Alberta Needs the Keystone XL Pipeline – But Not for the Reasons You Think!
My first cousin, who worked in Fort McMurray, asked a legitimate question on Facebook.
Why does Canada still buy oil from Saudi Arabia instead of Alberta?
An angry Albertan offered a knee-jerk answer.
That’s easy. Because of Trudeau, of course!
Based on the simple-minded conspiracy-based Facebook comments that followed the original post, I have to wonder if Albertans really want to know the answer or if they are happy with asking confirmation bias questions and finding a convenient effigy to burn in protest.
Alberta Venting
The truth is out there if anyone is willing to do the research. I know they wouldn’t, so I decided to tackle this question myself. Armed with a basic knowledge of micro- and macroeconomics, political science, sociology, economic history, deductive reasoning, and the oil and gas industry, I carefully selected a critical set of keywords and conducted 568 Google searches.
As a result of those searches, I identified and reviewed over 50 relevant online articles from the oil industry, historical articles, news reports, scientific papers, and government statistical reports. After carefully reading, comparing, and rereading, I discovered a reasonably sound, fact-based consensus on why Canada doesn’t buy all its crude from Alberta. Read on, follow the sources and make up your own mind. Then let me know if it’s all so simple.
My reply,
The closest-to-the-truth free market answer should be “supply and demand.”
But, you say, Albertan oil is cheap. Deep discounted, in fact. So, shouldn’t that equal higher demand and, ultimately, higher sales?
No, because the reality of supply and demand is not merely based on “price.” Many other factors come into play when any corporation decides to buy or not buy Albertan oil. To understand the big picture, we must examine the entire worldwide petroleum production process, including what determines the price of the coveted gasoline which powers the jacked-up four-wheel-drive pickup trucks we love to burn around in.
Precious
To start with, although crude oil is “upstream” of refineries and gasoline is “downstream” of refineries, the price of crude oil directly impacts the price of petrol. In this cost analysis, we are primarily concerned with the various factors that impact the upstream costs of petroleum production. This can be simplified into three major factors:
- Cost of extraction.
- Cost of transportation.
- Cost of refining.
Getting Good Grades
Before we discuss costs, however, it is essential to understand how different types of crude oil are graded. Cost factors are profoundly affected by the specifications or qualities of crude oil (known as “grades”). Unfortunately, 145 million years ago, during the Cretaceous period, no quality control measures were in place. Thus, not all crude oil was created equal.
Although there are hundreds of different grades, the simplest way to understand how the cost is affected is to classify crude into three specification grades: heavy, light sweet or light sour. For this simplification exercise, bitumen, extra heavy and heavy crude will be grouped under “heavy.” All three of these are also synonymous with “dirty” oil. This is not a slur or a slight on Albertans but rather a qualification based on contaminants and the requirement for upgrading before transporting or refining.
Light (low density/viscosity) crude is considered “high value” because it has a high percentage of light distillates. Heavy (high density/viscosity) crude is considered “low value” because it has a low percentage of light distillates. Light distillates are readily made into high-margin automobile gasoline.
Sweet (clean) crude is of high value because it is low in contaminants and sulphur. Heavy (dirty) crude leaves behind more low-value residuals after refinement than any other grade of oil. Heavy and sour crudes are less valuable because they contain impurities, such as sulphur, which are expensive to separate and significantly contribute to environmental costs in extraction and refinement. Light sour, therefore, is less valuable than light sweet but more valuable than heavy. There is no grade for heavy sweet crude.
1. Cost of Extraction
The total cost of extraction depends on the location of the crude oil, including geography, topography, depth, and its grade, which is determined by factors such as viscosity and quality. The location of the oil makes it easier or more complex to access and less expensive or more expensive to drill and/or extract. Light (low viscosity) oil flows easily, often with moderate assistance, whereas heavy (high viscosity) oil requires expensive methods, such as heating or dilution, to facilitate flow. The deeper the oil is located, the more difficult it is to extract; however, some shallow crude may be more expensive because it is labour-intensive.
In the “geographic/grade” order of easy-to-difficult, there is onshore shallow light, onshore deep light, offshore shallow light, offshore deep light, onshore shallow heavy sour, onshore shallow heavy and offshore shallow heavy.
Generally, onshore (land-based) operations are easier to access than offshore (ocean-based) operations, and shallow drilling is less technical and labour-intensive than deep drilling. Although several countries have offshore shallow heavy oil, no one has figured out how to tap it economically, leaving onshore shallow heavy oil, such as found in the Athabasca Oil Sands, as the most expensive to extract. That appears contrary to the concept that onshore and shallow extraction is more accessible, but that is because “easier/harder” can also be transposed with “less expensive/more expensive.”
The Athabasca Oil Sands are an exception to the rule due to break-even point cost accounting. Although offshore deep light requires the highest initial investment for developing the oil field infrastructure, the opportunity costs are heavily weighted at the beginning of the production period. However, once the high-value light sweet crude begins pumping, the risk-adjusted return on the initial investment is quickly paid off to a break-even point, after which the field starts to generate a profit. With world price fluctuations, the gains may fluctuate, but each new barrel of oil produced will be profitable down to a minimum (break-even) daily production cost.
Onshore shallow heavy infrastructure and extraction costs of oil sands are spread out over the entire production period. Hence, profits (within the same price spread comparison) depend entirely on day-to-day production and the current market crude prices. Since heavy crude is of low value, to begin with and due to the very high daily production costs, the price can drop below the profitability price spread very quickly. At this profit/loss price point, the onshore shallow heavy oil producers would have no economic reason to continue extraction.
Many countries export crude, but Canadian refineries only purchase from a select few. Saudi Arabia has onshore and offshore shallow light sweet, while Nigeria and Angola have both onshore and offshore shallow and deep light sweet. The U.K. and Norway have offshore deep light sweet. Iraq has onshore shallow light sweet. As a point of interest, Russia has a notorious onshore shallow heavy sour that emits a noxious sulphur gas (H2S) that will kill the drilling crew within seconds of exposure, making extraction very expensive. Again, this is a simplification based on each country’s most profitable “known reserves” of oil.
The Athabasca Oil Sands are the only place where oil companies have found methods to make onshore shallow heavy crude extraction cost-effective, using both in situ (drilling) and surface excavation (mining) methods.
2. Cost of Transportation
The total cost of transportation depends on whether the crude oil can be shipped cost-effectively to a refinery. The heavier (more viscous) the oil, the more complex and costly it is to ship via pipelines or tankers. Heavy oil must be upgraded, diluted, and/or heated to make it less viscous so it can be pumped through pipes, especially during cold winters. Additionally, heavy crude is corrosive, so pipelines and transfer (pumping) stations must be corrosion-resistant, which adds to the build costs.
The second factor is the distance and/or geography. How far does the crude need to be shipped, and what is the geography (topography and inhabitants) along the route? Port-to-port transportation via supertankers is the most cost-effective, while long-distance trucking or railway tankers over mountainous terrain are the most expensive. Pipelines are the least costly and environmentally safest means of transporting crude oil over land. Obviously, the further and more complex the transportation, the more expensive the product.
What makes Albertan heavy crude so expensive to transport isn’t just the long distances from high population centers and the complexity of transportation but also the cost to “prepare” the crude to be transported. Heavy crude extracted from the oil sands must be steamed, heated, converted into a slurry, separated from the sands, diluted with a refined distillate such as naphtha, and then upgraded to a lighter, less viscous, sweeter crude through an upgrading process. In other words, bitumen-heavy crude requires multiple complicated and expensive processing steps to prepare it for transportation.
Upgrading – Prepping for Pipes
As a preparation for transport, at least three-quarters of the Albertan bitumen heavy crude extracted during surface mining is “upgraded” before being transported or sold to other refineries. The upgrading refineries remove the highly corrosive sulphur and convert the bitumen, the raw product of oil sands extraction, into separate hydrocarbon products, including naphtha, light gas oil, and heavy gas oil. These are recombined or blended into a high-quality light, low-sulphur crude oil or, in other words, a light sweet crude. To distinguish it from conventional oil, this purified crude is referred to as synthetic crude oil (SCO) or Syncrude.
Upgrading refineries must be located near the source of the bitumen crude to minimize the initial transportation cost. Only after upgrading can the crude be shipped via tanker trucks, railway tankers, or pipelines to the refineries that will convert the crude into usable, high-value petroleum products.
Another marketable Albertan crude blend, Dilbit, is a relatively clean bitumen extracted in situ using traditional in-ground drilling and pumping methods. Dilbit still requires diluting with condensate before it can be transported, but, for the most part, it can be pumped through corrosion-resistant pipelines and processed by corrosion-resistant high-conversion refineries without further upgrading.
Dilbit can be sold and transported to high-conversion refineries “as is.” Additionally, it is often blended with conventional crude, Syncrude and non-upgraded bitumen to produce a consistent heavy sour “blended” crude called West Canada Select (WCS).
3. Cost of Refining
The cost of refining also depends on the quality or grade of the crude. Although the refining process is similar for all grades (basically boiling, distilling, and separating the petroleum components), refineries maximize profits by increasing the yields of high-value products, such as automobile gasoline. Light sweet crude has fewer impurities or sulphur; thus, you can distill naphtha and gasoline very cheaply – a lower boiling point requires less energy and few processing steps. Therefore, high-value light sweet crude is more natural and less expensive to refine, producing a higher percentage of high-value gasoline, avgas, jet fuel, and lubricants. Simple “topping” refineries that can only process light sweet crude are less expensive to build and operate as long as sweet crude is readily available.
Heavy crude processing requires not only more energy (to reach the boiling point) but also requires the processing steps of hydrotreating (removing corrosive impurities and sulphur), cracking, coking and blending to be able to turn the heavier crude oil fractions (residual industrial fuel) into high-value gasolines, jet fuels or diesel. The benefit of highly specialized “high-conversion” refineries that can process heavy crude oil is that they can have the flexibility to produce a higher percentage of low-value heating fuel oils, diesel, and asphalt to satisfy market demands. Typically, during processing, the final residuum, asphalt base, is reduced to a minimum simply because it is the least valuable product. However, the asphalt base can be maximized if your market needs new roads.
These high-conversion refineries can also make gasoline, but they have the option to balance out the comparative margins between different grades. Initially, because these highly flexible high-conversion refineries were so expensive to build and operate, there were very few in North America. Over the past decade, however, many refineries on the U.S. Gulf Coast and Midwest have undergone modifications. They all require heavy crude to continue operating, and Alberta’s Dilbit and WCS crude meet the requirements for their needs.
Okay, so what does this have to do with Canada buying oil from Saudi Arabia or the price of gas in Red Deer, Richmond, or Moncton? Well, everything.
First, let’s get something straight. The Canadian Federal Government does not purchase oil from Saudi Arabia or any other country. Albertans believe that federal “taxpayers,” including themselves, are purchasing the oil while “others” are reaping the benefits. That is simply nonsense. Private or publicly traded refineries purchase crude oil either directly from producers or through brokers, traders, or distributors. Most of Canada’s refineries and upgrading facilities are owned and operated by vertically integrated major oil companies, such as Imperial, Suncor, and Shell. Irving Oil, based in New Brunswick, purchases and refines crude oil overseas to supply gasoline, diesel, and heating fuel throughout the Maritime provinces and the American Northeast.
The Canadian Federal Government negotiates international trade agreements that allow for importing overseas crude oil and exporting Canadian crude oil. Thus, the Feds can control who the refineries buy from, but external forces, such as U.S. embargoes, tariffs, or restrictions in war zones, more often determine this.
Whereas Canada is a federation of provinces and territories, the federal government grants the rights-of-way for trans-provincial pipelines over Crown lands, including Indigenous reservations. More importantly, if necessary, they can apply eminent domain to gain access to privately owned properties where economic benefits to the country take precedence. There are various ways the Federal Government can step in to protect the interests of all Canadians, but historically, the government has only intervened during emergencies or bottleneck situations to ensure the economy runs smoothly.
In 1956, the Liberal government of Canada passed a bill through Parliament, allocating funds to construct a TransCanada pipeline connecting Alberta’s natural gas with the highly populated eastern markets of Ontario and Quebec. In 1973, the Liberal Prime Minister of Canada established a Crown corporation, Petro-Canada, to invest federal tax dollars in developing the Athabasca Oil Sands. Later, the government’s interests in both the pipeline and the national oil company were sold to private interests when the government no longer had a need to be involved.
The Feds can also set a higher or lower than the free-market price for domestic crude oil and refined petroleum products. The liberal government temporarily implemented this measure in the late 1970s to support Alberta by artificially increasing the cost of Alberta’s crude but relaxed it in 1980 when Syncrude production became competitive in the world market. Thus, crude and refined petroleum products depend on the international supply and demand market.
That takes us back to the Albertan’s question. Why are we buying crude from Saudi Arabia?
Undoubtedly, Alberta has the largest crude oil reserves, the most significant oil production and the most productive oil companies in Canada. Alberta holds 39% of Canada’s conventional oil reserves, but approximately 88% of Alberta’s oil comes from the Athabasca Oil Sands. Conventional oil “flows” and can be “pumped” from the ground and shipped via conventional pipelines, making it cheap to extract and transport. It also makes it easy to refine. Alberta’s oil sands crude, however, is a different story.
Tar Baby and the Tar Sands
The Athabascan Oil Sands were initially known as the “tar” sands, but since tar is a byproduct of refining, that term was technically incorrect. The word “tar” also has negative associations with racism and hatred, such as when the Americans “tarred and feathered” fellow Americans who they accused of being British Patriots during the American War of Independence. When thinking of Alberta, however, I think of the term “tar baby,” which can be a racial slur but originally meant getting involved in “a problematic situation that is only aggravated by additional involvement with it.” The angrier Br’er Rabbit got with the non-responsive tar “baby” effigy, the more he punched and kicked the sticky mess, and the worse the problem got.
Tar Baby: A folktale about food rights rooted in the inequalities of slavery.
To be politically correct, Alberta officially named its massive deposits the “Athabascan Oil Sands.” However, that was not technically correct either because the sands are saturated with bitumen, not oil.
In the simplest terms, bitumen is another name for asphalt. Try putting that into your gas tank and see how far you get. Again, why is Alberta bitumen priced so low? Because it is so expensive to transport and refine, and it produces a smaller percentage of the precious fluid that allows Albertans to burn rubber with gasoline-guzzling pick-up trucks.
The U.S., however, loves Alberta’s “bitumen” because, for one reason, it has over 4,310,000 km of paved roads, as well as 2,000,000,000 paved parking spots to maintain. That takes a lot of asphalt! The U.S. buys Alberta crude oil mainly because it is cheap, but it can also sell the residual asphalt to pave U.S. interstate highways and Walmart parking lots. Oh, and that is after they have extracted jet fuels and home heating oils. Specifically, Alberta’s bitumen has value in large markets.
In the examples I provided for determining the value of crude oil, I listed three main factors: the cost of extraction, transportation, and refining. As I mentioned earlier, there are several other factors. The crude’s overall production rate and marketability also affect the pricing in competition with other available crude oil being offered for sale around the world. This is not the supply and demand I mentioned earlier but rather a price-determining method called “benchmarking.”
Benchmarking
Benchmarking is a method markets use to establish global prices for crude oil from various countries and/or producers. West Canada Select, Alberta’s blended heavy crude, is benchmarked head-to-head with West Texas Intermediate (a light sweet) from the U.S. Midwest. WTI is, in turn, benchmarked head-to-head with North Seas Brent (a light sweet), including oil from the U.K. and Norway, but can also include similar grades of oil from countries such as Nigeria and Algeria.
The benchmarking comparison is based on several factors. The price spread between WTI and Brent is a derivative of geography, as Brent oil producers have easy access to shipping ports, whereas WTI is mostly landlocked within the central continental United States.
WCS, on the other hand, is “discounted” compared to West Texas Intermediate. Considering that WTI is NOT sold internationally, the pricing benchmark is only relevant because the U.S. buys WCS from Alberta. In fact, the U.S. buys 98% of all the crude oil that Canada exports, making Canada their largest supplier. Thus, to an American buyer, when comparing WTI and WCS head-to-head, WTI is a high-value product (light sweet), being cheaper to refine, and WCS is a low-value product, being more expensive to refine while producing significantly less of the high-value products per barrel.
The benchmarked price of WCS also includes a deduction for transportation, which covers the cost of adding diluent to facilitate the flow of heavy crude through the pipeline, as well as the service costs associated with pipeline usage. The final benchmark price is referred to as the “bitumen netback.” Thus, the benchmarked price spread between Brent and WTI is significant due to access to different markets, making Brent more valuable. In contrast, the price spread, called a “discount” between WTI and WCS, is even more significant because of refining and transportation costs, making WCS-heavy crude more expensive for the buyer. In other words, West Canada Select is being sold into the U.S. market at a significant discount for a compelling reason.
Thus, benchmarking considers marketability, which is determined by fixed or uncontrollable factors such as the quality of the crude and proximity to markets. Unfortunately, Alberta’s oil, formed during the tropical Cretaceous period over 100 million years ago, migrated out from under protective layers of sandstone or shale and was left exposed to the atmosphere for millions of years. Consequently, the most valuable distillates evaporated or were biodegraded by bacteria, leaving behind a thick, viscous residue known as bitumen. The oil sands basin is also domestically landlocked, with approximately 4,800 kilometres in one direction and extensive mountain ranges in the other direction between the fields and the export ports. That is what modern Alberta inherited, and they can do nothing about it. Love it or leave it. Get it or get out.
Production and World Markets
Production rates, however, add in a somewhat controllable variable. Oil producers, such as Saudi Arabia, with vast reserves and high production capacity, can adjust their output at will, thereby increasing or decreasing supply to influence or control markets. However, because many non-producing countries depend on Saudi Arabian oil exports, their production rate significantly impacts oil prices. Canada has the third-largest reserves in the world and is the fifth-largest producer, but because it only exports to the U.S., its production has a limited impact on global crude prices.
Therefore, the final market price of any crude oil shipment is heavily dependent on current-day demand and global supply variations. In other words, if a distributor or refinery needs crude oil, they will buy from whoever can supply what they need at the lowest price. If a West African or Arab Spring coup disrupts a refiner’s supply, they will switch. Alternatively, they don’t want to be locked into any long-term contract if prices drop drastically. Thus, crude oil buyers, specifically refineries, are always watching the markets and trading on futures markets, spot markets, and in-route trading, where, for example, you can buy a shipload of crude already loaded and en route to a destination. The ship will be rerouted to your destination port if you are willing to pay the price. In other words, refineries need to be flexible. That includes those who could utilize WCS-heavy crude.
East Coast Flexibility
What this means is that a refinery located on the east coast of Canada with easy access, via supertankers, to a multitude of different high-value sweet crude oil producers, particularly those along the West African coast, the North Africa and Mediterranean coasts, and those along the Red Sea with access to the Suez Canal, will have purchasing flexibility. Additionally, an East Coast refinery would have access to the entire eastern seaboard of Canada and the northeastern United States, with minimal competition for marketing and distribution. Any such refinery would have the ability to take advantage of world prices on the swing.
Irving Oil, an exclusively Canadian company, has established itself in an enviable position, building and operating the largest oil refinery in Canada. The Irving Oil refinery, however, began operations in the 1960s, when Alberta crude was not an option. They had access to light, sweet crude from multiple sources and built their refinery to maximize the use of the world’s best oils. Saudi Arabia, for example, has no shortage of light sweet, and it is relatively cheap. Irving had no reason to spend billions on building a plant to refine heavy crude when light sweet was abundant, easy to access and transport and profitable to refine. Although the refinery now has a limited capability to refine heavy crude (after all, everyone needs asphalt and heating fuels), the refinery needs light sweet to stay in business.
Initially built in 1960 and continuously upgraded, the Irving Oil Refinery has a daily production capacity of 320,000 barrels of crude oil. To stay productive, the refinery is supplied by over 100 supertankers a year to its own deep-water terminal facility in St. John, as well as regular rail tanker deliveries to its back door. Irving additionally ensures access to downstream world markets by chartering and operating its private flagship petroleum tankers, thus minimizing handling, transportation, and shipping costs and delays.
Quebec and Ontario Markets
Based on geography, Quebec and Ontario refineries are in a slightly different category, specifically their proximity to large population centers (markets) and existing pipelines. The refineries in these provinces also began refining cheap Arab oil in the 1970s, so their original refineries were built to process light, sweet crude that could be quickly transported to the St. Lawrence ports. With the Arab Oil embargo of 1973, however, the political winds forced changes in both the U.S. and Canadian markets.
In 1975, to address this problem, the Canadian government implemented a pipeline to supplement the existing railway tankers that supplied oil to Ontario and Quebec refineries from Alberta, making Canada less dependent on foreign oil. This pipeline was routed through the U.S., partially because a southern route around the Great Lakes was less expensive to build and mainly because the pipeline also provided oil producers with easy and direct access to the very lucrative U.S. markets.
Since the pipeline was built, however, Albertan oil has not constantly flowed north through those pipelines. For several reasons, primarily related to the global supply and demand of oil markets, the pipeline flow has been reversed to serve either Canada or the U.S. For example, the U.S. has been awash with tight (shale) oil since the current fracking boom. This resulted in the oil producers and pipeline owners reversing the flow, allowing Canadian refineries access to the price-advantaged (read: discounted) WCS crude, but only because U.S. refineries already had enough of what they needed.
Since reversing the Enbridge Line 9 pipeline, Ontario and Quebec (and New Brunswick, via small tanker ships and railway tankers) have been refining cost-advantaged North American crude oil sourced from both the U.S. and Alberta. However, this ability is still somewhat limited by the existing refinery technology and the smaller, in comparison to the U.S., local market requirements. Ontario and Quebec, for example, have many roads and shopping parking lots to pave and maintain. So, heavy crude oil works for them to an extent. Still, the ability to stay flexible and maintain refinery profitability margins demands that they continue to have access to light sweet when it is cheap and abundantly available.
In summary, Atlantic Canada lacks pipeline access to western crude. It meets all their transport requirements through less expensive and timely oil supertankers. At the same time, Ontario and Quebec had relatively easy access to an existing pipeline carrying WCS to the U.S. market. The TransCanada Energy East pipeline was cancelled due to various factors, but the primary reason was economic. It wasn’t cost-effective when oil prices were high, and it would be less profitable when prices were low, but either way, it certainly wasn’t intended to make Canada self-sufficient. Irving wanted to refine WCS to sell to the market south of the border. Irving currently exports 80% of its products to the U.S.
Critical Pipelines
Canada does not have the population or industry to use all the crude oil it produces. Although Canada produces approximately 5 million barrels daily, we only consume 1.5 million barrels domestically. Canada exports roughly 3.5 million barrels daily, with 98% of its crude going to the U.S. markets, primarily via existing pipelines. The answer to our excess capacity lies south of the border in the largest oil-consuming market in the world. Welcome to America. To keep up with its demands, Alberta needs more pipeline export capacity. The Enbridge replacement line and Phase IV of the Keystone XL Pipeline Project are the solutions.
The good news is that the southbound Enbridge Line 3 replacement pipeline with a 760,000 barrels per day southbound capacity has, at least on the Canadian side, been fully completed on schedule. Albertans should realize that the Canadian team finished their side, although the U.S. side did not. Find a way to blame the Canadian Federal Government for that. (Editor note: The U.S. finished their side in Oct 2021.)
That is similar to the dilemma facing the construction of the Keystone XL pipeline to American refineries in Illinois, Oklahoma, and Houston. Their refineries already possess world-class heavy crude high-conversion refinery capabilities and are ready and willing to accept the entire gamut of products that Albertan bitumen crude can provide. The refined products America doesn’t consume can be exported globally via Houston’s port.
The Keystone XL project is well-financed on the American side and fully supported by the Canadian Federal Government. But why do Albertans expect the rest of Canada to finance their projects? The provinces have total control, as enshrined in the constitution, over their resources, including full financial responsibility. Alberta is busy blaming Manitobans and Newfoundlanders for their economic problems, but the ball is in their court.
Presently, the U.S. 2020 markets are saturated with light sweet, tight oil from fracking, biofuels from corn, and light sweet crude from the Gulf of Mexico, Mexico, and Saudi Arabia; therefore, they can quickly meet their immediate demands for high-value petroleum products, such as automobile gasoline. Their preference for Albertan crude has more to do with its low value to the rest of the world. U.S. refineries can buy WCS at a deep discount and convert a higher percentage of it into diesel, home heating oil, or asphalt while retaining their profit margins. In other words, Albertans should forget about making Canada self-sufficient and be intent on continuing to supply a ready and appreciative market: the refineries of Chicago and Houston. The industry needs more pipeline capacity to allow the U.S. refineries access to Canada’s low-value heavy crude.
Albertans should learn a lot more about the reality of the global petroleum industry before blaming the rest of Canada or Trudeau for their perceived grievances. There is no doubt that, without considering the cost of transportation and refining, Canada could be totally self-sufficient by obtaining its oil domestically rather than internationally. Additionally, we can upgrade and refine our essential domestic gasoline and diesel needs. But at what costs?
Who is Supposed to Pay?
Canadian oil is expensive to extract, transport and refine compared to Arabian light sweet. Who will pay to build the additional pipelines and upgrade the Ontario, Quebec, and New Brunswick refineries? Who will pay the price difference between competitive world oil prices and our at-home solution gasoline pump prices when they increase due to higher production and transportation costs? Alberta? Why should all of Canada pay to meet misplaced provincial pride when there is an apparent next-door-neighbour solution?
Once Albertans get past the misleading belief that they are the “rich kids on the block,” that their tax dollars are, god forbid, helping other Canadians, that climate change advocates are the “spooky monster under our beds,” and that the inability to sell their low-value crude to markets that don’t need them is the fault of the Federal Government, they might come to the understanding that they need to consider their children’s future instead of dwelling on their immediate entitled desires.
That means paying their share of provincial personal and business taxes, provincial sales taxes and gas prices, equal to the rest of us in Canada. Considering the profit margins from Alberta’s heavy crude are likely the lowest of any crude oil produced globally, the Alberta Heritage Savings Trust Fund could not be expected to cover all their expenses. As of 2019, Alberta’s debt is over $ 86 billion, while the Heritage Fund is only worth $ 18 billion. When oil prices were high, and they were all working, they should have been willing to spend money to make money instead of expecting the rest of Canada to fund their live-for-today lifestyle. In truth, Alberta will most likely drag the rest of Canada down.
The MacKinnon Panel report clearly shows that years of rapid growth in operating budgets mean the Alberta government now spends 20 percent more per person than other provinces. Had Alberta matched the average spending of Canada’s three largest provinces (Ontario, Quebec, and B.C.), expenditures would have been $10 billion less, and there would now be a $3-billion surplus instead of a $7-billion deficit.
Alberta’s capital spending has also been higher than the rest of the country. Despite all the complaining from some local politicians, municipalities in Alberta have had a sweeter deal than anywhere else in Canada, with capital grants at least 20 percent higher than the national average.
Alberta Budget is Tough but Much Needed Medicine
Albertans should be spending their combined provincial tax earnings and oil on either building, subsidizing or financing pipelines to supply the southern markets that need their heavy crude. The Keystone XL pipeline, in that light, is critical and relevant to all Albertans and Canadians. The American tight oil boom is eventually ending, and Alberta should be ready for it. Until they are willing to put their money where their mouth is, Albertans should stop feeling sorry for themselves and blaming the rest of Canada for their unfortunate situation of holding the world’s third-largest crude oil reserve.
March 31st, 2020 Keystone XL Pipeline Update
CALGARY, Alberta and HOUSTON, March 31, 2020 (GLOBE NEWSWIRE) – News Release – TC Energy Corporation (TSX, NYSE: TRP) (TC Energy or the Company) today announced that it will proceed with construction of the Keystone XL Pipeline Project (the Project), resulting in an investment of approximately US$8.0 billion into the North American economy.
As part of the funding plan, the Government of Alberta has agreed to invest approximately US$1.1 billion as equity in the Project, which substantially covers planned construction costs through the end of 2020. The remaining capital investment of approximately US$6.9 billion is expected to be largely made in 2021 and 2022 and funded through the combination of a US$4.2 billion project level credit facility to be fully guaranteed by the Government of Alberta and a US$2.7 billion investment by TC Energy. [4]
Keystone XL finally gets the go-ahead, after Alberta promises to help foot the bill.
Stepping Up
Congratulations to Alberta for stepping up. Albertans have been busy blaming the Federal Government for everything they won’t do, so this commitment is a baby step forward. However, having the oil flowing south will not fully resolve Alberta’s financial problems or pay off its enormous self-imposed provincial debt if it doesn’t get its house in order. Additionally, although Prime Minister Stephen Harper and later Justin Trudeau’s Liberal government both advocated for the pipeline’s completion, the U.S. is currently in an election year, and no one knows if the next president will approve it. Alberta may be jumping the gun on their US$8.0 billion gamble. But, at least, it is with their own money this time.
Albertans need to realize that, as Canadians, we all share responsibilities, and as the COVID-19 pandemic has revealed, we are all in this together. We each must do our part to have a stable and sustainable economy with publicly funded healthcare and education. So, if you were not born in Alberta or, more specifically, if your little pink bottom wasn’t waddling within the boundaries of the McMurray Formation when you were growing up, what right do you have to be so entitled? The third-largest oil patch in the world may be located within Alberta’s provincial boundary, but living in a briar patch doesn’t mean you are self-sufficient or independent. The truth is just the opposite.
This may be Alberta’s last chance to prevent getting themselves deeper into a sticky mess, stop punching the Tar Baby, and rejoin the rest of us as Canadians, first and foremost.
John S Goulet worked in the oil industry for over 30 years, including Willbros International, an American pipeline company, Chevron Oil on the Star Deep Water Agbami Project, and Shell Oil.
This article was first published in March 2020 but it is still relevant today – March 2025.