Western Canadian Select (WCS) is a heavy sour blend of crude oil^[1] that is one of North America's largest heavy crude oil streams^[2] and, historically, its cheapest.^[3] It was established in December 2004 as a new heavy oil stream by EnCana (now Cenovus), Canadian Natural Resources, Petro-Canada (now Suncor) and Talisman Energy (now Repsol Oil & Gas Canada).^[4] It is composed mostly of bitumen blended with sweet synthetic and condensate diluents and 21^[5] existing streams of both conventional and unconventional^[5][6] Alberta heavy crude oils at the large Husky Midstream General Partnership terminal in Hardisty, Alberta.^[7] Western Canadian Select—the benchmark for heavy, acidic (TAN <1.1) crudes^[8][9]—is one of many petroleum products from the Western Canadian Sedimentary Basin oil sands. Calgary-based Husky Energy, now a subsidiary of Cenovus, had joined the initial four founders in 2015.^{[7][8][10][11][12][13]}

Western Canadian Select (WCS) is the benchmark price for western Canadian crude blends.^[14] The price of other Canadian crude blends produced locally are also based on the price of the benchmark.

During the COVID-19 pandemic many oil benchmarks around the world fell to record lows, with WCS dropping to $3.81 U.S. dollars per barrel on April 21, 2020.^[15][16] In June, Cenovus increased production at its Christina Lake oil sands project reaching record volumes of 405,658 bbls/d when the price of WCS increased "almost tenfold from April" to an average of $33.97 or C$46.03 per barrel (bbl).^[17] During the 2022 Russian invasion of Ukraine the price of WCS rose to over US$100 a barrel with the United States considering placing a ban on Russian oil imports.^[3]

Overview

Western Canadian Select is Canada's benchmark heavy crude and has historically been the cheapest crude oil heavy sour blend in North America.^[3][1] There are only four corporations that produce it—Cenovus Energy, Canadian Natural Resources, Suncor Energy, and Repsol.^[18] In total, Canada exported 3.2 million b/d of crude oil to the United States in May 2020.^[19]

WCS's influence over the crude oil market extends beyond the production of these four corporate giants, as the price of other Canadian crude blends produced locally are also based on the price of the benchmark, WCS, according to NE2, a brokerage and exchange company that handles approximately 38 percent of western Canadian oil production.^[18]

The calculation of the price of WCS is complex.^[18] Because WCS is a lower quality heavy crude oil and is also farther from the major oil markets in the United States, its price is calculated based on a discount to West Texas Intermediate (WTI)—a sweeter, lighter oil, which is produced in the heart of the oil markets regions. WTI is the benchmark price of oil in North America.^[18] The price of WTI changes from day to day but actual commodities trading market for crude oil is based on contract prices, not a daily price.^[18] The WCS discount on a futures contract for a two-month period is based on the average price of all WTI contracts in the most recent month prior to the WCS contract agreement.^[18]

Revenue

Husky Energy sold 65% of their Midstream business in 2016 and formed the Husky Midstream General Partnership (HMGP)^[20] with two additional partners. HMGP exclusively blends the crude super-stream to ensure a consistent high quality heavy crude product that is demanded by refineries. Since Husky joined the conglomerate, onstream WCS has been blended at the Husky Hardisty terminal (now owned by HMGP).^[8] In October 2020, Cenovus acquired the Calgary-based company established in the 1930s—Husky—for CA$3.8 billion.^[13]

Major producers

In 2004, Suncor Energy, Cenovus Energy, Canadian Natural Resources, and Talisman Energy (later Repsol) developed the Western Canadian Select (WCS) blend.^[4] According to Argus, in 2012 the WCS blend was still produced by only four companies because of the complex set of rules regarding compensate for contributions to the WCS blend.^[8] Cenovus and Husky completed a merger by January 2021, with the company operating under Cenovus. Through the merger Cenovus became the third-largest crude oil and natural gas company and the second-largest upgrader in Canada.^[21]

Major importers

The United States imports about 99% of Canada's oil exports,^[22] According to monthly data provided by the U.S. Energy Information Administration (EIA), Canada is the "largest exporter of total petroleum" to the United States with crude oil exports to the US of 3,026,000 bpd in September 2014, 3,789,000 bpd in September 2015 and 3,401,000 bpd in October 2015.^[23]

Canadian oil is much cheaper than oil from other sources. Since 2009, US refineries have increased use of Canadian crude oil, according to a March 20, 2020 report^[24] Since 2009, the US has decreased oil imports from Saudi Arabia, Mexico, and Venezuela.^[24] Of the total crude oil imports to the US, crude oil from Canada accounts for 56%, according to a 2019 EIA report.^[24]

Historical pricing

Crude prices are typically quoted at a particular location. Unless stated otherwise, the price of WCS is quoted at Hardisty and the price of West Texas Intermediate (WTI) is quoted at Cushing, Oklahoma.^[25]

Statista provides accurate current and historical records of the price of WCS.^[16]

By March 18, 2015, the price of benchmark crude oils, WTI had dropped to $US 43.34/barrel (bbl).^[25] from a high in June 2014 with WTI priced above US$107/bbl and Brent above US$115/bbl.^[26][27] WCS, a bitumen-derived crude, is a heavy crude that is similar to Californian heavy crudes, Mexico's Maya crude or Venezuelan heavy crude oils.^[28] On March 15, 2015, the differential between WTI and WCS was US$13.8. Western Canadian Select was among the cheapest crude oils in the world^[29] with a price of US$29.54/bbl on March 15, 2015,^[25][30] its lowest price since April 2009. By mid-April 2015 WCS had risen almost fifty percent to trade at $US44.94.^[31]

By June 2, 2015, the differential between WTI and WCS was US$7.8, the lowest it had ever been.^[32] By August 12, 2015, the WCS price dropped to $23.31 and the WTI/WCS differential had risen to $19.75,^[33] the lowest price in nine years when BP temporarily shut down its Whiting, Indiana refinery for two weeks,^[34] the sixth largest refinery in the United States,^[35] to repair the largest crude distillation unit at its Whiting, Indiana refinery.^[34] At the same time Enbridge was forced to shut down Line 55 Spearhead pipeline and Line 59 Flanagan South pipeline in Missouri because of a crude oil leak.^[35][36] By September 9, 2015, the price of WCS was US$32.52.^[37]

By December 14, 2015, with the price of WTI at $35 a barrel, WCS fell "75 percent to $21.82," the lowest in seven years and Mexico's Maya heavy crude was down "73 percent in 18 months to $27.74".^[22] By December 2015 the price of WCS was US$23.46, the lowest price since December 2008^[38] and The WTI-WCS differential was US$13.65.^[39] In mid-December 2015, when the price of both Brent and WTI was about $35 a barrel and WCS was $21.82. Mexico's comparable heavy sour crude, Maya dropped in price 73% but the Mexican government used an oil hedge to "somewhat protect" it.^[22]

By February 2016 WTI had dropped to US$29.85 and WCS was US$14.10 with a differential of $15.75.^[40] By June 2016 WTI was priced at US$46.09, Brent at MYMEX was US$47.39 and WCS was US$33.94 with a differential of US$12.15.^[41] By June 2016 the price of WCS was US$33.94.^[41] By December 10, 2016, WTI had risen to US$51.46 and WCS was US$36.11 with a differential of $15.35.^[42]

On June 28, 2018, WTI spiked to US$74, a four-year high,^[43] then dropped by 30% by the end of November.^[44]

In November 2018, the price of WCS hit its record low of less than US$14 a barrel.^[45] From 2008 through 2018, WCS sold at an average discount of US$17 against WTI. In the fall of 2018, the differential increased to a record of around US$50.^[45] On December 2, Premier Rachel Notley announced a mandatory cut of 8.7% in Alberta's oil production.^[46] This represents cutting back 325,000 bpd in January 2019, and dropping to 95,000 bpd by the end of 2019.^[47][46] According to a December 12, 2018 article in the Financial Post, after the mandatory cuts were announced, the price of WCS rose c. 70% to c. US$41 a barrel with the WTI narrowing to c. US$11. The price difference between WCS and WTI was as wide as US$50 a barrel in October.^[46][47] As the international price of oil recovered from the December "sharp downturn", the price of WCS rose to US$28.60.^[48] According to CBC News, the lower global price of oil was related to declining economic growth as the China–U.S. trade war continued.^[48] The price rose as oil production was cut back by the Organization of Petroleum Exporting Countries (OPEC) and Saudi Arabia.^[48] According to the U.S. Energy Information Administration (EIA) report, oil production rose by 12% in the U.S., primarily because of shale oil. As a result, Goldman Sachs lowered its 2019 oil price forecast for 2019.^[48]

In March 2019, the differential of WTI over WCS decreased to $US9.94 as the price of WTI dropped to US$58.15 a barrel, which is 7.5% lower than it was in March 2018, while the price of WCS averaged increased to US$48.21 a barrel which is 35.7% higher than in March 2018.^[49] By October 2019, WTI was averaging US$53.96 a barrel which is 23.7% lower than in October 2018. In comparison, for the same period, WCS averaged US$41.96 a barrel which is 2.0% higher than in October 2018 with a differential of US$12.00 in October 2019.^[50]

By March 30, 2020, the price of WCS bitumen-blend crude was US$3.82 per barrel.^[51] In April 2020 the price briefly fell below zero, along with WTI, due to collapsing demand caused by the COVID-19 pandemic.^[52] "• WCS oil price 2005-2021 | Statista". Retrieved May 18, 2022.

Curtailment

In the fall of 2018, the differential between WCS and WTI—which had averaged at US$17 for the decade from 2008 to 2018—widened to a record of around US$50.^[45] By December 2018 the price of WCS had plummeted to US$5.90.^[50] In response, the NDP government under Premier Notley, set temporary production limits of 3.56 million barrels per day (b/d) that came into effect on January 1, 2019. The curtailment was deemed necessary because of chronic pipeline bottlenecks out of Western Canada which cost the "industry and governments millions of dollars a day in lost revenue". Following the December 2 announcement of mandatory oil production cutbacks in Alberta, the price of WCS rose to US$26.65 a barrel.^[53][46][47] The global price of oil dropped dramatically in December before recovering in January. The price of WCS increased to US$28.60 with WTI at US$48.69.^[48] In the fall of 2019, the UCP government under Premier Kenney "extended the curtailment program into 2020 and increased the base exemptions for companies before the quotas kick in, lowering the number of producers affected by curtailment to 16".^[54]

Curtailment "supported domestic oil prices" but also "limited growth and overall industry investment as companies have been unable to expand production above their mandated quotas".^[54]

Integrated producers, such as Imperial Oil and Husky Energy, oppose curtailment because when the price of WCS is low, their refineries in the United States benefit. Other oil producers in Alberta support curtailment as a way of preventing the collapse of WCS.^[54]

In the summer of 2019, Suncor Energy, Cenovus Energy and Canadian Natural Resources agreed to increase production with the mandatory use of oil-by-rail as a condition for the increase.^[54] The Canadian Association of Petroleum Producers (CAPP)'s Terry Abel said that, "The whole point of curtailment was to try and match takeaway capacity with produced capacity so that we don’t create downward pressure on prices...To the extent you add incremental (rail) capacity, you should be able to make some adjustments to curtailment to accommodate that."^[54]

Characteristics

"The extremely viscous oil contained in oil sands deposits is commonly referred to as bitumen." (CAS 8052-42-4) At the Husky Hardisty terminal, Western Canadian Select is blended from sweet synthetic and condensate diluents from 25 existing Canadian heavy conventional and unconventional bitumen crude oils.^{[12][8][5][6][55]}

Western Canadian Select's characteristics are described as follows: API gravity level of between 19 and 22 (API),^[2][56] density (kg/m3) 930.1,^[12] MCR (Wt%) 9.6,^[12] sulphur (Wt%) 2.8-3.5%,^[56] TAN (Total Acid number) of (Mg KOH/g) 0.93.^[12]

Refiners in North America consider a crude with a TAN value greater than 1.1 as "high-TAN". A refinery must be retrofitted in order to handle high TAN crudes. Thus, a high TAN crude is limited in terms of the refineries in North America that are able to process it. For this reason, the TAN value of WCS is consistently maintained under 1.1 through blending with light, sweet crudes and condensate. Certain other bitumen blends, such as Access Western Blend and Seal Heavy Blend, have higher TAN values and are considered high TAN.^[57]

"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)."^[58]: 9 WCS may be referred to as a syndilbit, since it may contain both synbit and dilbit.^[59]

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)".^[60]

The Canadian Society of Unconventional Resources (CSUR) identifies four types of oil: conventional oil, tight oil, oil shale, and heavy oil^[61] like WCS.

Volumes

By September 2014 Canada was exporting 3,026,000 bpd to the United States. This increased to its peak of 3,789,000 bpd in September 2015 and 3,401,000 bpd in October 2015, which represents 99% of Canadian petroleum exports.^[23][22] Threshold volumes of WCS in 2010 were only approximately 250,000 b/d.^[12]

On May 1, 2016, a devastating wildfire ignited and swept through Fort McMurray, resulting in the largest wildfire evacuation in Albertan history.^[62][63] As the fires progressed north of Fort McMurray, "oil sands production companies operating near Fort McMurray either shut down completely or operated at reduced rates".^[64] By June 8, 2016, the U.S. Department of Energy estimated that "disruptions to oil production averaged about 0.8 million b/d in May, with a daily peak of more than 1.1 million b/d. Although projects are slowly restarting as fires subside, it may take weeks for production to return to previous levels."^[64] The Fort McMurray fires did not significantly affect the price of WCS.^[64]

"According to EIA's February Short-Term Energy Outlook, production of petroleum and other liquids in Canada, which totaled 4.5 million barrels per day (b/d) in 2015, is expected to average 4.6 million b/d in 2016 and 4.8 million b/d in 2017. This increase is driven by growth in oil sands production of about 300,000 b/d by the end of 2017, which is partially offset by a decline in conventional oil production."^[65] The EIA claims that while oil sands projects may be operating at a loss, these projects are able to "withstand volatility in crude oil prices".^[65] It would cost more to shut a project down—from $500 million to $1 billion than to operate at a loss.^[65]

Comparative cost of production

In their May 2019 comparison of the "cost of supply curve update" in which the Norway-based Rystad Energy—an "independent energy research and consultancy"—ranked the "world's total recoverable liquid resources by their breakeven price", Rystad reported that the average breakeven price for oil from the oil sands was US$83 in 2019, making it the most expensive to produce, compared to all other "significant oil producing regions" in the world.^{[66][Notes 1]} The International Energy Agency made similar comparisons.^[67]

In 2016, the Wall Street Journal reported that the United Kingdom at US$44.33, Brazil at US$34.99, Nigeria at US$28.99, Venezuela at US$27.62, and Canada at US$26.64 had the highest production costs.^[68] Saudi Arabia at US$8.98, Iran at US$9.08, Iraq at US$10.57, had the cheapest.^[68]

An earlier 2014 comparison, based on the Scotiabank Equity Research and Scotiabank Economics report that was published November 28, 2014,^[5] compared the cost of cumulative crude oil production.

This analysis "excludes" 'up-front' costs (initial land acquisition, seismic and infrastructure costs): treats 'up-front' costs as 'sunk'. Rough estimate of 'up-front' costs = US$5–10 per barrel, though wide regional differences exist. Includes royalties, which are more advantageous in Alberta and Saskatchewan." The Weighted average of US$60-61 includes existing Integrated Oil Sands at C$53 per barrel."^[5]

Lowering production costs

WCS is very expensive to produce.^[69] There are exceptions, such as Cenovus Energy's Christina Lake facility which produces some of the lowest-cost barrels in the industry.^[69]

In June 2012 Fairfield, Connecticut-based General Electric (GE), with its focus on international markets, opened its Global Innovation Centre in downtown Calgary with "130 privately employed scientists and engineers", the "first of its kind in North America", and the second in the world.^[69][70] GE's first Global Innovation centre is in Chengdu, China, which also opened in June 2012. GE's Innovation Centre is "attempting to embed innovation directly into the architecture".^[70] James Cleland, general manager of the Heavy Oil Centre for Excellence, which makes up one-third of the Global Innovation Centre, said, "Some of the toughest challenges we have today are around environmental issues and cost escalations... The oil sands would be rebranded as eco-friendly oil or something like that; basically to have changed the game."^[70]

GE's thermal evaporation technology developed in the 1980s for use in desalination plants and the power generation industry was repurposed^[70] in 1999 to improve on the water-intensive Steam Assisted Gravity Drainage (SAGD) method used to extract bitumen from the Athabasca Oil Sands.^[71] In 1999 and 2002 Petro-Canada's MacKay River facility was the first to install 1999 and 2002 GE SAGD zero-liquid discharge (ZLD) systems using a combination of the new evaporative technology and crystallizer system in which all the water was recycled and only solids were discharged off site.^[71] This new evaporative technology began to replace older water treatment techniques employed by SAGD facilities, which involved the use of warm lime softening to remove silica and magnesium and weak acid cation ion exchange used to remove calcium.^[71]

Cleland describes how Suncor Energy is investigating the strategy of replication where engineers design an "ideal" small-capacity SAGD plant with a 400 to 600 b/d capacity that can be replicated through "successive phases of construction" with cost-saving "cookie cutter", "repeatable" elements.^[69]

Price of crude oil

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 approximately 0.24% sulphur, rating it a sweet crude, sweeter than Brent. Its properties and production site make it ideal for being refined in the United States, primarily 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 National Bank of Canada's Tim Simard, argued that WCS is the benchmark for those buying shares in Canadian oil sands companies, such as Canadian Natural Resources, Cenovus Energy Northern Blizzard Resources, Pengrowth Energy, or Twin Butte Energy or others where a "big part of their exposure will be to heavy crude”.^[72]

The price of Western Canadian Select (WCS) crude oil (petroleum) per barrel^[73] suffers a differential^[74] against West Texas Intermediate (WTI)^[75] as traded on the New York Mercantile Exchange (NYMEX) as published by Bloomberg Media, which itself has a discount versus London-traded Brent oil.^[74] This is based on data on prices and differentials from Canadian Natural Resources (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°."^[58]: 9

West Texas Intermediate WTI is a sweet, light crude oil, with an API gravity of around 39.6 and a specific gravity of about 0.827, which is lighter than Brent crude. It contains about 0.24% sulphur thus is rated as a sweet crude oil (having less than 0.5% sulphur), sweeter than Brent which has 0.37% sulphur. 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.

"WCS prices at a discount to WTI because it is a lower quality crude (3.51Wt. percent sulphur and 20.5 API gravity)^[76] and because of a transportation differential. The price of WCS is currently set at the U.S. Gulf Coast. It costs approximately $10/bbl for a barrel of crude to be transported from Alberta to the U.S. Gulf Coast, accounting for at least $10/bbl of the WTI-WCS discount. Pipeline constraints can also cause the transportation differential to rise significantly.

By March 2015, with the price of Ice Brent at US$60.55, and WTI at US$51.48, up US$1.10 from the previous day, WCS also rose US$1.20 to US$37.23 with a WTI-WCS price differential of US$14.25.^[77] By June 2, 2015, with Brent at US$64.88/bbl, WTI at US$60.19/bbl and WCS at US$52.39/bbl.^[32]

According to the Financial Post, most Canadian investors continued to quote the price of WTI and not WCS even though many Canadian oil sands producers sell at WCS prices, because WCS "has always lacked the transparency and liquidity necessary to make it a household name with investors in the country".^[72] In 2014 Auspice created the Canadian Crude Excess Return Index to gauge WCS futures. Tim Simard, head of commodities at the National Bank of Canada, claims "WCS has "some interesting different fundamental attributes than the conventional WTI barrel." WCS has "better transparency and broader participation" than Maya. However, he explained that in 2015 "one of the only ways to take a position in oil is to use an ETF that is tied to WTI."^[72] Simard claims that when the global price of oil is lower, for example, "the first barrels to be turned off in a low-price environment are heavy barrels" making WCS "closer to the floor" than WTI.^[72]

In order to address the transparency and liquidity issues facing WCS, Auspice created the Canadian Crude Index (CCI), which serves as a benchmark for oil produced in Canada.^[78] The CCI allows investors to track the price, risk and volatility of the Canadian commodity.^[78] The CCI can be used to identify opportunities to speculate outright on the price of Canadian crude oil or in conjunction with West Texas Intermediate (WTI) to put on a spread trade which could represent the differential between the two.^[79] The CCI provides a fixed price reference for Canadian crude oil by targeting an exposure that represents a three-month rolling position in crude oil.^[80] To create a price representative of Canadian crude the index uses two futures contracts: A fixed-price contract, which represents the price of crude oil at Cushing, Oklahoma, and a basis differential contract, which represents the difference in price between Cushing and Hardisty, Alberta.^[80] Both contracts are priced in U.S. dollars per barrel. Together, these create a fixed price for Canadian crude oil, and provide an accessible and transparent index to serve as a benchmark to build investable products upon, and could ultimately increase its demand to global markets.^[79]

In the spring of 2015, a veteran journalist specializing in energy and finance, Jeffrey Jones, described how the price of WCS briefly the "hottest commodity" with is price surging over 70% "outpacing West Texas intermediate (WTI), Brent" and "quietly" became the "hottest commodity in North American energy".^[81] In April 2015, Enbridge filled a "new 570,000-barrel-a-day pipeline".^[82] A May 2015 TD Securities report provides some of the factors contributing the WCS price gains as "normal seasonal strength driven by demand for the thick crude to make asphalt as road paving", improvements to WCS access to various U.S. markets in spite of pipeline impediments, five-year high production levels and high heavy oil demand in U.S. refineries particularly in the US Midwest, a key market for WCS.^[81]

By September 9, 2015, the price of WCS was US$32.52 and the WTI-WCS differential was differential US$13.35.^[37] It plunged to US$14 a barrel, a record low, in November 2018^[45] but rose to US$28 by December 24.

On March 30, 2020, the combination of the COVID-19 pandemic and the 2020 Russia–Saudi Arabia oil price war, caused the price of oil to drop to below $30 a barrel.^{[83][84][85][86]}

Crude oil differentials and Western Canadian Select (WCS)

By June 2015 the differential between WTI and WCS was US$7.8, the lowest it has ever been.^[32]

In a 2013 white paper for the Bank of Canada, 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".^[87]

Alberta's Minister of Finance argues that WCS "should be trading on par with Mayan crude at about $94 a barrel".^[88] Maya crudes are close to WCS quality levels.^[76] However, Maya was trading at US$108.73/bbl in February 2013, while WCS was US$69/bbl. 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".^[28] 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, (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, sulphur 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.^[89]

(Prices except Maya for years 2007-February 2013)^[94](Prices for Maya)^[88] (Prices for April 24, 2013).^[95]

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'".^[96] 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'".^[96] 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".^[96]

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 bpd of heavy oil being transported by rail.^[97]

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.^[91] 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.^[91][91]

In April 2020, the price of WTI was $16.55 and the price of WCS was $3.50 with a differential of -$13.05.^[15] In June the price of WTI was $38.31 and WCS $33.97, with a differential of -$4.34.^[15]

Transport

Pipelines

According to the Oil Sands Magazine, as of March 31, 2020, Western Canadian crude oil export pipelines—Trans Mountain Corporation, TC Energy, Enbridge, and Plains All American Canada—have a total estimated export capacity of 4,230,000 b/d.^[98]

Heavy discounts on Albertan crudes in 2012 were falsely attributed to crudes being "landlocked" in the U.S. Midwest. Since that time, several major pipelines have been constructed to release that glut, including Seaway, the Southern leg of Keystone XL and Flanagan South. At the same time Enbridge was forced to shut down Line 55 Spearhead pipeline and Line 59 Flanagan South pipeline in Missouri because of a crude oil leak.^[35][36]

However, significant obstacles persist in approvals on pipelines to export crude from Alberta. In April 2013, Calgary-based Canada West Foundation warned that Alberta is "running up against a wall around 2016, when we will have barrels of oil we can't move".^[99] For the time being, rail shipments of crude oil have filled the gap and narrowed the price differential between Albertan and North American crudes. However, additional pipelines exporting crude from Alberta will be required to support ongoing expansion in crude production.

Trans Mountain Pipeline System

The Trans Mountain Pipeline System, which has transported liquid fuels since 1953, was purchased from the Canadian division of Kinder Morgan Energy Partners, by the Canada Development Investment Corporation (CDIC)'s Trans Mountain Corporation.^[100] The Trans Mountain Pipeline is the only pipeline that carries Albertan crude and refined oil to the British Columbia Coast. The CDIC, which is accountable to the Parliament of Canada,^[100] is in charge of the pipeline system and the Trans Mountain Expansion Project (TMX).

Keystone Pipeline System

TC Energy's Keystone Pipeline System is an oil pipeline system in Canada and the United States that was commissioned in 2010.^[101] It runs from the Western Canadian Sedimentary Basin in Alberta to refineries in Illinois and Texas, and also to oil tank farms and an oil pipeline distribution center in Cushing, Oklahoma.^[102]

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 Trans Mountain line to Vancouver, British Columbia, Alberta intensified exploration of two northern projects "to help the province get its oil to tidewater, making it available for export to overseas markets".^[99] Canadian Prime Minister Stephen Harper, spent $9 million by May 2012 and $16.5 million by May 2013 to promote Keystone XL.^[103]

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.^[103]

The project was rejected by the Obama administration on November 6, 2015,^[104] "over environmental concerns".^[105][106] It was revived by Presidential executive order on January 24, 2017, by President Donald Trump.^[107][108] which "would transport more than 800,000 barrels per day of heavy crude" from Alberta to the Gulf Coast.^[105]

On March 31, 2020, TC Energy's CEO Russ Girling said that construction of the Keystone XL Pipeline would resume,^[109] following Alberta's Premier, Jason Kenney's announcement that the UCP government was taking an "equity stake" and providing a "loan guarantee", which amounts to a "total financial commitment of just over $7 billion" to the Keystone XL project.^[110] On January 20, 2021, President Joe Biden revoked the permit for the pipeline on his first day in office fulfilling a long-time promise.^[111]

Energy East pipeline

The Energy East pipeline was a proposed pipeline project announced on August 1, 2013, by TransCanada CEO Russ Girling. The $12 billion 4,400-kilometre (2,700 mile) pipeline project^[112] was canceled by TransCanada in 2017. A number of groups announced their intention to oppose the pipeline.^[113] The project was canceled on October 5, 2017, by TransCanada.^[114] In the long term, this meant that WCS could be shipped to Atlantic tidewater via deep water ports such as Quebec City^[115] and Saint John. Potential heavy oil overseas destinations include India,^[115] 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^[115] from Alberta to eastern Canadian refineries in Montreal and Quebec City, for example. Eastern Canadian refineries, such as Imperial Oil's 88,000-barrel-a-day refinery in Dartmouth, N.S.,^[115] currently imports 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 would have had the potential of carrying 1.1-million barrels of oil per day from Alberta and Saskatchewan to eastern Canada.^[116]

Patricia Mohr, a Bank of Nova Scotia senior economist and commodities analyst, in her report^[96] on the economic advantages to Energy East, argued that, Western Canadian 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.^[115]In her report, Mohr predicted that initially Quebec refineries, such as those owned by Suncor Energy and Valero, could access light oil or upgraded synthetic crude from Alberta's oil sands via Energy East to displace "imports priced off more expensive Brent crude".^[115] In the long term, supertankers 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."^[115]

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's, would be built near Irving Oil's import terminal with construction to begin in 2015.^[117]

Maine-based Portland–Montreal Pipe Line Corporation, which consists of Portland Pipe Line Corporation (in the United States) and Montreal Pipe Line (in Canada), is considering ways to carry Canadian oil sands crude to Atlantic tidewater at Portland's deep-water port.^[118] 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.

Enbridge Pipeline System

Enbridge, which operates in North America, has the longest crude oil transportation system in the continent.^[119]

Enbridge Northern Gateway Pipelines, which was first announced in 2006, would have transported heavy crude oil from Athabasca to Kitimat, British Columbia.^[120] Under Prime Minister of Canada Justin Trudeau, Bill-48 was passed in 2015, which imposed a ban on oil tanker traffic on the north coast of British Columbia. Bill-48 made the project uneconomical.^[121]

Enbridge owns and operates the Alberta Clipper pipeline—Line 67—part of the Enbridge Pipeline System, which has been running from Hardisty, Alberta to Superior, Wisconsin, in the United States since 2010, connecting the oil sands production area with the existing network.^[122][123]

Enbridge reversed the flow direction of the Seaway pipeline to originate in Cushing, transporting WCS to Freeport, Texas, on May 17, 2012, which caused a price increase in WCS.^[2] With the opening of Enbridge's major pipeline Seaway—the Southern leg of Keystone XL and Flanagan South Line 59 in Missouri in 2015, some of the "bottleneck" was relieved.^[35][36] In April 2015, Enbridge filled a "new 570,000-barrel-a-day pipeline".^[82]

By March 2020, Cenovus Energy has committed to 75,000 barrels a day in long-term contracts with Enbridge to ship via Mainline and Flanagan South systems to Texas.^[124] As of March 30, 2020, the price oil producers pay to transport heavy oil to Texas through Enbridge pipelines, is US$7 to US$9 a barrel.^[124] At that time, the price of WCS a barrel was US$3.82 per barrel.^[51]

Plains All American Pipeline

The 16.5 km long Milk River and the 0.75 km Rangeland pipelines are owned and operated by the Texas-headquartered Plains All American Pipeline.^[98] The Milk River pipeline transports 97,900 bbl/day.^[98]

Rail

By 2011, output from the Bakken Shale formation in North Dakota Crude was increasing faster than pipelines could be built. Oil producers and pipeline companies turned to railroads for transportation solutions.^[125] Bakken oil competes with WCS for access to transportation by pipeline and by rail. By the end of 2010, Bakken oil production rates had reached 458,000 barrels (72,800 m³) per day, thereby outstripping the pipeline capacity to ship oil out of the Bakken.^[126][125] By January 2011 Bloomberg News reported that Bakken crude oil producers were using railway cars to ship oil.^[125]

In 2013, there were new rail shipments of WCS.^[96] Since 2012, the amount of crude oil transported by rail in Canada had quadrupled and by 2014 it was expected to continue to surge.^[127]

In August 2013, then-U.S. Development Group's (now USD Partners) CEO, Dan Borgen, a Texas-based oil-by-rail pioneer, shifted his attention away from the U.S. shale oil plays towards the Canadian oil sands.^[128] Borgen "helped introduce the energy markets to specialized terminals that can quickly load mile-long oil tank trains heading to the same destination - facilities that .... revolutionized the U.S. oil market".^[128] Since 2007, Goldman Sachs has played a leading role in financing USD's "expansion of nearly a dozen specialized terminals that can quickly load and unload massive, mile-long trains carrying crude oil and ethanol across the United States".^[129] USD's pioneering projects included large-scale “storage in transit” (SIT) inspired by the European model for the petrochemicals industry.^[129] USD sold five of the specialized oil-by-rail US terminals to "Plains All American Pipeline for $500 million in late 2012, leaving the company cash-rich and asset light".^[129][128] According to Leff, concerns have been raised about the link between Goldman Sachs and USD.

"Understanding the trading flows through such lynchpin oil facilities can provide valuable insight for oil traders, who scour the market for information that may help them predict how much oil is being shipped to different parts of the country. Large price discounts for oil in locations poorly served by pipelines have offered traders attractive opportunities if they can figure out how to get the crude to higher-priced markets. Data on crude-by-rail shipments is particularly opaque, with government figures only available months after."

— Jonathan Leff 2013a

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 bpd of heavy oil being transported by rail.^[97]

The price of WCS rose in August 2014 as anticipated expansions in crude-by-rail capacity at Hardisty increased when USDG Gibson Energy's Hardisty Terminal, the new state-of-the-art crude-by-rail origination terminal and loading facility with pipeline connectivity,^[130] became operational in June 2014 with a capacity to load up to two 120-rail car unit trains per day (120,000 of heavy crude bbd).^[131][132] The Hardisty rail terminal can load up to two 120-railcar unit trains per day "with 30 railcar loading positions on a fixed loading rack, a unit train staging area and loop tracks capable of holding five unit trains simultaneously".^[131] By 2015 there was "a newly-constructed pipeline connected to Gibson Energy's Hardisty storage terminal" with "over 5 million barrels of storage in Hardisty".^[131]

Before the 2019 provincial election, the previous NDP government, had approved a plan that would cost $3.7 billion over a three-year period to transport up to 120,000 barrels per day out of Alberta by leasing 4,400 rail cars.^[54] While the NDP government said the leased cars "would generate $5.9 billion in increased royalties, taxes and commercial revenues", the UCP government under Premier Jason Kenney, who won the 2019 election, disagreed. The UCP's October 2019 budget included a $1.5 billion incentive to cancel the NDP crude-by-rail program. The government said that this would "mitigate further losses by $300 million." They entered into negotiations to privatize the crude-by-rail agreements.^[54]

After months of discussions, Premier Kenney's UCP government announced in late October 2019, that petroleum producers could increase their "oil output levels above current provincial quotas", if they incrementally increased the amount of oil they ship by rail.^[54]

Canadian Pacific Railway

In 2014, Canadian Pacific Railway (CPR) COO Keith Creel said CPR was in a growth position in 2014 thanks to the increased Alberta crude oil (WCS) transport that will account for one-third of CPR's new revenue gains through 2018 "aided by improvements at oil-loading terminals and track in western Canada".^[127] By 2014 CPR was shaped by CEO Hunter Harrison and American activist shareholder Bill Ackman. Americans own 73% of CPR shares, while Canadians and Americans each own 50% of CN^{[clarification needed]}.^[133] In order to improve returns for their shareholders, railways cut back on their workforce and downsized the number of locomotives.^[133]

Creel said in a 2014 interview that the transport of Alberta's heavy crude oil would account for about 60% of the CP's oil revenues, and light crude from the Bakken Shale region in Saskatchewan and the U.S. state of North Dakota would account for 40%. Prior to the implementation of tougher regulations in both Canada and the United States following the Lac-Mégantic rail disaster and other oil-related rail incidents which involved the highly volatile, sensitive light sweet Bakken crude, Bakken accounted for 60% of CPR's oil shipments. Creel said that "It safer, less volatile and more profitable to move and we’re uniquely positioned to connect to the West Coast as well as the East Coast."^[127]

Railway officials claim that more Canadian oil-by-rail traffic is "made up of tough-to-ignite undiluted heavy crude and raw bitumen".^[134] Zdroj:https://en.wikipedia.org?pojem=Western_Canadian_Select
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