a premium to Maya’s US$ 46.32. Previously buyers had to use prices where WCS was often heavily discounted against Maya due to the transportation costs.

Alaska Output’s Deep Freeze

Alaskan crude output has dropped since its 2 million b/d peak in 1988, to below 560,000, b/d. The U.S. government projects a continued decline to the point where the Trans Alaska Pipeline System (TAPS) may close by 2025 – under one oil price scenario – impacting North Slope output. TAPS pipes Alaskan North Slope (ANS) crude south to Valdez, the only port suitable for crude carriers that is ice-free year round, for transport to West Coast refineries. TAPS operator, Alyeska Pipeline Service Company, says the pipeline needs to maintain a minimum throughput of 300,000 b/d to 350,000 b/d to remain operational in winter. In January 2017, its throughput averaged 555,458 b/d. A flow-rate drop would potentially cause wax build up, water dropout from the crude, ice formation and displacement of the buried pipeline due to soil freezing and thawing, making it uneconomical to operate.

Although WCS is heavier and sourer than ANS, it can be blended 55 percent Bakken and 45 percent WCS to simulate it. The blend has the same gravity as ANS (API 32.1) and virtually identical distillation yields. The blend’s sulfur content of 1.4 percent and TAN at 0.6 would be higher than ANS 0.9 percent and 0.1 respectively, but would still be in the range of Californian refineries’ capacity. And there are plans to bring Bakken crudes by rail to the west coast. The biggest project is Tesero’s 360,000 b/d export terminal in the port of Vancouver, Washington, which needs regulatory approval.

Carbon Copy

The carbon regulations and pricing of California and Alberta create a synergy that works in Albertan oil sands operators’ favor when competing against jurisdictions that do not incent lowering emissions. Under the Low Carbon Fuel Standards (LCFS) regime, Californian refiners have to reduce their carbon intensity from well to pump. The California Air Resources Board assigns an intensity score to crudes, and those under the baseline receive a carbon credit to sell or use. Refiners using crudes over the baseline must purchase credits to offset the extra emissions. Replacing a carbon-intense crude such as California’s Placerita with one of Alberta’s oil sands crudes —all of which are less carbon intense — reduces this carbon credit penalty. Furthermore, Albertan producers are investing heavily in lowering their crudes’ carbon intensity, making them even more attractive to Californian refiners when compared to other foreign heavy crudes from Iraq, Saudi Arabia, Colombia and Ecuador, which are in jurisdictions whose regulations do not require this.


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