Oil Price Differentials Explained: Why Alberta crude sells at a deep discount

Oil Price Differentials Explained: Why Alberta crude sells at a deep discount

SUMMARY:
  • 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.

PRICE DIFFERENTIALS FOR CDN LT/HEAVY CRUDE
% DISCOUNT TO WTI • DATA FROM CME GROUP

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.

VARIABLE 1 - QUALITY: STACKING UP THE COMPETITION

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.

 
API density scale - heavy, medium and light crude
SWEET < 0.7% SULPHUR  •  SOUR > 0.7% SULPHUR
 

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
DENSITY AND SULPHUR CONTENT OF TYPICAL CRUDE OIL IMPORTS STREAMS
DID YOU KNOW? Most global oil reservoirs are medium to heavy and sour (high in sulphur), whereas the most common benchmarks are light and sweet.

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
Purchase prices at US refineries based on API gravity

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.

VARIABLE 2 - MARKETABILITY: FINDING A CUSTOMER FOR YOUR CRUDE

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.


PRODUCT SLATE EXPLAINED
Definition: The relative quantities of petroleum products produced by a refinery, as governed by the type of crude feedstock and refinery complexity. Refinery products primarily consist of:
  • Light/Middle Distillates: Gasoline, naphtha, diesel, kerosene ($$$)
  • Heavy Products & Residue: Heavy fuel oil, bitumen, coke ($)

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.

CDN CRUDE EXPORTS TO USA BY TYPE
1,000 BBL/DAY • NEB DATA

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
Canada and US major refining hubs by 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.

US IMPORTS OF CDN CRUDE BY PADD
1,000 BBL/DAY • EIA DATA
  • PADD 2 (Midwest): Largest market for Canadian crude, accounting for more than half of refinery feedstock and 99% of foreign imports.
  • PADD 3 (Gulf Coast): Very large and underserved market. Limited pipeline access from Canada.
  • PADD 4 (Rocky Mountains): At capacity for Canadian crude.
  • PADD 5 (West Coast): Good demand for heavy sour crude, but very limited access from Canada.
  • 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.

    TOTAL US CRUDE IMPORTS
    1,000 bbl/day • H1/2018 data from EIA
  • East Coast (PADD 1): Limited pipeline access from Canada. Heavy reliance on more expensive seaborne feedstock.
  • Midwest (PADD 2): Access to Cdn crude via Enbridge's Mainline, blended with light Bakken crude from North Dakota.
  • Gulf Coast (PADD 3): Cdn crude delivered through TransCanada's Keystone pipeline and pipelines from the Midwest, via Cushing. Growing volumes being delivered by rail. Facing dwindling supply of heavy crude from Venezuela and Mexico.
  • Rocky Mtns (PADD 4): Cdn crude delivered via Enbridge's Express Pipeline, blended with light Bakken crude.
  • West Coast (PADD 5): Cdn crude delivered by Trans Mountain pipeline and some crude-by-rail.
  • 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.

    DID YOU KNOW? Although US imports of Canadian heavy crude have more than doubled in the past decade, heavy oil imports into the Midwest have held steady at about 1.8 million bbl/day since 2016. Much of the growth in Canadian heavy demand is being led by the Gulf Coast, rising from 100,000 bbl/day in 2014 to over 650,000 bbl/day by the middle of 2018.

    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.

    US IMPORTS BY COUNTRY
    1,000 BBL/DAY • DATA FROM EIA
  • Most US heavy oil imported from Venezuela and Mexico are processed in the USGC, representing 45% of heavy imports into the region. Most of Canada's heavy oil is processed in the US Midwest.
  • Canada, Mexico and Venezuela now make up 75% of all heavy sour imports into the USGC.
  • TransCanada's Keystone XL pipeline is designed to transport 830,000 bbl/day of crude from Alberta directly to the US Gulf Coast, should the line ever be completed.

    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.

     
    API density profile production imports and refinery feedstock
     
    DID YOU KNOW? Two-thirds of US crude imports are heavy, bordering on medium, in line with diluted bitumen produced out of the oil sands, which has an average API of about 21°.

    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.

    REFINING CAPACITY BY REGION
    1,000 BBL/DAY • DATA FROM EIA/NEB
    █ EAST COAST  █ MIDWEST  █ GULF COAST  █ ROCKY MNTS  █ WEST COAST  █ CANADA
    HEAVY OIL IMPORTS INTO USGC
    % OF TOTAL IMPORTS • JUN 2018 DATA FROM EIA
    █ VENEZUELA  █ MEXICO  █ CANADA  █ COLUMBIA  █ IRAQ  █ OTHER

    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.

     
    World's largest producer and consumer of heavy sour crude - Alberta and US Gulf Coast
     
    DID YOU KNOW? Poor marketability reduced demand for light sweet crude produced at Alberta's bitumen upgraders. Growing light oil supply from the Permian and dwindling heavy oil supply from Venezuela and Mexico has reduced demand for more synthetic light oil. As a result, light oil production out of the oil sands has been relatively stagnant at about 1 million bbl/day since 2013, as producers shift focus to growing heavy oil volumes.

    VARIABLE 3 - LOGISTICS: TRANSPORTING YOUR OIL TO MARKET

    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.

    According to Statistics Canada, a record 7,650 bbl/day of crude was transported by truck in August, mostly out of the province of Saskatchewan.

    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.

    OIL SANDS & PERMIAN PRODUCTION PROFILE
    1,000 BBL/DAY • DATA FROM STATSCAN & EIA
  • Production from the oil sands is expected to top 4 million bbl/day by 2030 and potentially hit 5.5 million bbl/day by 2038. Most of that increase will be heavy sour crude.
  • Production of light sweet crude from US shale basins, including the Permian, is expected to grow by another 4 million bbl/day over the next two decades.
  • 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.

    DID YOU KNOW?
    Due to the rapid rise of oil production out of the Permian Basin in West Texas and New Mexico, pipeline infrastructure running to refineries and export terminals in the Gulf Coast has become constrained, forcing many producers to truck their crude to markets. The 500 mile journey costs an average of US$15 per barrel, driving up transportation costs for Permian crude, lowering prices in Midland, Texas.
    NORTH AMERICAN CRUDE PRODUCTION & NET IMPORTS (EX-MEXICO)
    1000 BBL/DAY • DATA FROM STATSCAN & EIA
  • Crude oil production from both the US and Canada is projected to increase by another 9 million bbl/day over the next two decades.
  • Canada imports about 500,000 bbl/day, mostly into the East Coast. Despite rising production out of Western Canada, imports into Eastern Canada are unlikely to be reduced due to lack of infrastructure running from west to east.
  • Although the US is currently the world's largest crude importer (tied with China), net imports are expected to be reduced to zero by about 2020.
  • At the end of 2015, the US lifted its crude export ban, allowing exports to rise from almost zero to over 2.5 million bbl/day by the end of 2018. According to the EIA, net imports into the USA could be reduced to zero as early as 2020.

    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.

    YEAR PIPELINE OPERATOR SOURCE DESTINATION CAPACITY
    2006 Pegasus Pipeline Reversal EXXON Patoka, IL Nederland, TX 90,000
    2012 Seaway Reversal Enterprise PP Cushing, OK Freeport, TX 400,000
    2014 Marketlink TransCanada Cushing, OK Texas 700,000
    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
    DID YOU KNOW?
    Skyrocketing production of light oil from US shale basins has disrupted the normal flow of crude in the Lower 48. Traditionally, foreign crude was imported into the Gulf Coast and pipelined north to markets inland. As the US produces more crude domestically and moves to export more of its oil, flow has been reversed, moving crude from inland regions to export terminals in Texas and Louisiana.

    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.

    US CRUDE-BY-RAIL IMPORTS FROM CANADA BY PADD
    1,000 BBL/DAY • EIA DATA
  • Plenty of crude-by-rail loading capacity in Western Canada, but limited by availability of rail cars and congestion on rail tracks.
  • According to government estimates, Canadian crude exports to the US by rail are expected to jump to 300,000 bbl/day by the end of 2018 and 400,000 bbl/day by the end of 2019.
  • PULLING IT ALL TOGETHER: ADDING UP THE PRICE DISCOUNTS

    PRICE DIFFERENTIALS
    Q3/18 AVG USD/BBL • CME GROUP/ICE DATA

    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.

    WTI VS WCS PRICES IN HOUSTON
    USD/BBL • DATA FROM NYMEX/ARGUS

    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.

    QUALITY DISCOUNT AT HOUSTON, TX
    CRUDE LOCATION USD/BBL
    WTI HOUSTON $73.20
    WCS $67.80
    DISCOUNT @ HOUSTON (Q3/18) $5.40
    QUALITY DISCOUNT AT CUSHING, OK
    CRUDE LOCATION USD/BBL
    WTI CUSHING $69.40
    WCS $65.00
    DISCOUNT @ CUSHING (Q3/18) $4.40
    WHY HOUSTON PRICES MATTER A LOT ... ESPECIALLY FOR HEAVY SOUR CRUDE

    The cost of transportation to the US Gulf Coast (USGC) largely governs the price discount for a particular stream of crude at a particular location, especially heavy sour crude. Houston prices matter because:
    • The area has ample access to tidewater and about 70 million barrels of storage capacity, making it a major import/export and blending hub for a very wide variety of crude feedstocks.
    • There are 56 refineries operating in the USGC with a total refining capacity of almost 10 million bbl/day, representing half of total US capacity. That keeps crude demand very high and mitigates the impact of maintenance outages.
    • Local refineries have a very high conversion capacity, improving profit margins when processing heavier grades of crude.
    • Crude handling, production and refining is managed by a diverse group of companies, preventing control of markets and encouraging competition.
    • The USGC is the world's largest market for heavy/sour crude, and sets the market price for medium and heavy grades.
    • Texas is politically stable state, with an accomodative government that supports its energy sector. The region is relatively immune to frequent regulatory changes and interference from special interest groups.

    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.

    TRANSPORTATION DISCOUNTS
    CRUDE LOCATION USD/BBL
    WTI HOUSTON $71.80
    CUSHING $69.20
    MIDLAND $54.20
    CUSHING → HOUSTON (Q3/18) $2.60
    MIDLAND → HOUSTON (Q3/18) $17.60
    TRANSPORTATION DISCOUNTS
    CRUDE LOCATION USD/BBL
    WCS HOUSTON $66.90
    CUSHING $64.80
    HARDISTY $42.80
    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
    Transportation costs Alberta crude - rail, tanker and pipelines
    • Pipeline tolls are a function of API gravity, commitment volumes and contract duration.
    • Shipments by sea assumes daily charter rate of US$6,500/day per million barrels (VLCC), assuming the following transit times:
      • Vancouver to Asia: 35 to 45 days
      • East Coast to Asia (via Suez Canal): 35 to 40 days
      • US Gulf Coast to Asia (via Cape Agulhas): 45 to 55 days
    Tolls for heavy crude are higher than light oil, typically in the order of 20%, to account for the added pumping power and slower transit time. For example, pumping light oil from Edmonton to Chicago takes about 20 days, versus 30 days for heavy crude.

    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.

    WHY CANADA’S EAST COAST REFINERIES HAVE LITTLE APPETITE FOR ALBERTA CRUDE

    Although shipping Canadian crude to Canadian refineries on the East Coast sounds like a no-brainer, logistically, it can be very expensive and impractical. Refineries located on the Atlantic have access to seaborne crude, which is typically priced closer to Brent.

    When the differential between Brent and Alberta crude is very high, it makes sense to buy crude in Western Canada and ship to Eastern Canada by rail. But that discount needs to be very wide to make the economics work, given the 4,500 km distance between Edmonton and Irving Oil’s 300,000 bbl/day refinery in New Brunswick, Canada’s largest refinery and biggest importer of foreign crude. Since New Brunswick is 1,000 km further than the Gulf Coast, displacing 100% of Canadian foreign imports with Alberta crude is therefore unlikely to happen, even if Energy East eventually gets revived.

    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.

    CRUDE LOCATION USD/BBL
    WTI HOUSTON $71.80
    BRENT SCOTLAND $74.30
    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.

    Federal permits for Enbridge's Northern Gateway Pipeline were cancelled by the Federal Court of Appeal, in a ruling very similar to the recent cancellation of the Trans Mountain Expansion. The federal government's moratorium on crude tankers on BC's northern coast has left Northern Gateway on the backburner for now.
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    UPDATED:  DEC 13, 2018
    SOURCES:  • US PETROLEUM TRADE DATA PROVIDED BY THE EIA
    • CDN PETROLEUM TRADE DATA PROVIDED BY STATISTICS CANADA AND THE NEB
    • OIL PRICES AND DISCOUNTS COURTESY CME GROUP AND ARGUS
    • PIPELINE TOLLS PROVIDED BY CAPP
    • SHIPPING RATES PROVIDED BY EURONAV
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