Western Canadian Select (WCS) is the benchmark price for 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
Cenovus headquarters, CalgarySuncor Energy headquarters, CalgaryHusky headquarters in Calgary. Husky was acquired by Cenovus in 2020.
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.
Plays
Cost of production fall 2014
Saudi Arabia
US$10–25 per barrel
Montney Oil Alberta and British Columbia
US$46
Saskatchewan Bakken
US$47
Eagle Ford, USA Shale+
$40–6 US$50 (+ Liquids-rich Eagle Ford plays, assuming natural gas prices of US$3.80 per million Btu)
Lloyd & Seal Conventional Heavy, AB
US$50
Conventional Light, Alberta and Saskatchewan
US$58.50
Nebraska USA Shale
US$58.50
SAGD Bitumen Alberta
US$65
North Dakota Bakken, Shale
US$54–79
Permian Basin, TX Shale
US$59–82
Oil sands legacy projects
US$53
Oil sands mining and infrastructure new projects
US$90
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]
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]
"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.
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 [pipeline capacity] 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.
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]
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 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]
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
CN GATX 7565 tank car
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]
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 [WCS is] 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]
CPR's high capacity North Line, which runs from Edmonton to Winnipeg, is connected to "all the key refining markets in North America".[131] Chief Executive Hunter Harrison told the Wall Street Journal in 2014 that Canadian Pacific would improve tracks along its North Line as part of a plan to ship Alberta oil east.[127]
Waterborne
On September 21, 2014, Suncor Energy loaded its first tanker of heavy crude, about 700,000 barrels of WCS, onto the tanker Minerva Gloria at the port of Sorel near Montreal, Quebec. Minerva Gloria is an Aframax Crude Oil double hulled tanker with a deadweight tonnage (DWT) of 115,873 tons. Her destination was Sarroch, on the Italian island of Sardinia.[29]Minerva Gloria measures 248.96 metres (816.8 ft) × 43.84 metres (143.8 ft).[135]
"A second tanker, the Stealth Skyros, is scheduled to load WCS crude from Montreal at the end of next week for delivery to the U.S. Gulf Coast, a person with knowledge of booking said today. That shipment will be the first waterborne delivery to the Gulf from eastern Canada for the oil, which is typically carried by pipeline."
— Tobben and Murtaugh 2014
The 116,000-dwt Stealth Skyros measures 250 metres (820 ft) × 44 metres (144 ft).[136] From October 2013 to October 2014 Koch held a one-year charter on Stealth Skyros which was fixed for 12 months at $19,500 per day.[137]
Oil tanker, double hull
Oil tanker side view
An Aframax double-hulled crude oil tanker similar to the Minerva Gloria
Repsol and WCS
The Spanish oil company Repsol obtained the license from the U.S. Department of Commerce to export 600,000 barrels of WCS from the United States.[138] The WCS was shipped via Freeport, Texas, in the Gulf Coast (USGC) to the port of Bilbao on the Suezmax oil tanker, Aleksey Kosygin. It is considered to be "the first re-export of Canadian crude from the USGC to a non-US port"[139] as the "US government tightly controls any crude exports, including of non-US grades."[139] The Brussels-based European Union's European Environment Agency (EEA)[140] monitored the trade. WCS, with its API of 20.6 and sulphur content of 3.37%, has been controversial.[141]
In December 2014, Repsol agreed to buy Talisman Energy (TLM.TO), Canada's fifth-largest independent oil producer, for US$8.3 billion which is estimated to be at about 50 percent of Talisman's value in June 2014. By December 2014, the price of WCS had dropped to US$40.38 from $79.56 in April 2014.[91] The global demand for oil decreased, production increased and the price of oil plunged starting in June and continuing to drop through December.[142]
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.[8][76][145] Most of WCS goes to refineries in the Midwestern United States where refineries "are configured to process a large percentage of heavy, high-sulphur crude and to produce large quantities of transportation fuels, and low amounts of heavy fuel oil".[145] 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.[145]
WCS crude oil with its "very low API (American Petroleum Institute) gravity and high sulfur content and levels of residual metals"[76][145] 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."[145]
US refineries import large quantities of crude oil from Canada, Mexico, Colombia and Venezuela, and they began in the 1990s to build coker and sulphur capacity enhancements to accommodate the growth of these medium and heavy sour crude oils while meeting environmental 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.[146][145] 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.[146][145]
Large integrated oil companies that produce WCS in Canada have also started to invest in upgrading refineries in order to process WCS.[147][145]
The BP Plc refinery in Whiting, Indiana,[148] is the sixth-largest refinery in the US with a capacity of 413,500 b/d.[149][150] In 2012 BP began investing in a multi-billion modernization project at the Whiting refinery in order to distill WCS.[151][152][153] This $4 billion refit[149] was completed in 2014 and was one of the factors contributing to the increase in price of WCS.[97] The centerpiece of the upgrade was Pipestill 12, the refinery's largest crude distillation unit, which came online in July 2013.[149] Distillation units provide feedstock for all the other units of the refinery by distilling the crude as it enters the refinery.[149] The Whiting refinery is situated close to the border between Indiana and Illinois. It is the major buyer of CWS and WTI from Cushing, Oklahoma, the delivery point of the US benchmark oil contract.
On August 8, 2015, there was a malfunction of piping inside Pipestill 12 causing heavy damage and the unit was offline until August 25.[34][149] This was one of the major factors contributing to the drop in the price of oil[33][154] with WCS at its lowest price in nine years.[35][36]
Toledo refinery, Ohio
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.[155][156] Since the early 2000s, the company has been focusing its refining business on processing crude from oil sands and shales.[148][157]
Since September 2013 WCS has been processed at Imperial Oil's Sarnia, Ontario, refinery and ExxonMobil Corporation's (XOM) has 238,000 barrels (37,800 m3) Joliet plant, Illinois and Baton Rouge, Louisiana.[158]
By April 2013, Imperial Oil's 121,000 barrels (19,200 m3) Sarnia, Ontario refinery was the only plugged-in coking facility in eastern Canada that could process raw bitumen.[99]
In July 2014 the Canadian Academy of Engineering identified the Sarnia-Lambton $10-billion oil sands bitumen upgrading project to produce refinery ready crudes, as a high priority national scale project.[159]
Lloydminster heavy oil, a component in the Western Canadian Select (WCS) heavy oil blend, is processed at the CCRL 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.[160] The price of Western Canadian Select weakened against U.S. benchmark West Texas Intermediate (WTI) oil.[160]
The Pine Bend Refinery, the largest oil refinery in Minnesota, located in the Twin Cities receives 80% of its incoming heavy crude from the Athabasca oil sands.[161] The crude oil is piped from the northwest to the facility through the Lakehead and Minnesota pipelines which are also owned by Koch Industries. Most petroleum enters and exits the plant through a Koch-owned, 537-mile pipeline system that stretches across Minnesota and Wisconsin.[161] The U.S. Energy Information Agency (EIA) ranked it at 14th in the country as of 2013 by production.[162][163] By 2013 its nameplate capacity increased to 330,000 barrels (52,000 m3) per day.[164]
Repsol responded to the enforcement in January 2009 of the European Union's reduced sulphur content in automotive petrol and diesel from 50 to 10 parts per million, with heavy investment in upgrading their refineries. They were upgrading three of their five refineries in Spain (Cartagena, A Coruña, Bilbao, Puertollano and Tarragona) with cokers that have the capacity to refine Western Canadian Select heavy oil. Many other European refineries closed as margins decreased.[139] Repsol tested the first batches of WCS at its Spanish refineries in May 2014.[138]
Cartagena refinery
In 2012 Repsol completed its €3.15-billion upgrade and expansion of its Cartagena refinery in Murcia, Spain, which included a new coking unit capable of refining heavy crude like WCS.[165]
Repsol's 2013 completed upgrades, which included a new coker unit and highly efficient cogeneration unit at their Petronor refinery at Muskiz near Bilbao, cost over 1 billion euros and represents "the largest industrial investment in the history of the Basque Country".[166] This new coker unit will produce "higher-demand products such as propane, butane, gasoline and diesel" and "eliminate the production of fuel oil".[166] The cogeneration unit will reduce CO2 emissions and help achieve Spain's Kyoto protocol targets. The refinery is self-sufficient in electricity and capable of distributing power to the grid.[166]
Blenders: ANS, WCS, Bakken Oil
In their 2013 article published in Oil & Gas Journal, John Auers and John 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".[167]
The CIBC reported that the oil industry continued to produce massive amounts of oil in spite of a stagnant crude oil market. Oil production from the Bakken formation alone was forecast in 2012 to grow by 600,000 barrels every year through 2016. By 2012, Canadian tight oil and oil sands production was also surging.[168]
By the end of 2014, as the demand for global oil consumption continued to decline, the remarkably rapid oil output growth in ‘light, tight’ oil production in the North Dakota Bakken, the Permian and Eagle Ford Basins in Texas, while rejuvenating economic growth in "U.S. refining, petrochemical and associated transportation industries, rail & pipelines", [it also] "destabilized international oil markets".[5]
Since 2000, the wider use of oil extraction technologies such as hydraulic fracturing and horizontal drilling, have caused a production boom in the Bakken formation which lies beneath the northwestern part of North Dakota.[169][170][171] WCS and Bakken compete for pipelines and railway space. By the end of 2010, 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] This oil competes with WCS for access to transportation by pipeline and rail. Bakken production has also increased in Canada, although to a lesser degree than in the US, since the 2004 discovery of the Viewfield Oil Field in Saskatchewan. The same techniques of horizontal drilling and multi-stage massive hydraulic fracturing are used. In December 2012, 2,357 Bakken wells in Saskatchewan produced a record high of 71,000 barrels per day (11,000 m3/d).[172] The Bakken Formation also produces in Manitoba, but the yield is small, averaging less than 2,000 barrels per day (300 m3/d) in 2012.[173]
"Just over 21% of North Dakota’s total 2013 gross domestic product (GDP) of $49.77 billion comes from natural resources and mining."[174]
"The state levies a 5% production tax on the gross value at the wellhead of all oil produced in the state, with some exceptions. The state also levies an oil extraction (excise) tax on produced oil. In 2012 the state collected $1.68 billion in oil revenues, up 71.4% over its 2011 collections. Oil taxes provide 42.3% of the state’s total net revenues, nearly four times the individual income tax and more than eight times the revenue received from corporate income taxes. The state’s 5% oil production tax is split between state and county governments. The state treasurer takes 20% that it then allocates to cities and to an impact grant program. The remaining 80% is split between the state and county governments according to a mandated formula."
— Auskick 2014
"The state created a legacy fund in 2010 — similar to a sovereign wealth fund in foreign nations — to salt away some of the state’s revenues from oil and gas production. By law, 30% of the state’s oil and gas taxes (after some mandated distributions) are deposited in the legacy fund. This has resulted in oil and gas tax collections of $446.3 million for fiscal year 2012, $824.7 million for fiscal year 2013 and $926.6 million for fiscal year 2014."
— Auskick 2014
Royalties
Royalty rates in Alberta are based on the price of WTI. That royalty rate is applied to a project's net revenue if the project has reached payout or gross revenue if the project has not yet reached payout. A project's revenue is a direct function of the price it is able to sell its crude for. Since WCS is a benchmark for oil sands crudes, revenues in the oil sands are discounted when the price of WCS is discounted. Those price discounts flow through to the royalty payments.
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.[175]
In 2006–07, 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.[176] In that year, Alberta's total resource revenue "fell below $7 billion...when the world economy was in the grip of recession".[177]
In February 2012, the Province of Alberta "expected $13.4 billion in revenue from non-renewable resources in 2013-14".[177] By January 2013, the province was anticipating only $7.4 billion. "30 percent of Alberta’s approximately $40-billion budget is funded through oil and gas revenues. Bitumen royalties represent about half of that total."[177] In 2009–10, royalties from the oil sands amounted to $1.008 billion (Budget 2009 cited in Energy Alberta 2009).[176]
In order to accelerate the 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 percent of a project’s gross revenues until the project’s investment costs are paid in full at which point rates increased to 25 percent 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."[175] A revised Alberta Royalty Regime was implemented on January 1, 2009.[178] through which each oil sands project pays a gross revenue royalty rate of 1% (Oil and Gas Fiscal Regimes 2011:30).[179] Oil and Gas Fiscal Regimes 2011 summarizes the petroleum fiscal regimes for the western provinces and territories. The Oil and Gas Fiscal Regimes described how royalty payments were calculated:[179]
"After an oil sands royalty project reaches payout, the royalty payable to the Crown is equal to the greater of: (a) the gross revenue royalty (1% - 9%) for the period, and (b) the royalty percentage (25% - 40%) of net revenue for the period. Effective January 1, 2009 the royalty percentage of net revenue is also indexed to the Canadian dollar price of WTI. It is 25% when the WTI price is less than or equal to $55/bbl, rising linearly to a maximum of 40% when the price reaches $120/bbl.
For royalty purposes, net revenue equals project revenue less allowed costs."
— Oil and Gas Fiscal Regimes
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".[179]
Payout refers "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"].[180]
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 multinational 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.[181]
From 2009 to 2015, oil sands royalties represented the largest contributor to the province's royalty revenues and contributed about 10% of all of Alberta revenues.[182] In 2014-2015 oil sands revenue was over $5 billion and represented over 10% of Alberta's $48.5 operational expenses.[182] As of December 2015, the only sources of revenue that contributed more were personal income tax provides at 23%, federal transfers at 13%, and corporate income tax at 11%.[182]
In 2019, 1.1 billion barrels of oil were extracted from the Alberta oil sands.[183]
Oil Sands Royalty Rates
"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."[184]
Price WTI C $/bbl
Pre-Payout Royalty Rate on Gross Revenue
Post Payout Royalty Rate on Net Revenue
Below C$55
1.00%
25.00%
C$60
1.62%
26.15%
C$75
3.46%
29.62%
C$100
6.54%
35.38%
Above C$120
9.00%
40.00%
Bitumen Bubble
Athabasca Oil Sands Planned Production 2012
In January 2013, the then-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.[185] 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 resulted in a loss of about six billion dollars in provincial revenue.[186]
^The "Middle East onshore market" was the "cheapest source of new oil volumes globally" with the "North American tight oil"—which includes onshore shale oil in the United States—in second place. The breakeven price for North American shale oil was US$68 a barrel in 2015, making it one of the most expensive to produce. By 2019, the "average Brent breakeven price for tight oil was about US$46 per barrel. The breakeven price of oil from Saudi Arabia and other Middle Eastern countries was US$42, in comparison.
Financial Post (December 2, 2014), Commodities, Calgary, Alberta: Calgary Herald
"Commodities", Financial Post, Calgary Herald, p. B7, December 19, 2014a
"Commodities", Financial Post, Calgary Herald, pp. D6–D7, March 18, 2015a
"Commodities", Financial Post, Calgary Herald, pp. B8–B9, August 6, 2015c
"Commodities", Financial Post, Calgary Herald, pp. D8–D9, August 6, 2015d
Foran, John (June 17, 2013). Market Diversification for Canadian Oil and Gas(PDF). 2013 U. S. Energy Information Administration (EIA) Energy Conference. Energy in the Americas. Washington, DC: Natural Resources Canada. Retrieved April 12, 2014.
"Energy Prices", Government of Alberta, June 18, 2014, retrieved July 18, 2014
"Manitoba oil facts", Government of Manitoba, 2013, retrieved September 17, 2013
Hackett, D.; Noda, L.; Grissom, S.; Moore, M.C.; Winter, J. (February 8, 2013), Pacific Basin Heavy Oil Refining Capacity(PDF), SPP Research Papers, vol. 6, Calgary, Alberta: School of Public Policy, University of Calgary, retrieved December 13, 2013
Moore, M.C.; Flaim, S.; Hackett, D.; Grissom, S.; Crisan, D.; Honarvar, A. (December 2011). "Catching the Brass Ring: Oil Market Diversification Potential for Canada"(PDF). SPP Research Papers. 4 (16). Calgary, Alberta: School of Public Policy, University of Calgary. Retrieved December 13, 2013.
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