Western Canadian heavy crude producers are getting desperate to find markets for oil sands production expected to increase by 1 MMb/d over the next 3 years. Few Canadian refineries can process these heavy bitumen crudes and domestic Canadian conventional crude production exceeds local refining capacity. Of all the current market alternatives, the US Gulf Coast is the most logical. Transporting heavy crude to that market continues to be constrained by a lack of infrastructure. Oversupply into the Midwest market and continued uncertainty about infrastructure have created a volatile price environment. Today we begin a two-part analysis of the Gulf Coast market for heavy Canadian crude.
The number of refining markets with capacity to process increasing Canadian heavy crude production is strictly limited. Heavy crudes need to be processed by refineries equipped to handle the extremely heavy hydrocarbons they contain. Such refineries upgrade the high yields of residual fuel oil from heavy crude into lighter products by running them through coker units (see Complex Refining 101 – Part 2 Upgrading). Complex refineries like these are prohibitively expensive to build from scratch. It does not make sense to build them in Western Canada where there is no ready market for refined products. Canadian heavy crude production is therefore largely destined for export to markets that have heavy refining capacity. [Note that about 0.5 MMb/d of Canadian heavy oil sands crude is upgraded to synthetic light crude at the point of production. This crude can be refined more easily than heavy crudes and it is therefore an option for Canadian producers to upgrade more heavy crude. The recent shelving of the Suncor Voyageur upgrader project suggests that the economics of this approach are not currently viable.]
The closest export market to Western Canada is the US Midwest but that market is already saturated with heavy crude. Canadian National Energy Board (NEB) data shows that in the final quarter of 2012, more than 550 Mb/d of heavy bitumen crude was exported to the PADD 2 Midwest region of the US. That is more heavy crude than Midwest refineries can process at the moment. Inventories of crude at the Cushing, OK Midwest trading hub are at record levels right now and prices are being discounted. The Midwest over supply situation may ease up in the second half of 2013 when the massive 400 Mb/d BP Whiting refinery near Chicago comes back online with new heavy crude processing capability. However Canadian bitumen production continues to increase. As noted above, another 1 MMb/d is expected in the next three years. So regardless of the BP Whiting refinery boost, Canadian producers need to find other destination markets for their heavy crude outside the Midwest.
Last week in our ongoing series covering crude by rail we discussed the transport of Western Canadian heavy crude bitumen to the US Gulf Coast (see Crude Loves Rock’n’Rail – Heat It! Bitumen Economic Part 1). The Gulf Coast is the largest market in the world for heavy crude refining. In fact the Gulf Coast region has about 2.38 MMb/d of refining capacity configured to process heavy crude grades, primarily from Mexico and Venezuela (see Production Stampede – Where Will Canadian Oil Production Go?). The big challenge for Canadian producers right now is figuring out how to transport their heavy crude to US Gulf Coast refineries. NEB data shows that only 90 Mb/d of Canadian heavy crude made it to the Gulf Coast during the final quarter of 2012. New pipelines expected online that would deliver Canadian oil all the way to the Gulf Coast market have been delayed (e.g. Keystone XL) for political and environmental reasons. The expected relief afforded by completion of the second phase of the 400 Mb/d Seaway pipeline from Cushing to Houston in January of this year (2013) did not materialize because of congestion at the Houston end of that pipeline. This week the situation took a turn for the worse when the ExxonMobil Pegasus pipeline that previously delivered up to 96 Mb/d of Canadian crude from Patoka, IL to Nederland, TX was closed because of a leak in Arkansas.
Aside from the Gulf Coast about the only other choice for Canadian producers is to export their crude to Asia from the West Coast of Canada. That choice also requires pipeline infrastructure to be built – over mountainous terrain. Although plans are in place to expand existing and build new West Coast pipelines, they are the subject of significant opposition and will not be in service before 2017 at the earliest (see West Coast Pipe Dreams – Canadian Crude Oil Double Jeopardy). For the moment at least – the Gulf Coast is the only market choice. And unless you are lucky enough to find space on the Seaway pipeline, shipping heavy crude to the Gulf Coast is currently only possible by rail (now that the Pegasus pipeline is shut). As we learned last week – moving heavy crude by rail from Alberta to the Gulf Coast can cost upwards of $30/Bbl (see Crude Loves Rock’n’Rail – Heat It! Bitumen Economic Part 1).
Let’s not forget another factor that comes into play when transporting Canadian heavy crudes - the need to blend them with lighter diluent components to flow through pipelines (see Fifty Shades of Eh? Part 1 and Part 2). Bitumen crudes can be transported without diluent in rail cars but it requires special equipment to load and unload the railcars and specially equipped steam coil rail tank cars to heat the bitumen on arrival. Whether by pipeline or rail additional transportation costs for heavy crude have to be taken into account.
Even though transport costs to the Gulf Coast are higher, Canadian producers that find transportation routes are at least getting access to a market that has plenty of refining capacity to process their crudes. That means Gulf Coast refiners will pay higher prices than Canadian producers have been getting in the Midwest where the oversupply situation has led to big discounts for crude priced in that market against the benchmark West Texas Intermediate (WTI) crude versus the Gulf Coast. At the Gulf Coast, Canadian heavy crude would compete with similar grades such as Mexican Maya that are priced relative to international benchmarks and not subject to the big inland discounts that domestic US crudes such as WTI have suffered.
At the moment however, most Canadian producers have to settle for prices set in Alberta based on a substantial discount to WTI. Prices for pipeline specification diluent blended bitumen (dilbit) in Alberta are set against the benchmark Western Canadian Select (WCS) blend crude. Four production companies - Cenovus, Suncor, Canadian Natural Resources and Talisman, created WCS in an effort to produce a crude blend with consistent qualities that would be more attractive to refiners than an ever-changing recipe of bitumen crudes from different producers in the Canadian heavy oil sands. [Maintaining consistent crude blending quality is a common challenge for producers and refiners – we covered similar issues with the North Sea Brent market recently – see Crazy Little Crude Called Brent – The Art of Quality Maintenance]. WCS is made with up to 19 different Canadian heavy conventional and bitumen crude oils blended together with sweet synthetic and condensate diluents.
The trading market for WCS at Hardisty is based on differentials to the US Midwest benchmark WTI. WCS is a heavier crude (typically 20 degrees API) having higher sulfur content (3.5%) than WTI (38 API, 0.5% sulfur). Based on quality alone, WCS would be expected to trade at a discount to WTI because the latter is a lighter crude that produces higher yields of valuable refined products such as gasoline and diesel. WCS at Hardisty would also expect to be discounted against WTI by the cost of pipeline transportation to Cushing, OK – about $10/Bbl.
The chart below shows the WCS price discount to WTI since the start of 2012. That discount has greatly exceeded the “normal” quality and transportation discount that we might expect between these crudes because of the oversupplied Midwest market. The WCS discount to WTI Cushing over the 15 month period averaged $24/Bbl reaching a low point of $38/Bbl in January 2013 and a high point close to $9/Bbl in September 2012. The average $24/Bbl discount to WTI works out to an average realized WCS price of $70/Bbl at Hardisty. When you subtract the $10/Bbl pipeline cost to ship WCS to Cushing – Canadian producers are only realizing $60/Bbl on average. At that price level existing Canadian crude producers will likely continue to produce bitumen but the economics for new production projects begin to look marginal.
Source: CME data from Morningstar
Comparing the discounted price for WCS in Hardisty with the price of Mexican Maya crude gives us an idea of how much more WCS would be worth if Canadian producers could deliver to the Gulf Coast market. Maya is similar in density and sulfur content to WCS. Maya has 21.8 degrees API density (WCS is 20) and 3.4 percent sulfur (WCS is 3.5). The two crudes do have other characteristics that differ – mainly because WCS is a dilbit blend of heavy crude with lighter diluent. Refiners often call Dilbit crudes “dumbbell” crudes because they have less of the valuable middle distillate fractions (see Turner Mason and the Goblet of Light and Heavy for more on this topic). Maya will attract a quality premium over WCS at the gate of a Gulf Coast heavy crude refinery because WCS is a dumbbell crude but the two should not be priced far apart ($2/Bbl would be a conservative estimate) based on quality.
Because of the Midwest crude logjam that we mentioned earlier, Gulf Coast crude prices have traded consistently higher than WTI at Cushing over the past two years. That means crudes like Maya have traded at a premium to WTI and since as we have seen, WCS has been priced at a discount to WTI that averaged $24/Bbl over the past 15 months, Maya prices have been significantly higher than WCS. The chart below shows the premium of Gulf Coast Maya to Hardisty WCS since the start of 2012. Over this period the Maya premium to WTS averaged about $30/Bbl. The highest premium was close to $42/Bbl in February 2012 and the lowest just below $15/Bbl in September 2012. If we assume that WCS might price at a quality discount to Maya of $2/Bbl – then Canadian producers could sell their barrels for as much as $28/Bbl more on average at the Gulf Coast than they get in Alberta. Of course that does not include transportation costs and as we have seen those could be as much as $30/Bbl by rail (although producers can save on diluent costs by using rail). The pipeline cost from Hardisty to the US Gulf Coast (assuming that you have access to pipeline capacity) would be closer to $14/Bbl (US State Department estimate for Keystone XL analysis).
Source: CME data from Morningstar
The unnerving part about this price analysis for Canadian producers is that over the past 15 months the price relationships that we have looked at between WTI, WTS and Maya have been extremely volatile. Price swings of $20/Bbl in either direction during relatively short time periods have been common. This volatility is very unattractive to producers facing high transportation costs to market.(It goes a long way toward explaining why more heavy crude rail transport capacity has not been developed from Western Canada to the Gulf Coast yet). Canadian heavy crude producers do not have the luxury of multiple market destinations that (for example) Bakken producers have been afforded by rail destinations on the East and West Coast in addition to the Gulf. Except for a few notable exceptions like the PBF Delaware City refinery, the Gulf Coast is the only destination market for Canadian heavy crude right now. Selling into a volatile market with high transport costs and no alternative destinations is not a pleasant occupation. Or one that makes much sense economically over the long term.
As a result the returns that Canadian heavy oil producers can expect to make today and over the coming years from exports to the US Gulf Coast region are heavily dependent on two factors. The first is the development of adequate pipeline capacity from the Midwest to the Gulf Coast that will give them a reasonably priced and secure route to market. The second dependency is on stable and sustained prices for heavy crudes in the Gulf Coast region that are high enough to cover their transport and production costs. Unfortunately right now, neither of these factors is guaranteed and the current price volatility could well continue to provide a rocky ride for Canadian production companies.
Looking at the current market options for Canadian producers and the delays in building out pipeline infrastructure to the Gulf Coast, you could be forgiven for not getting too excited about their future prospects. To understand whether and how infrastructure and prices might work out in favor of Canadian producers over the next two to three years we need to work through how the pricing relationships between WTI, WCS and Maya evolve at the Gulf Coast. Those relationships are going to change as the Midwest supply logjam at Cushing unwinds and more Canadian heavy crude reaches the Gulf Coast – assuming that pipeline capacity is built to transport it there. In the next episode in this series we will take a closer look at the future direction these prices could take.