Alberta Needs the Keystone XL Pipeline – But Not for the Reasons You Think!
A friend on Facebook asked a legitimate question.
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.
The truth is out there if anyone is willing to do a bit of research, 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 choose a critical set of keywords and conducted 568 Google searches.
As a result of those searches, I found, selected and read over 50 relevant online oil industry articles, 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 their crude from Alberta. Read on, follow the sources and make up your own mind. Then let me know if it’s all so simple.
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 how supply and demand works 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 look at the entire world-wide petroleum production process, including what determines pricing for our coveted gasoline that powers the jacked-up four-wheel-drive pickup trucks we love to peel around in.
To start with, although crude is “upstream” of refineries and gasoline is “downstream” of refineries; obviously, the price of crude oil directly affects the price of petrol. In this cost analysis, we are mainly concerned with the different factors that affect the upstream costs of petroleum production. This can be simplified into three major factors. 1. Cost of extraction. 2. Cost of transportation. 3. Cost of refining.
Getting Good Grades
Before we get into costs, however, we must understand how different types of crude are graded. The cost factors are profoundly affected by the specifications or qualities (known as “grades”) of the crude oil. Unfortunately, 145 million years ago, during the Cretaceous period, there were no quality controls. Thus, not all crude oil was created equal.
Although there are literally hundreds of different grades, I find that 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 gasolines.
Sweet (clean) crude is high value because it is low on 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 have impurities, such as sulphur, which are expensive to separate and add significantly to the environmental costs in both extraction and refinement. Light sour, therefore, is less valuable than light sweet but more valuable than heavy. There is no grade for heavy sweet.
1. Cost of Extraction
The total cost of extraction depends on where the crude oil is found (geography, topography and depth) and the grade (viscosity and quality). Where the oil is located makes it easier or harder 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 of heating or diluting to make it flow. The deeper the oil is located usually the more difficult it is to extract, but some shallow crude may be more expensive to extract because the process 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) is easier to access than offshore (ocean), and shallow drilling is less technical and labour intensive than deep drilling. Although several countries have Offshore shallow heavy, no one has figured out how to tap it economically, leaving Onshore shallow heavy, such as found in the Athabascan 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 reason that the Athabascan Oil Sands are an exception to-the-rule is because of 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. Once the high value light sweet crude begins pumping, however, the risk-adjusted return on the initial investment gets paid off quickly to a break-even point after that which the field starts to make a profit. With world price fluctuations, the gains may go up or down, but each new barrel of oil produced will be profitable down to a meagre daily production cost.
Onshore shallow heavy infrastructure and extraction costs of oil sands are spread out over the entire production period, so profits (within the same price spread comparison) depend entirely on day-to-day production and the current market crude prices. Since heavy crude is low value, to begin with, and because of 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 producers would have no economic reason for continuing extraction.
There are many countries exporting crude, but Canadian refineries only buy from a 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 the most profitable “known reserves” of oil that each country produces.
The Athabasca Oil Sands is the only place where oil companies have found methods to make extraction cost-effective for Onshore shallow heavy using both in situ (drilling) and surface excavation (mining) methods.
2. Cost of Transportation
The total cost of transportation depends on if the crude oil can be cost-effectively shipped to a refinery. The heavier (more viscous) the oil, the more difficult and costly it is to ship via either 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 the cold winters. Plus, heavy crude is corrosive, and so pipelines and transfer (pumping) stations need to be corrosion resistant, adding to 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 via supertankers is the least expensive, while long-distance trucking or railway tankers over mountains is the most costly. Pipelines are the least expensive (and environmentally safest) means to transport crude 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 in the cost to “prepare” the crude to be transported. Heavy crude extracted from the oil sands must be steamed, heated, made 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 it can be 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 of 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 called synthetic crude oil (SCO) or Syncrude.
The upgrading refineries must be nearby the original source of the bitumen crude to keep the initial transportation cost from being prohibitive. Only after upgrading can the crude be shipped via tanker trucks, railway tankers or pipelines to the refineries that will turn the crude into usable high-value petroleum products.
Another marketable Albertan crude blend called Dilbit is relatively clean bitumen extracted in situ using more 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 maximizing yields of high-value products such as automobile gasoline. Light sweet crude has less impurities or sulphur, and 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 and produces 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 for the highly specialized “high-conversion” refineries that can process heavy crude is that they can have the flexibility to produce a higher percentage of low-value heating fuel oils, diesel and asphalt to satisfy the market demands. Typically during processing, the final residuum, asphalt base, is reduced to a minimum simply because it is the least valuable product unless, of course, your market needs new roads, then the asphalt base can be maximized.
These high-conversion refineries can also make gasoline, but they have the option to balance out the comparative margins between different grades. Originally, because these highly flexible high-conversion refineries were so expensive to build and operate, there were very few in North America. Over the past 10 years, however, many of the U.S. Gulf Coast and Midwest refineries have been modified. They all need heavy crude to continue operating, and for their needs, Albertan Dilbit and WCS crude fits the bill. 1.
Ok, so what has this got 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 buy oil from Saudi Arabia or anyone else. Albertans seem to think federal “taxpayers,” including themselves, are buying the oil, and “others” are reaping the benefits. That is simply nonsense. Private or publicly traded refineries buy crude oil either directly from the producers or through brokers, traders or distributors. Most of the refineries (and upgrading facilities) in Canada are owned and operated by the vertically integrated big oil companies, such as Imperial, Suncor, and Shell. Irving Oil in New Brunswick, for example, buys and refines crude oil overseas to supply gasoline, diesel and heating fuel throughout the maritime provinces and the American north-east.
The Canadian Federal Government negotiates international trade agreements that allow for both importation of overseas crude oil and exportation of Canadian crude oil. Thus, the Feds can control who the refineries buy from, but that is more often determined by external forces such as U.S. embargoes or warzone restrictions.
Whereas Canada is a federation of provinces and territories, the federal government also brokers right-of-way for trans-provincial pipelines over Crown lands (including indigenous reservations). More importantly, they can, if necessary, apply eminent domain to gain access to privately owned properties where economic benefits to the country take precedence. There are various ways that the Federal Government can step in to protect the interests of all Canadians, but, historically, the government only steps in during emergencies or bottleneck situations to keep the economy rolling.
In 1956 the Liberal government of Canada forced a bill through parliament contributing finances to build a TransCanada pipeline to connect Alberta natural gas with the highly populated eastern markets of Ontario and Quebec. In 1973, as another example, the Liberal Prime Minister of Canada incorporated a Crown corporation, Petro-Canada, to invest federal tax money into developing the Athabascan 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 needed 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 did this in the late 1970s to support Alberta by artificially shoring up the cost of Alberta’s crude, but relaxed this measure in 1980 when Syncrude production increased to the point of being competitive in the world market. Thus, both crude and refined petroleum products are dependant on the international supply and demand market. That takes us back to the Albertan’s question. Why are we buying crude from Saudi Arabia?
There is no doubt that Alberta has the largest crude oil reserves, the most significant oil production and the most productive oil companies in Canada. Alberta has 39% of the conventional oil reserves of Canada, but up to 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. The oil sands crude, however, is a different story.
Tar Baby and the Tar Sands
The Athabascan Oil Sands was initially known as the “tar” sands, but since tar is a man-made product, 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 it, and the worse the problem got.
To be politically correct, Alberta decided to officially name their massive deposits, “Athabascan Oil Sands.” That was not technically correct either because the sands are saturated with bitumen and 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 because it produces a smaller percentage of the precious products such as gasoline and jet fuel. The U.S., however, loves Alberta “bitumen” because, for one reason, they have 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 main reason the U.S. buys Alberta crude oil is that it is cheap but also because they can sell the residual asphalt to pave U.S Interstate highways and Walmart parking lots. So to specific markets, Alberta’s bitumen has value.
In the examples I gave for determining the value of crude oil, I listed three main factors: cost of extraction, cost of transportation and cost of refining. As I mentioned earlier, there are several other factors. The overall production rate and marketability of the crude 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 is a way for markets to determine world prices for crude oil from different 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. WTI and Brent’s price spread is a derivative of geography, whereas Brent oil producers have easy access to shipping ports while WTI is mostly landlocked within the central continental U.S.
WCS, on the other hand, is “discounted” in comparison with 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 (light sweet) being cheap to refine, and WCS is a low value being expensive to refine while producing a lot less of the high-value products per barrel.
The benchmarked price of WCS also includes a deduction for transportation, including the cost of adding the diluent to make the heavy crude flow in the pipeline, and the service cost of using pipelines. The final benchmark price is called the “bitumen netback.” Thus, the benchmarked price spread between Brent and WTI is significant because of access to markets making Brent more valued while 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 deep discount for an excellent reason.
Thus, benchmarking considers marketability 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 bitumen. The oil sands basin is also domestically landlocked with four thousand eight hundred kilometres in one direction, and extensive sets of mountains ranges in the other direction between the fields and the export ports. That is what modern Alberta inherited, and there is nothing they can do about it.
Production and World Markets
Production rates, however, add in a somewhat controllable variable. Oil producers, such as Saudi Arabia, with vast reserves and a high production capacity, can raise or lower their output at will, thereby increasing or decreasing supply in an attempt to win or control markets. But because so many non-producing countries depend on Saudi Arabian exports, their production rate has a strong effect on oil crude pricing. Canada has the third-largest reserves in the world and the fifth-largest producer, but because they only export to the U.S., their production has little impact on the world crude prices.
The final market price of any shipment of crude oil, therefore, is heavily dependant on both the current day-to-day demand and the world supply variances. In other words, if a distributor or refinery needs crude, they will buy from whoever can supply what they need at the lowest prices. If a West African or Arab Spring coup disrupts a refiner’s supply, they will switch. Alternatively, if prices drop drastically, they don’t want to be locked into any long-term contract. Thus, the crude oil buyers, specifically the 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 that is already loaded and on route to somewhere. If you are willing to pay the price, the ship will be rerouted to your port. In other words, refineries need to be flexible. That includes those who could possibly make use of 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 Africa 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 marketing and distribution access to the entire eastern seaboard of Canada and the northeastern states of American without a lot of competition. 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 this enviable position building and operating the largest oil refinery in Canada. The Irving Oil refinery, however, started business in the 1960s when Albertan crude was not an option. They had access to light sweet crude from multiple different sources and built their refinery to make the best 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, Irving Oil Refinery has a production crude capacity of 320,000 barrels per day. To stay productive, the refinery is supplied by over 100 supertankers a year to their own deep-water terminal facility in St John as well as regular rail tanker deliveries to their back door. Irving additionally ensures their access to downstream world markets by chartering and operating their private flagship petroleum tankers, thus keeping handling, transportation and shipping costs and delays to a minimum.
Quebec and Ontario Markets
Quebec and Ontario refineries are in a slightly different category based on geography, specifically, proximity to large population centers (markets) and existing pipelines. The refineries in these provinces also started by refining cheap Arab oil in the 1970s, so their original refineries were built for light sweet crude that they could quickly get through 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 pushed through a pipeline, to supplement the existing railway tankers, to supply oil to the Ontario and Quebec refineries from Alberta to make Canada less dependant 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, but mostly because the pipeline also gave oil producers easy and direct access to the very lucrative U.S. markets.
Since the pipeline was built, however, Albertan oil has not always been flowing north through those pipelines. For a lot of different reasons, mostly to do with supply and demand of the world oil markets, the pipeline flow has been reversed to either serve Canada or the U.S. For example, during the current fracking boom, the U.S. is awash with tight (shale) oil. This resulted in the oil producers and pipeline owners reversing the flow, allowing the Canadian refineries access to the price advantaged (read “discounted”) WCS crude, but only because the U.S. refineries already had enough of what they needed.
Since the reversal of the Enbridge Line 9 pipeline, both Ontario and Quebec (and New Brunswick via small tanker ships and railway tankers) have been refining cost-advantaged North American (meaning both U.S. and Albertan) crude oil but that ability is still somewhat limited by the existing technology of the refinery and the smaller (in comparison to the U.S.) local market requirements. Ontario and Quebec, for example, have lots of roads and shopping parking lots to pave and maintain. So heavy crude 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 does not have pipeline access to the 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. Cancelling the TransCanada Energy East pipeline was blamed on many different things, but the real reason was economics. It wasn’t cost-effective when oil prices were high, and it would be less profitable when prices are 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.
The good news is that both the southbound Enbridge Line 3 replacement and the Keystone XL lines have been approved. In fact, the Enbridge Line 3 Replacement pipeline with a 760,000 barrels per day southbound capacity has, at least on the Canadian side, has been fully completed on schedule. Albertans should realize that the Canadian team finished their side, although the U.S side has not. Find a way to blame the Canadian Federal Government for that.
That is a similar situation for the building of the Keystone XL pipeline to the American refineries in Illinois, Oklahoma and Houston. Their refineries already have world-class heavy crude high-conversion refinery capabilities and ready and willing markets for the entire gamut of products that the Albertan bitumen crude can provide. The 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, enshrined in the constitution, over their resources, including full financial responsibly as well. Alberta is busy blaming Manitobans and Newfoundlanders for their financial 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 and, therefore, can quickly meet their immediate demands for high-value petroleum products such as automobile gasolines. Their preference for Albertan crude is more to do with the fact that it is of low value for the rest of the world. The U.S. refineries can buy WCS at a deep discount and convert a higher percentage of it into diesel or asphalt while retaining the 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. To do this, the industry needs more pipeline capacity to allow the U.S. refineries access to Canada’s heavy crude.
My point is that Albertans should learn a bit more about the reality of the global petroleum industry before blaming the rest of Canada for their perceived grievances. There is no doubt that, without considering the cost of transportation and refineries, Canada could be totally self-sufficient by getting their oil domestically rather than internationally. Additionally, we have the upgrading and refining capability to meet 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 is going to pay for building the additional pipelines, upgrading the Ontario, Quebec and New Brunswick refineries? Who is going to pay for the price difference between competitive world oil prices and our at-home-solution gasoline pump prices when it jumps up according to increased production and transportation costs? Alberta? Why should all of Canada pay just to meet misplaced national or 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 just 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 that the profit margins from Albertan heavy crude are most likely the lowest of any crude oil produced in the world, the Alberta Heritage Savings Trust Fund could not be expected to pay for all their spending. As of 2019 Alberta’s debt is over 86 billion dollars when 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, it is most likely Alberta that will drag the rest of Canada down with it.
The MacKinnon Panel report is clear that years of rapid growth in operating budgets means the Alberta government now spends 20 per cent more per person than other provinces. In fact, had Alberta simply matched the average spending of Canada’s three largest provinces (Ontario, Quebec and B.C.), expenditures would be $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 per cent higher than the national average.https://calgaryherald.com/opinion/columnists/opinion-alberta-budget-is-tough-but-much-needed-medicine/
Albertans should be spending their combined provincial tax earnings and oil on either building or 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 as well as all Canadians. The American tight oil boom is coming to an end, and Alberta should be ready for it. Until they are willing to put their money where their mouth is, Albertans should quit feeling so sorry for themselves and stop blaming the rest of Canada for their unfortunate situation of holding the third largest reserve of crude oil in the entire world.
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
Congratulations to Alberta for stepping up. Albertans have been busy blaming the Federal Government for everything that they won’t do themselves, so this commitment changes some of that. Having the oil flowing south, however, will not fully resolve Alberta’s financial problems or pay off their enormous self-imposed provincial debt if they don’t get their house in order.
Albertans need to realize that as Canadians, we all have responsibilities, and as this COVID-19 pandemic reveals, we are all in this together. To have a stable and sustainable economy with publicly funded health care and education, we each need to do our share. 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, then 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. In fact, the truth is just the opposite. This may be Alberta’s last chance to stop punching the Tar-Baby and rejoin the rest of us as Canadians first and foremost.
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