Western Canadian Select

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Western Canadian Select is one of North America’s largest heavy crude oil streams.[1] It is a heavy blended crude oil composed mostly of bitumens blended with sweet synthetic and condensate diluents from 19 existing Canadian heavy conventional[Notes 1][2] and bitumen crude oils at the Husky terminal in Hardisty.[3][4][5][6] Western Canadian Select heavy crude oil is one of many petroleum products from Western Canadian Sedimentary Basin oil sands. "The extremely viscous oil contained in oil sands deposits is commonly referred to as bitumen. Western Canadian Select is the benchmark for emerging heavy, high TAN (acidic) crudes[5] Western Canadian Select was launched in December 2004 as a new heavy oil stream by Cenovus, Canadian Natural Resources Limited, Suncor and Talisman Energy Inc.[3][5] Only these produce WCS and they are committed to keeping the quality of WCS "tightly controlled" making it a benchmark for emerging heavy, high TAN (acidic) crudes[5] Western Canadian Select was produced and traded out of Western Canada,[3]Hardisty, Alberta (CAPP 2012),[4] but in June 2012 Platts launched a new daily price assessment, pricing Platts Ex-Cushing Western Canadian Select (WCS), assessed at $70.78 per barrel at Cushing, Oklahoma, a major storage area and delivery point for key crude oil futures contracts.[1] According to the Government of Alberta's June 2014 Energy Prices report the price of WCS rose 15% from $68.87 in April 2013 to $79.56 in April 2014 but experienced a low of $58 and a high of $91.[7]. During the same time period the price of the benchmark West Texas Intermediate (WTI) rose 10.9% averaging $102.07 a barrel in April 2014.[7][7]. Western Canadian Select, a bitumen-derived crude is a heavy crude that is similar to California, Mexico Maya or Venezuela heavy crude oils.[8]

Bitumen comprises all of Canada’s unconventional oil, and is either converted into heavy oil or upgraded to synthetic light crude.[9]

Western Canadian Select: unconventional or conventional[edit]

According to the International Energy Agency (IEA), "Unconventional oil consists of a wider variety of liquid sources including oil sands, extra heavy oil, gas to liquids and other liquids." However, more recently, the IEA argued that categories of "unconventional" and "conventional" oil, may change over time "as economic and technological conditions evolve" and "resources hitherto considered unconventional can migrate into the conventional category."[10] In an editorial in the Calgary Herald published 28 December 2013, oil and energy professional, Norm Kalmanovitch, a long-time member of the "Friends of Science" advocacy group, characterized Western Canadian Select as a conventional crude oil.[11]

Crude oil like Western Canada Select (American Petroleum Institute gravity 20.5) has a very high flash point and would never have ignited had the derailed train (in Lac Megantic) been carrying this type of conventional crude.


At the Husky Hardisty terminal, Western Canadian Select is blended from sweet synthetic and condensate diluents from 19 existing Canadian heavy conventional and bitumen crude oils.[3][5]

Western Canadian Select is a heavy crude oil with an API gravity level of between 19 to 22 (API),[1][12] 20.5° (Natural Gas and Petroleum Products 2009).[13]

Western Canadian Select's characteristics are described as follows: Gravity, Density (kg/m3) 930.1,[3] MCR (Wt%) 9.6,[3] Sulphur (Wt%) 2.8-3.5%,[12] TAN (Total Acid number) of (Mg KOH/g) 0.93.[3]

WCS has an API gravity of 19-22.[12]

"Oil sands crude oil does not flow naturally in pipelines because it is too dense. A diluent is normally blended with the oil sands bitumen to allow it to flow in pipelines. For the purpose of meeting pipeline viscosity and density specifications, oil sands bitumen is blended with either synthetic crude oil (synbit) and/or condensate (dilbit)."[13]

In a study commissioned by the U.S. Department of State (DOS), regarding the Environmental Impact Statement (EIS) for the Keystone XL pipeline project, the DOS assumes "that the average crude oil flowing through the pipeline would consist of about 50% Western Canadian Select (dilbit) and 50% Suncor Synthetic A (SCO)."[14]


By 2010 Western Canadian Select achieved threshold volumes of approximately 250,000 barrels per day.[3]

Price of Crude Oil[edit]

Main article: Price of petroleum

The price of petroleum as quoted in news in North America generally refers to the WTI Cushing Crude Oil Spot Price per barrel (159 liters) of either WTI/light crude as traded on the New York Mercantile Exchange (NYMEX) for delivery at Cushing, Oklahoma, or of Brent as traded on the Intercontinental Exchange (ICE, into which the International Petroleum Exchange has been incorporated) for delivery at Sullom Voe. West Texas Intermediate (WTI), also known as Texas Light Sweet, is a type of crude oil used as a benchmark in oil pricing and the underlying commodity of New York Mercantile Exchange's oil futures contracts. WTI is a light crude oil, lighter than Brent Crude oil. It contains about 0.24% sulfur, rating it a sweet crude, sweeter than Brent. Its properties and production site make it ideal for being refined in the United States, mostly in the Midwest and Gulf Coast (USGC) regions. WTI has an API gravity of around 39.6 (specific gravity approx. 0.827). Cushing, Oklahoma, a major oil supply hub connecting oil suppliers to the Gulf Coast, has become the most significant trading hub for crude oil in North America.

The price of Western Canadian Select (WCS) crude oil (petroleum) per barrel[15] suffers a differential[16] against West Texas Intermediate (WTI)[17] as traded on the New York Mercantile Exchange (NYMEX) as published by Bloomberg Media, which itself has a discount versus London-traded Brent oil.[16] This is based on data on prices and differentials from Canadian Natural Resources Limited (TSX:CNQ)(NYSE:CNQ).

"West Texas Intermediate Crude oil (WTI) is a benchmark crude oil for the North American market, and Edmonton Par and Western Canadian Select (WCS) are benchmarks crude oils for the Canadian market. Both Edmonton Par and WTI are high-quality low sulphur crude oils with API gravity levels of around 40°. In contrast, WCS is a heavy crude oil with an API gravity level of 20.5°."[13]

West Texas Intermediate WTI is a sweet, light crude oil, with an API gravity of around 39.6 and specific gravity of about 0.827, which is lighter than Brent crude. It contains about 0.24% sulfur thus is rated as a sweet crude oil (having less than 0.5% sulfur), sweeter than Brent which has 0.37% sulfur. WTI is refined mostly in the Midwest and Gulf Coast regions in the U.S., since it is high quality fuel and is produced within the country (from Wikipedia article on West Texas Intermediate).

"WCS prices at a discount to WTI because it is a lower quality crude (3.51Wt. percent sulfur and 20.5 API gravity).[18]

Crude oil differentials and Western Canadian Select (WCS)[edit]

In a 2013 white paper for the Bank of Canada,[19] authors Alquist and Guénette examined implications for high global oil prices for the North American market. They argued that North America was experiencing a crude oil inventory surplus. This surplus combined with the "segmentation of the North American crude oil market from the global market", contributed to "the divergence between continental benchmark crudes such as WTI and Western Canada Select (WCS) and seaborne benchmark crudes such as Brent (Figure 3).11 I."[20]

Alberta's Minister of Finance argues that WCS "should be trading on par with Mayan crude at about $94 a barrel."[21] Maya crudes are close to WCS quality levels.[18] However, Maya was trading at $US 108.73 a barrel in February 2013 while WCS was $US 69. In his presentation to the U.S. Energy Information Administration (EIA) in 2013 John Foran demonstrated that Maya had traded at only a slight premium to WCS in 2010. Since then WCS price differentials widened "with rising oil sands and tight oil production and insufficient pipeline capacity to access global markets."[8] Mexico enjoys a location discount with its proximity to the heavy oil-capable refineries in the Gulf Coast. As well, Mexico began to strategically and successfully seek out joint venture refinery partnerships in the 1990s to create a market for its heavy crude oil in the U.S. Gulf. In 1993, for example, (Petróleos Mexicanos, the state-owned Mexican oil company) and Shell Oil Company agreed on a joint $US 1 billion refinery upgrading construction project which led to the construction of a new coker, hydrotreating unit, sulfur recovery unit and other facilities in Deer Park, Texas on the Houston Ship Channel in order to process large volumes of PEMEX heavy Maya crude while fulfilling the U.S. Clean Air Act requirements.[22]

Year 2007 2008 2009 2010 2011 2012 Feb 2013 24 April 2013 August 2013 December 2013 January 2014
2007 2008 2009 2010 2011 2012 Feb 2013 24 April 2013 August 2013 December 2013 January 2014 April 2014
Price Brent C $US/bbl[Notes 2] 73 98 62 80 112 112 118 103.41 110
Price WTI C $US/bbl 72 100 (peak 147)[23] 62 80 95 95 95 93.29[24] 97.90 102.07 [7]
Price WCS C $US/bbl 80 52 65 78 72 69 77.62[24] 82.36 67[25] $79.56 [7]
Price Syncrude Sweet C $US/bbl 62 102 62 78 104 93 97 98.51
Edmonton Par C $US/bbl 72 96 58 75 96 86 87 89.53
Maya C $US/bbl 101 87 [25]

(Prices except Maya for years 2007-February 2013)[9](Prices for Maya)[21] (Prices for 24 April 2013).[26]

By July 2013, Western Canadian Select (WCS) "heavy oil prices climbed from US$75 to more than US$90 per barrel — the highest level since mid-2008, when WTI oil prices were at a record (US$147.90) — just prior to the 2008-09 'Great Recession'."[27] WCS "heavy oil prices were "expected to remain at the US$90, which is closer to the world price for heavy crude and WCS 'true, inherent value'."[27] The higher price of WCS oil off WTI was explained by "new rail shipments alleviating some export pipeline constraints — and the return of WTI oil prices to international levels."[27]

By January 2014 there was a proliferation of trains and pipelines carrying WCS along with an increased demand on the part of U.S. refineries. By early 2014 there were approximately 150,000 barrels a day of heavy oil being transported by rail.[28]

Getting to tidewater: landlocked Canadian oil sands petroleum products suffer huge losses on price differentials[edit]

Until Canadian crude oil, Western Canadian Select, accesses international prices like LLS or Maya crude oil by "getting to tidewater (marketing)" (south to the US Gulf ports via Keystone XL for example, west to the BC Pacific coast via the proposed Enbridge Northern Gateway Pipelines to ports at Kitimat, BC or north via the northern hamlet of Tuktoyaktuk, near the Beaufort Sea,[29] or east to the Atlantic Ocean, the Alberta government (and to some extent, the Canadian government) is losing from $4 – 30 billion in tax and royalty revenues as the primary product of the oil sands, Western Canadian Select (WCS), the bitumen crude oil basket, is discounted so heavily against West Texas Intermediate (WTI) while Maya crude oil, a similar product close to tidewater, is reaching peak prices.[30] Calgary-based Canada West Foundation warned in April 2013, that Alberta is "running up against a [pipeline capacity] wall around 2016, when we will have barrels of oil we can’t move."[29]

Frustrated by delays in getting approval for Keystone XL (via the US Gulf of Mexico), the Northern Gateway Project (via Kitimat, BC) and the expansion of the existing TransMountain line to Vancouver, British Columbia, Alberta has intensified exploration of two northern projects "to help the province get its oil to tidewater, making it available for export to overseas markets."[29] Canadian Prime Minister Stephen Harper, spent $9 million by May, 2012 and $16.5 million by May, 2013 to promote Keystone XL.[31]

In the United States, Democrats are concerned that Keystone XL would simply facilitate getting Alberta oil sands products to tidewater for export to China and other countries via the American Gulf Coast of Mexico.[31]

On 1 August 2013, TransCanada CEO Russ Girling announced that the company was moving forward on the $12 billion 4,400-kilometre (2,700 mile) Energy East pipeline pipeline project with a proposed completion date in 2017 or 2018.[32] In the long term this would mean that WCS could be shipped to Atlantic tidewater via deep water ports such as Quebec City[33] and Saint John. Potential heavy oil overseas destinations include India,[33] where super refineries capable of processing vast quantities of oil sands oil are already under construction. In the meantime, Energy East pipeline would be used to send light sweet crude, such as Edmonton Par crude[33] from Alberta to eastern Canadian refineries Montreal/Quebec City, for example. Eastern Canadian refineries, such as Imperial Oil Ltd. 88,000-barrel-a-day refinery in Darmouth, N.S.,[33] currently import crude oil from North and West Africa and Latin America, according to Mark Routt, "a senior energy consultant at KBC in Houston, who has a number of clients interested in the project." The proposed Energy East Pipeline will have the potential of carrying 1.1-million barrels of oil per day from Alberta and Saskatchewan to eastern Canada.[34]

Patricia Mohr, a Bank of Nova Scotia senior economist and commodities analyst, in her report[27] on the economic advantages to Energy East, argued that, Western Canada Select, the heavy oil marker in Alberta, "could have earned a much higher price in India than actually received" in the first half of 2013 based on the price of Saudi Arabian heavy crude delivered to India" if the pipeline had already been operational.[33]In her report, Bohr predicted that initially Quebec refineries, owned by Suncor Energy Inc. and Valero, for example could access comprise light oil or upgraded synthetic crude from Alberta’s oil sands via Energy East to displace "imports priced off more expensive Brent crude."[33] In the long term, super tankers using the proposed Irving/TransCanada deep-sea Saint John terminal could ship huge quantities of Alberta's blended bitumen, such as WCS to the super refineries in India. Mohr predicted in her report that the price of WCS would increase to US$90 per barrel in July, 2013 up from US$75.41 in June."[33]

Canada's largest refinery, capable of processing 300,000 barrels of oil per day, is owned and operated by Irving Oil, in the deep-water port of Saint John, New Brunswick, on the east coast. A proposed $300-million deep water marine terminal, to be constructed and operated jointly by TransCanada and Irving Oil Ltd., would be built near Irving Oil's import terminal with construction to begin in 2015.[35]

Maine-based Portland–Montreal Pipe Line Corporation, which consists of Portland Pipe Line Corporation (in the United States) and Montreal Pipe Line Limited (in Canada), is considering ways to carry Canadian oil sands crude to Atlantic tidewater at Portland's deep-water port.[36] The proposal would mean that crude oil from the oil sands would be piped via the Great Lakes, Ontario, Quebec and New England to Portland, Maine. The pipelines are owned by ExxonMobil and Suncor.

Bull or Bear Markets in Crude Oil in the US[edit]

Investors placed bullish bets in the six weeks from January through February 8, 2013, on oil futures based on the U.S. central bank's bond-buying program that "adds liquidity to the financial markets." The demand, and therefore the price, of commodities in general and oil in particular falls if and when such a program is scaled back. Even a rumor that a hedge fund is in trouble and was liquidating positions can cause the price of U.S. crude oil to fall. Signs of strong demand of crude oil from China and India with hopes of a tighter market can raise the price and even an oil rally. Investors also refer to the Energy Information Administration reports on U.S. inventories of commercial crude oil. The higher the inventory of crude oil, the lower the price. U.S. inventories of commercial crude oil hit their highest level in February 15, 2013 since July 2012."[37]

Western Canadian Select Derivatives Market[edit]

Most Western Canadian Select is piped to Illinois for refinement and then to Cushing, Oklahoma for sale. Western Canadian Select (WCS) futures contracts are available on the Chicago Mercantile Exchange (CME)while bilateral over-the-counter WCS swaps can be cleared on Chicago Mercantile Exchange (CME)'s ClearPort or by NGX.[5]


WCS is transported from Alberta to refineries with capacity to process heavy oil from the oil sands. The Petroleum Administration for Defense Districts (Padd II), in the US Midwest, have experience running the WCS blend.[5][18][38] Most of WCS goes to refineries in the Midwestern United States where refineries "are configured to process a large percentage of heavy, high-sulfur crude and to produce large quantities of transportation fuels, and low amounts of heavy fuel oil."[38] While the US refiners "invested in more complex refinery configurations with higher processing capability" that use "cheaper feedstocks" like WCS and Maya, Canada did not. While Canadian refining capacity has increased through scale and efficiency, there are only 19 refineries in Canada compared to 148 in the United States.[38]

WCS crude oil with its "very low API (American Petroleum Institute) gravity and high sulphur content and levels of residual metals"[18][38] requires specialized refining that few Canadian refineries have. It can only be processed in refiners modified with new metallurgy capable of running high-acid (TAN) crudes.

"The transportation costs associated with moving crude oil from the oil fields in Western Canada to the consuming regions in the east and the greater choice of crude qualities make it more economic for some refineries to use imported crude oil. Therefore, Canada’s oil economy is now a dual market. Refineries in Western Canada run domestically produced crude oil, refineries in Quebec and the eastern provinces run primarily imported crude oil, while refineries in Ontario run a mix of both imported and domestically produced crude oil. In more recent years, eastern refineries have begun running Canadian crude from east coast offshore production."[38]

If the Keystone pipeline were completed and WCS could reach Gulf Coast refineries and tidewater, it would "narrow the spread or discount faced by Canadian crude producers".[39][38] and WCS would "be priced at the equivalent discount of Maya".[40] Getting to tidewater is a term used by industry and government to refer to the need for the oil sands products to be transported to the north, south, east and west coasts raising the price of WCS per barrel in an international market.

US refineries import large quantities of crude oil from Canada, Mexico, Columbia and Venezuela, and they began in the 1990s to build coker and sulfur capacity enhancements to accommodate the growth of these medium and heavy sour crude oils while meeting environment requirements and consumer demand for transportation fuels. "While US refineries have made significant investments in complex refining hardware, which supports processing heavier, sourer crude into gasoline and distillates, similar investment outside the US has been pursued less aggressively.[39][38] Medium and heavy crude oil make up 50% of US crude oil inputs and the US continues to expand its capacity to process heavy crude.[39][38]

Large integrated oil companies that produce WCS in Canada have also started to invest in upgrading refineries in order to process WCS.[41][38]

British Petroleum refinery in Whiting, Indiana[42] is the sixth largest in the US and can refine more than 400,000 barrels of crude oil per day.[43] As of 2012, BP is making a multi-billion investment to modernise the refinery in order to allow it to process heavier crude oil.[44][45] This multi-billion dollar upgrade was completed in 2014 and was one of the factors contributing to the increase in price of WCS.[28]

The Toledo refinery in northwestern Ohio, in which BP has invested around $500 million on improvements since 2010, is a joint venture with Husky Energy, which operates the refinery, and processes approximately 160,000 barrels of crude oil per day.[46][47] Since the early 2000s, the company has been focusing its refining business on processing crude from oil sands and shales.[42][48]

Lloydminster heavy oil, a component in the Western Canadian Select (WCS) heavy oil blend, is processed at the Co-op Refinery Complex heavy oil upgrader which had a fire in the coker of the heavy oil upgrader section of the plant, on February 11, 2013. It was the third major incident in 16 months, at the Regina plant.[49] The price of Western Canadian Select weakened against U.S. benchmark West Texas Intermediate (WTI) oil.[49]

Blenders: ANS, WCS, Bakken Oil[edit]

In their 2013 article published in Oil & Gas Journal, Auers and Mayes suggest that the "recent pricing disconnects have created opportunities for astute crude oil blenders and refiners to create their own substitutes for waterborne grades (like Alaska North Slope (ANS)) at highly discounted prices. A "pseudo" Alaskan North Slope substitute, for example, could be created with a blend of 55% Bakken and 45% Western Canadian Select at a cost potentially far less than the ANS market price." They argue that there are financial opportunities for refineries capable of blending, delivering, and refining "stranded" cheaper crude blends, like Western Canadian Select(WCS). In contrast to the light, sweet oil produced "from emerging shale plays in North Dakota (Bakken) and Texas (Eagle Ford) as well as a resurgence of drilling in older, existing fields, such as the Permian basin", the oil sands of Alberta is "overwhelmingly heavy." [50]


Royalty rates in Alberta are based on the price of WCS discounted against WTI. "Based on the high correlation with WTI (0.95 or 95 percent of the difference is explained by substituting WTI for WCS on the world market after adjusting for quality differences."[51]

The Province of Alberta receives a portion of benefits from the development of energy resources in the form of royalties that fund in part programs like health, education and infrastructure.[52]

In 2006-7 the oil sands royalty revenue was $2.411 billion. In 2007/08 it rose to $2.913 billion and it continued to rise in 2008/09 to $2.973 billion. Following the revised Alberta Royalty Regime it fell in 2009/10 to $1.008 billion. .[53] In that year Alberta's total resource revenue "fell below $7 billion...when the world economy was in the grip of recession."[54]

In February 2012 the Province of Alberta "expected $13.4 billion in revenue from non-renewable resources in 2013-14.[54] By January 2013 the province was anticipating only $7.4 billion. "30 per cent of Alberta’s approximately $40-billion budget is funded through oil and gas revenues. Bitumen royalties represent about half of that total."[54] In 2009/10 royalties from the oil sands amounted to $1.008 billion (Budget 2009 cited in Energy Alberta 2009.[53]

In order to accelerate development of the oil sands, the federal and provincial governments more closely aligned taxation of the oil sands with other surface mining resulting in "charging one per cent of a project’s gross revenues until the project’s investment costs are paid in full at which point rates increased to 25 per cent of net revenue. These policy changes and higher oil prices after 2003 had the desired effect of accelerating the development of the oil sands industry.[52] "A revised Alberta Royalty Regime was implemented in January 1, 2009.[55] through which each oil sands project pays a gross revenue royalty rate of 1% (Oil and Gas Fiscal Regimes 2011:30).[56] Oil and Gas Fiscal Regimes 2011 summarizes the petroleum fiscal regimes for the western provinces and territories. When the price of oil per barrel is less than or equal to $55/bbl indexed against West Texas Intermediate (WTI) (Oil and Gas Fiscal Regimes 2011:30)(Indexed to the Canadian dollar price of West Texas Intermediate (WTI) (Oil and Gas Fiscal Regimes 2011:30) to a maximum of 9%). When the price of oil per barrel is less than or equal to $120/ bbl indexed against West Texas Intermediate (WTI) "payout."[57] (i.e. the first time when the developer has recovered all the allowed costs of the project, including a return allowance on those costs equal to the Government of Canada long-term bond rate ["LTBR"].[58]

In order to encourage growth and prosperity and due to the extremely high cost of exploration, research and development, oil sands and mining operations pay no corporate, federal, provincial taxes or government royalties other than personal income taxes as companies often remain in a loss position for tax and royalty purposes for many years. Defining a loss position becomes increasingly complex when vertically-integrated multi-national energy companies are involved. Suncor claims their realized losses were legitimate and that Canada Revenue Agency (CRA) is unfairly claiming "$1.2-billion" in taxes which is jeopardizing their operations.[59]

Oil Sands Royalty Rates[edit]

"Bitumen Valuation Methodology (BVM) is a method to determine for royalty purposes a value for bitumen produced in oil sands projects and either upgraded on-site or sold or transferred to affiliates. The BVM ensures that Alberta receives market value for its bitumen production, taken in cash or bitumen royalty-in-kind, through the royalty formula. Western Canadian Select (WCS), a grade or blend of Alberta bitumens, diluents (a product such as naphtha or condensate which is added to increase the ability of the oil to flow through a pipeline) and conventional heavy oils, developed by Alberta producers and stored and valued at Hardisty, AB was determined to be the best reference crude price in the development of a BVM."[60]

Price WTI C $/bbl Royalty Rate on Gross Revenue Royalty Rate on Net Revenue
Below C$55 1.00% 5.00%
C$60 1.62% 26.15%
C$75 3.46% 29.62%
C$100 6.54% 35.38%
Above C$125 9.00% 40.00%

Bitumen Bubble[edit]

In January 2013, the Premier of Alberta, Alison Redford, used the term bitumen bubble to explain the impact of a dramatic and unanticipated drop in the amount of taxes and revenue from the oil sands linked to the deep discount price of Western Canadian Select against WTI and Maya crude oil, would result in deep cuts in the 2013 provincial budget.[61] In 2012 oil prices rose and fell all year. Premier Redford described the "bitumen bubble" as the differential or "spread between the different prices and the lower price for Alberta's Western Canadian Select (WCS)." In 2013 alone, the "bitumen bubble" effect will result in about six billion dollars less in provincial revenue.[62]

See also[edit]


  1. ^ "Western Canadian Select (WCS) is a high-quality blend of 19 streams of Alberta heavy crude produced jointly by Cenovus, Talisman Energy Inc., Canadian Natural Resources Ltd. and Suncor. For WCS crude, the delivery point is at the Hardisty Terminal, managed by Husky Energy ." | CME Group 2012
  2. ^ According to the Wikipedia article Barrel (unit), One common term is barrels per day(BPD, BOPD, bbl/d, bpd, bd, or b/d) where 1 BPD is equivalent to 0.0292 gallons per minute. One BPD also becomes 49.8 tonnes per year. At an oil refinery, production is sometimes reported as barrels per calendar day (bc/d or bcd), which is total production in a year divided by the days in that year.


  1. ^ a b c Platts 2012.
  2. ^ CME Group 2012.
  3. ^ a b c d e f g h Cenovus 2010.
  4. ^ a b CAPP 2013.
  5. ^ a b c d e f g Argus 2012.
  6. ^ Suncor & 2013 1.
  7. ^ a b c d e Government of Alberta 2014.
  8. ^ a b Foran 2013.
  9. ^ a b TD 2013.
  10. ^ International Energy Agency (IEA) 2013.
  11. ^ Kalmanovitch 2013.
  12. ^ a b c Platts 2013.
  13. ^ a b c NRC 2013, p. 9.
  14. ^ Lattanzio 2013, p. 9.
  15. ^ Index Mundi nd.
  16. ^ a b Globe and Mail 2012.
  17. ^ Department of Energy 2012.
  18. ^ a b c d Moore 2011.
  19. ^ Alquist & Guénette 2013.
  20. ^ Alquist & Guénette 2013, p. 7.
  21. ^ a b Van Loon 2013.
  22. ^ PR 1993.
  23. ^ Scotiabank 2014.
  24. ^ a b PSAC 2013a.
  25. ^ a b Philips 2013.
  26. ^ PSCA 2013.
  27. ^ a b c d Mohr 2013.
  28. ^ a b Lewis 2014.
  29. ^ a b c Hussain 2013.
  30. ^ Vanderklippe 2013.
  31. ^ a b Goodman 2013.
  32. ^ Zawadzki & Sheppard 2013.
  33. ^ a b c d e f g Lewis 2013.
  34. ^ TransCanada 2013.
  35. ^ CBC 2013.
  36. ^ Sherwood 2013.
  37. ^ Krishnan & Brown 2013.
  38. ^ a b c d e f g h i Hackett 2013.
  39. ^ a b c Moore 2011, p. 3.
  40. ^ Moore 2011, p. 2.
  41. ^ Moore 2011, p. 34.
  42. ^ a b Dezember 2012.
  43. ^ Oil and Gas Online 2012.
  44. ^ Fox News 2012.
  45. ^ Tweh 2012.
  46. ^ Reuters UK 2012.
  47. ^ Toledo Blade 2010.
  48. ^ Aulds 2012.
  49. ^ a b Welsch & Harvey 2013.
  50. ^ Auers, John R.; Mayes, John (5 June 2013), "North American production boom pushes crude blending", Oil & Gas Journal (Dallas, Texas) 111 (5), retrieved December 28, 2013 
  51. ^ Moore 2011, p. 37.
  52. ^ a b Government of Alberta 2009, p. 1.
  53. ^ a b Government of Alberta 2009, p. 10.
  54. ^ a b c O'Donnell & Gerein 2013.
  55. ^ Government of Alberta 2009, p. 7.
  56. ^ Alberta Department of Energy 2011.
  57. ^ Alberta Department of Energy 2011, p. 30.
  58. ^ Alberta Department of Energy 2011, p. 11.
  59. ^ Vanderklippe 2013b.
  60. ^ Government of Alberta 2009.
  61. ^ Kleiss 2013.
  62. ^ Redford 2013.


External links[edit]