Oil Price Differentials Explained: Why Alberta crude sells at a deep discount
- Although crude prices largely rise and fall together, there can be significant price differences between the different streams, depending on the type of crude (quality), supply and demand fundamentals (marketability) and costs to transport the crude to the final customer (logistics).
- Quality is by far least important variable, particularly with respect to API gravity. Sulphur content and acidity are more important drivers of the quality discount.
- About two-thirds of Canada's exports (3.5 million bbl/day) are shipped to the Midwest via Enbridge's Mainline. Having a single large buyer of Canadian crude, particularly heavy crude, reduces Alberta's ability to compete for higher prices.
- Since Midwest refineries are largely at capacity, incremental heavy oil from the oil sands must find another buyer, or face deeper discounts.
- The world's largest market for heavy, sour crude is the US Gulf Coast, which has very limited pipeline access from Western Canada. The region offers the best pricing for heavy crude, and also typically sets the price differentials.
- Since Canada's export pipelines are at capacity, the incremental barrel of oil needs to be shipped by rail, which has a higher transportation cost and drives up pricing discounts.
- The proposed Keystone XL pipeline to the Gulf Coast offers the best marketability, since the USGC is a very large market for heavy crude with a shortage of stable suppliers.
- However, transportation discounts would be minimized by expanding capacity to BC's West Coast, either to Vancouver via the Trans Mountain Expansion, or to Kitimat, using Northern Gateway. Both offer the shortest distances to tidewater, minimizing pipeline tolls. Once seaborne, crude can be inexpensively shipped to Asia or California, two very large buyers of heavy, sour crude.
There are almost 200 benchmark crude streams produced around the world. Each stream has a unique quality specification, particularly in reference to density and sulphur content. Benchmark prices always reflect a specific point of sale, and will therefore be priced differently at different locations.
The two most commonly quoted benchmarks are West Texas Intermediate (WTI), priced out of the Cushing storage hub in Oklahoma, and Brent, priced out of the UK North Sea. Brent represents the international benchmark price, used as a reference for about two-thirds of the world’s crude trade.
In Canada, the two most common benchmarks are Western Canadian Select (WCS) and Canadian Light Sweet (CLS), formerly known as Edmonton Par. WCS is a blend of diluted bitumen and conventional heavy oil priced out of Hardisty, Alberta. CLS is a basket of light sweet crude priced out of Edmonton, Alberta. WCS represents the benchmark for diluted bitumen produced out of the oil sands while CLS more closely resembles WTI specifications. Each trades in reference to the WTI benchmark price.
THREE DRIVERS OF PRICE DIFFERENCES
Although crude prices largely rise and fall together, there can be significant price differences between the different streams, depending on the type of crude, where it is produced and where the final customer is located.
In Canada, light and heavy benchmarks, priced out of Alberta, largely trade at a discount to WTI. However, some streams, such as condensate and synthetic crude produced through bitumen upgrading, can trade close to par or even at a small premium to the US benchmark.
There are three variables that drive price differences between the different benchmarks:
1. Quality, which is mostly defined by API density and sulphur content, but can also be affected by impurities, molecular structure and acidity of the crude oil.
2. Marketability, as governed by supply and demand fundamentals. Basically, how much of a specific crude is produced, how many customers are willing to process that crude, and where those customers are located.
3. Logistics, which refers to available infrastructure and transportation method used to get a specific crude from the producer to its final customer.
Density and sulphur content are the two most important indicators of quality or grade. Crudes are classified on a scale of extra-heavy to light, as defined by API gravity. There are several other variables that affect quality, such as sediment and salt content, acidity, chloride concentration and the fraction of high-carbon molecules contained in the crude. Each of these variables impact processability and what type of refinery can accept that type of feedstock.
Heavy crudes are generally processed by more complex refineries, capable of producing a profitable slate of final products. Complex refineries have a higher secondary conversion capacity, allowing for more of the low-value heavy molecules to be cracked into high-value final products. In fact, high conversion refineries rely on discounted heavy sour crude to improve profit margins.
Refineries typically blend a variety of input streams in order to achieve a desired grade of feedstock. Depending on the complexity of the refinery, each facility will have a different limit for the volume of heavy sour crude it can process.
Shown below are the most common crude streams processed in American refineries:
API GRAVITY AND SULPHUR CONTENT OF TYPICAL US REFINERY FEEDSTOCK|
However, the correlation between selling price and quality isn’t straightforward. A good example can be seen from the realization prices of various US domestic and imported crude streams.
2017 AVG CRUDE PURCHASE PRICES VS API DENSITY|
US DOMESTIC PRICES & LANDED COSTS FOR IMPORTED STREAMS
The price paid by the refinery is almost unrelated to API density or grade. For example, Light Louisiana Sweet sells at a premium to WTI, but Heavy Louisiana Sweet has an even higher selling price. In fact, many medium and heavy sour grades were also purchased at premium prices, due to high demand for heavy crude in the Gulf Coast and oversupply of light oil from the Permian Basin.
Another example is California heavy crude, which was sold near par with WTI, despite significant quality differences. California crude is produced adjacent to California refineries, which are designed to handle heavy/sour feedstock. Proximity to market is therefore a far more important driver of price than quality.
Marketability is the art of matching your product to your customer, or finding the right customer for your product.
Although marketability doesn't have a direct cost, transportation costs are driven by where the market is located. Producers must be price competitive with other available suppliers for the same market. A product with good marketability has a wide variety of customers. Refineries with few alternatives are preferable, since this reduces competition for that market.
WHY MARKETABILITY MATTERS SO MUCH
Refineries make money on the price difference between the slate of refined products and the input cost of the crude. Product slate is a function of the type of crude processed and refinery complexity, with respect to process equipment and capacity.
The market price of a particular crude stream is defined by the all-in price a refinery is willing to pay for that crude (including transport) in order to obtain a certain profit margin, regardless of quality.
High conversion refineries are considerably more complex and come at a much higher capital investment cost. These facilities have additional cracking, coking and hydrotreating capacity, allowing them to produce more value-added final products, such as low-sulphur diesel, gasoline, and jet fuel. Complex refineries can therefore afford to pay more for "lower-quality" crude and still produce a profitable slate of final products.
Since simple refineries have little flexibility in their product slate, processing heavy sour crude would produce too much low-value residue. These refineries typically see much lower profit margins when processing heavier feedstock, and would therefore only buy that crude if priced at a significant discount.
Canada’s crude supply is becoming increasingly heavy and sour. Volumes added in recent years are mostly in the form of diluted bitumen, and that trend is expected to continue in the coming decades. Since Canadian refineries are relatively simple and already at capacity, a majority of Alberta's heavy oil is exported to the US, which has a much greater capacity to handle heavy sour crude.
FINDING THE RIGHT BUYER FOR ALBERTA'S HEAVY CRUDE
The two largest refining centres in the US are the Midwest region (PADD 2) and the Gulf Coast (PADD 3). Both operate complex high-conversion facilities, designed for a wide variety of feedstocks, including heavy sour crude. The Gulf Coast is the largest market and was traditionally well served by nearby high-producing regions such as Texas, Mexico, Venezuela and offshore Gulf of Mexico. Although the Keystone pipeline delivers Alberta crude to the Gulf Coast, the need for additional volumes of Canadian crude in PADD 3 was historically minimal at best.
MAJOR REFINING HUBS IN NORTH AMERICA|
1,000 BBL/DAY 2017 AVERAGE OPERATING CAPACITY
The Midwest was, for the longest of time, Canada’s ideal customer. The region is significantly closer, and had no major producers or import terminals nearby. Refineries in the Midwest invested billions retooling their facilities to process heavy, sour and acidic crude from the oil sands. Canada’s largest crude pipeline operator, Enbridge, built out most of its infrastructure to serve the area through its extensive Mainline network.
However, the dynamics of the US refining sector began to change about 10 years ago. As imports of Canadian crude into the Midwest continued to increase, the region no longer needed to import volumes from the Gulf Coast, and instead began blending heavy Canadian crude with light Bakken oil, produced in North Dakota and transported east by rail. Canada now accounts for 99% of all foreign oil imports into the Midwest. More than 60% of Midwest total feedstock is now Canadian crude, leaving little room for future growth.
Unfortunately, over-reliance on one buyer isn't good for Alberta’s producers. As the Midwest (PADD 2) is nearing its maximum capacity for heavy crude, incremental output from the oil sands desperately needs to find alternative buyers.
THE WORLD'S LARGEST MARKET FOR HEAVY SOUR CRUDE
The US Gulf Coast (USGC) is one of the world's largest refining hubs, containing some of the world's most complex high-conversion refineries. That makes the region the most important buyer of heavy sour crude produced globally. The USGC (PADD 3) often sets the price for most North American benchmarks and typically offers the best pricing for heavy, sour crude.
The region historically relied on heavy oil imports from Venezuela, Mexico and Columbia. As output from Venezuela and Mexico began falling dramatically in recent years, the USGC has been scrambling to bring in more heavy oil from Canada. PADD 3 is served by the 580,000 bbl/day Keystone pipeline, volumes shipped in from Alberta by rail and several US pipelines funnelling Canadian crude from the Midwest, through the Cushing storage hub in Oklahoma.
GIVING THE CUSTOMERS WHAT THEY WANT
Almost all of Canada’s crude exports are destined for US refineries. This makes sense since the US is one of the world’s largest importers and refiners of crude oil. Canada’s export pipelines have been designed to accommodate the needs of the customer, which wasn’t a problem until very recently.
The US shale revolution of the past decade has dramatically shifted the prospects for Alberta’s crude producers. US refineries have invested heavily in the addition of secondary conversion capacity, improving profitability when taking in heavy, sour feedstock. At the same time, US crude production has become increasingly light, creating a significant mismatch between the US refinery feedstock grade and domestic crude production.
The Gulf Coast region is bearing the brunt of this mismatch. The area is being swamped with light oil out of the Permian and faces dwindling supplies of heavy oil from its two largest sources, Mexico and Venezuela. The region is attempting to correct this imbalance by exporting domestically produced light crude, adding petrochemical conversion capacity, and finding alternative sources of heavy crude.
Enter Canada, the world’s largest producer of heavy crude.
Unfortunately, although Canadian heavy oil has excellent marketability in the Gulf Coast, the pipeline network to the USGC is limited at best, and unlikely to get better in the near term. That forces barrels onto rail cars and drives up the price discounts in Alberta.
There are four primary modes of transportation for crude oil - by pipeline, tanker, rail and by truck.
Pipelines are by far the most efficient mode of transportation by land. However, pipelines require significant capital investment and reach can be limited by geography. Due to regulatory hurdles surrounding new pipeline construction, build-out of infrastructure can take several years to achieve. Tolls are federally regulated by the National Energy Board (NEB) in Canada and the Federal Energy Regulatory Commission (FERC) in the US.
Tankers are the most common mode of transport for global oil trade and the least expensive by far. However, transport by ship is also the slowest. Over 60 million barrels of crude is shipped worldwide daily, mostly outside of North America. The most common crude carriers are VLCC (2 million barrel capacity), Suezmax (1 million barrels) and Aframax (750,000 barrels) tankers. Tanker day rates are a function of capacity and distance travelled.
Rail transportation is by far the most expensive and least efficient method of shipping crude. However, rail lines extend to almost every corner of North America and are not subject to the same regulatory hurdles as pipelines. Crude transportation by rail was virtually non-existent prior to 2012, but became a viable option as production volumes increased and pipelines became constrained. Rail loading terminals are also relatively cheap and easy to build. The average rail tanker holds about 700 barrels of crude.
Trucking crude oil is often a method of last resort for producers that need to ship their crude a relatively short distance. Truck transport has become quite common in Texas, where Permian production is trucked from West Texas to export terminals in the Gulf Coast. Producers in Alberta and Saskatchewan have also been increasing reliance on trucking to ship crude to refineries in Colorado or rail loading terminals in southern Saskatchewan. The average truckloads holds an estimated 250 barrels of crude.
GROWING PRODUCTION FROM LAND-LOCKED REGIONS
There are two regions in North America where production is rapidly rising - light oil from the Permian Basin, primarily located in West Texas, and heavy sour crude from the Alberta oil sands. Production from the Permian and the oil sands each topped 3 million bbl/day in 2018, and is expected to keep growing. US shale supply is expected to double by 2030, sending another 4 million bbl/day of light oil flooding into North American markets, while heavy oil from the oil sands is expected to increase by 1.5 million bbl/day by 2035. Combined, the two regions will soon account for about half of total output from the continent.
As domestic production grows, less oil is imported into Canada and the US. More importantly, more oil needs to be transported by land, mostly by pipeline, but also by rail. Infrastructure has not kept pace, particularly from Alberta going south, but also from West Texas into the Gulf Coast export terminals. This all adds up to wider pricing differentials.
GETTING TO THE GULF COAST VIA THE MIDWEST - SANS KEYSTONE XL
While pipeline construction in Canada has been subdued in the past decade, construction south of the border has in part attempted to keep up with growing output from Alberta. A number of new pipelines and reversal of existing lines has helped alleviate congestion in the Midwest area, where most Canadian crude is currently funneled. Many of these projects were focused on directing more Canadian crude to the US Gulf Coast, which suffers from a shortage of heavy crude.
|2006||Pegasus Pipeline Reversal||EXXON||Patoka, IL||Nederland, TX||90,000|
|2012||Seaway Reversal||Enterprise PP||Cushing, OK||Freeport, TX||400,000|
|2014||Seaway Twin Loop||Enterprise PP||Cushing, OK||Freeport, TX||450,000|
|2014||Flanagan South||TransCanada||Flanagan, IL||Cushing, OK||585,000|
|2014||Line 67 (Alberta Clipper)||Enbridge||Hardisty, AB||Superior, WI||450,000|
|2016||Southern Access Extension||Enbridge||Flanagan, IL||Patoka, IL||300,000|
|2018||Seaway Expansion||Enterprise PP||Cushing, OK||Freeport, TX||100,000|
CRUDE-BY-RAIL: GOING WHERE THE PIPELINES DON'T GO
While getting a new pipeline constructed can be a regulatory nightmare, moving crude by rail is comparatively simpler and less susceptible to public backlash. While rail transport is less efficient and more expensive per barrel, it has the distinct advantage of being able to access more markets, reaching almost any corner of North America. If using heated rail cars, heavy oil can be shipped without the use of diluent. Crude loading and offloading terminals are also much cheaper and faster to build than new pipelines.
Although quality, marketability and logistics all impact pricing differentials, the three variables are interdependent.
This effect can be seen in the pricing differentials between WTI and WCS, two very different grades of crude, priced in four different locations - Hardisty, Cushing, Houston and Midland, Texas, in the heart of the Permian Basin.
In the third quarter of 2018, the WTI benchmark, priced out of the Cushing storage hub in Oklahoma, averaged US$69.40 a barrel. At the same time, the WCS benchmark, priced out of the Hardisty storage hub in Alberta, was selling at just under US$42, a discount of US$28/bbl.
MEASURING THE TRUE COST OF QUALITY
The “quality gap” is best quantified by comparing WTI and WCS, two opposing grades of crude, at one particular location. And the best location to benchmark against is Houston, Texas.
Through the third quarter of this year, the discount for Canadian heavy, sour crude (WCS) in Houston averaged just US$5.40 a barrel. That discount was even narrower in Cushing, at just US$4.40. Assuming both Cushing and Houston have a diverse customer base and similar marketability, the true quality discount (light sweet versus heavy sour crude) was therefore about US$5 a barrel in Q3/2018.
|DISCOUNT @ HOUSTON (Q3/18)||$5.40|
|DISCOUNT @ CUSHING (Q3/18)||$4.40|
GETTING YOUR OIL TO MARKET: THE COST OF TRANSPORTATION
The spread between Hardisty, Cushing, Houston and Midland is also reflective of the cost of transportation. The cost of transporting crude from Cushing to Houston averaged US$2.60/bbl for WTI (light/sweet) and US$2.10 for WCS (heavy/sour) in the third quarter. The smaller discount for WCS is likely reflective of higher demand for heavy crude in the USGC.
Due to the rapid rise of Permian production and relatively slow pace of new pipeline construction, the incremental barrel of WTI shipped from Midland to Houston is being transported by truck, reflected in the US$17.60/bbl discount.
|CUSHING → HOUSTON (Q3/18)||$2.60|
|MIDLAND → HOUSTON (Q3/18)||$17.60|
|CUSHING → HOUSTON (Q3/18)||$2.10|
|HARDISTY → CUSHING (Q3/18)||$22.00|
THE TRANSPORTATION FACTOR IN WCS DISCOUNT
Since Canada’s export pipeline are oversubscribed, additional production out of Western Canada is most likely to be shipped by rail, or even by truck, if traveling a very short distance. The rail option to the Gulf Coast makes the most sense, since the USGC offers the best pricing for heavy sour crude. In Q3, the price difference for WCS in Hardisty versus Houston was about US$24.10/bbl, likely reflecting the current cost of rail transport between the two regions.
TRANPORTATION COSTS FOR ALBERTA CRUDE|
2018 DATA FROM EIA, CAPP, BARCLAYS, REUTERS AND CLARKSON RESEARCH
However, the volumes that can be shipped by rail are not infinite. There are still constraints in loading and offloading capacity, availability of tanker cars and congestion on the rail networks. Once all the pipelines are full and rail transport reaches its limit, producers can no longer get their crude to market, forcing barrels into storage tanks.
This effect was most evident in the fall of 2018, when growing production out of the oil sands collided with seasonal maintenance shutdowns in the Midwest. As pipelines and railcars to the Gulf Coast reached capacity, there was no way for producers to get their crude to their customer, stranding production in Alberta. The price of Canada’s light and heavy benchmarks plummeted back to the lows of early 2016.
CHASING THE ASIAN BUYER - THE CHEAPEST TRANSPORT OPTION
Tanker charter rates are a function of capacity and distance travelled. Day rates for VLCC tankers have fallen dramatically from as much as US$150,000 per day in 2007 to less than US$10,000 in 2012, below the cost of operation. Prices recovered in 2015 after China began leasing tankers to store crude offshore. An overbuild in new capacity caused prices to collapse once again in 2016, with rates falling to less than US$1/bbl in recent years.
|LOGISTICS DISCOUNT (Q3/18)||$2.50|
In Q3/2018, the discount between light oil in Houston (WTI) and light oil in the UK North Sea (Brent) was US$2.50/bbl, representing the shipping differential between the Gulf Coast and the UK. Although the USGC has better access to South America, the North Sea is closer to Europe and Asia, two very large importers of crude.
In terms of minimizing the transportation discount for Alberta crude, Enbridge’s Northern Gateway definitely wins the prize. Politics, aside, the pipeline has the distinct advantage of being routed through a less populated area than Trans Mountain, as well as being located 670 km closer to China, now the world’s largest importer of crude. Trans Mountain is a very close second, given that the pipeline is considerably shorter than Keystone XL or Energy East, providing quicker access to tidewater.
Once seaborne, Alberta crude can be cheaply transported to California, Asia or even the USGC via the Panama Canal, for only a few dollars per barrel.