1 Boom, Bust, and Consolidation*Corporate Restructuring in the Alberta Oil Sands
Ian Hussey, Éric Pineault, Emma Jackson, and Susan Cake
The Alberta oil sands tend to evoke images of sprawling surface mines worked by giant rope-and-pulley shovels and larger-than-life trucks, extracting and transporting a tarlike substance to immense industrial processing facilities. The oil sands may also conjure up images of tailings ponds and mountains of caustic sand—the by-products of bitumen extraction—and of billowing smokestacks that send greenhouse gases rising into the atmosphere, along with visions of pipelines and trains snaking their way south, east, and west to refining hubs or to ports elsewhere on the continent. Underlying these images, however, is another, more abstract one: that of a massive web of economic power, concentrated in Alberta but linked to policy makers in Ottawa and to central Canadian elites via Bay Street finance. This hegemonic complex, an intricate network of both public and private power, has had an enormous impact on Canadian politics, economics, and society, particularly over the past two decades. It has been able to exert a defining influence in areas as diverse as labour regulations and employment, fiscal policy, interprovincial commerce and international trade, climate and environmental management (including the protection of water resources), funding for scientific research, and relations of the colonial state with Indigenous nations.
The early years of the twenty-first century were dominated by concerns that the world’s supply of oil was running out, which contributed to an upward spiral in oil prices. Over the course of a ten-year commodity boom—prices were high from 2004 to 2014—the oil sands grew into an ever more dominant economic force capable of nourishing and sustaining the hegemonic power of the fossil fuel industry. Then, in the autumn of 2014, oil prices crashed, with a barrel of West Texas Intermediate (WTI) losing nearly half its value in the space of only four months.1 Yet the key corporations that make up this hegemonic complex managed to emerge from the crisis relatively intact, with the oil sands industry ultimately retaining its status as a decisive economic and political force.
The power of the oil sands industry is grounded in the activities of a surprisingly small number of firms: five extractive corporations dominate bitumen production in Canada. Together with two major pipeline companies, these corporations form the core of this hegemonic complex.2 Their strategies of capitalist accumulation are embodied in the fixed capital mentioned above—in the equipment, physical structures, and other tangible property bound up in the flow of bitumen from pit to refinery—as well as in the labour and energy required to mobilize these assets. The accumulation of capital has sustained the hegemonic power of the oil sands as an economic and political force, and this power has in turn been exercised to further the accumulation strategies of the major corporate players in the industry. The “Big Five” are Suncor Energy, Canadian Natural Resources Limited (CNRL), Cenovus Energy, Imperial Oil, and Husky Energy.3
Of course, the oil sands industry is populated by thousands of businesses, of all sizes. In 2011, at the height of the oil sands boom, the extractive portion of the Canadian oil and gas sector comprised 7,051 firms that actually employed staff (counting employee-less shell firms the number goes up to 14,415). Of these firms, 6,537 (93 percent) were small businesses with fewer than fifty employees. Of the remaining 514 firms, 485 were medium-sized businesses with 50 to 499 employees, while only 29 were large corporations with 500 employees or more. Most of these firms (including roughly two-thirds of the small ones) operated in the area of “services to oil and gas extraction,” a category that accounted for 62 percent of the total number of firms with employees. Conventional oil and gas extractors made up another 25 percent of the total number, while 10 percent were oil and gas contract drillers. At that time, firms active in “non-conventional oil extraction” accounted for fewer than 1 percent of the total.4 Yet it is the investment decisions made by this handful of firms—firms engaged in extracting hydrocarbons from unconventional sources such as oil sands and in exploring for new reserves and developing ways to increase extractive capacity—that determine the overall growth trajectory of the industry.
The accumulation strategies of the Big Five must be examined in the context of the commodity cycles that mark the development of extractive capital. Capitalist development is not a linear and progressive process. Accumulation is, by its very nature, cyclical, and commodity-producing industries are subject to some of the wildest economic gyrations. Price volatility is a hallmark of commodity-producing sectors, all the more so given the existence of vast and deeply rooted financial markets where shipments of basic commodities are bought and sold and options on future transactions traded. The price dynamics of commodity extraction and circulation drive an investment cycle that is prone to immense overshoots, which can have dire economic consequences as the value of fixed capital is destroyed during the inevitable downturns. These cyclical dynamics lie behind the recent development of the Canadian oil sands, and an appreciation of their influence is crucial to the analysis presented in this chapter.
We begin by examining the Big Five’s key assets—both financial and organizational—with a view to understanding the nature of their oligopolistic power. The Big Five have, in particular, been developing and implementing their accumulation strategies in an era of “extreme oil,” and we go on to outline the industrial, financial, and ecological relations in which bitumen as a commodity is enmeshed. We then turn to the cyclical dynamics that undergird the Big Five’s accumulation strategies, focusing on the three phases of the most recent commodity cycle—boom (2004–14), bust (2014–16), and restructuring and consolidation (from 2015 onward). This analysis enables us to offer certain projections about the future direction of the extreme oil industry in a world now gripped by climate change.
Mapping the Oligopolistic Core of the Oil Sands Industry
In the period from 1999 to 2016, bitumen’s share of overall oil production in Canada grew by 419 percent, with bitumen (refined and unrefined) accounting in 2016 for roughly 63 percent of the oil produced in the country (Hughes 2018, 55, figure 50)—a figure that had risen to 64 percent by the following year.5 In 2017, Canada’s overall oil production averaged 4.2 million barrels per day (bbl/d), and bitumen accounted for nearly 2.7 million of those barrels.6 The Big Five alone had the potential to produce even more than that amount: their combined capacity for bitumen production stood at 2.86 million bbl/d in 2017 (see table 1.1). This meant that they controlled 79.4 percent of Canada’s total potential capacity for bitumen production, which stood at 3.6 million bbl/d in 2017.7 Beyond control over supply, however, their production capacity also gave them control over an immense amount of wealth.
Number of employees
Bitumen production capacity (bbl/d)
(including 54% stake in Syncrude)b
(including 70% stake in Athabasca Oil Sands Project)
(including 25% stake in Syncrude)
Sources: For assets and net income, FP Infomart; for revenue, data available from Morningstar, Inc.; for market capitalization and ranking, Toronto Stock Exchange (TSX), “Quoted Market Value,” May 31, 2018; for number of employees and production capacity, Excel data underlying JWN Energy’s Oilweek 2018 Top 100: An Uneven Recovery report (prepared by KPMG), June 2018.
a Total revenue refers to total earnings in a given reporting period, prior to the deduction of any expenses. Net income is the amount remaining once all expenses (including the cost of goods sold) have been deducted.
b Early in 2018, Suncor acquired Mocal Energy’s 5 percent share in Syncrude, bringing Suncor’s total Syncrude stake to 58.74 percent (Canadian Press 2018).
In 2017, the Big Five had an aggregate revenue of over $115.2 billion (see table 1.1). Their net income totalled more than $13.7 billion, and the assets they owned were worth in excess of $278.8 billion. (By way of comparison, Alberta’s annual gross domestic product is about $325 billion.) As of May 31, 2018, the Big Five represented 7 percent of the total Quoted Market Value of the Toronto Stock Exchange (TSX), with Suncor, by far the largest of the Big Five, ranking fourth among all the companies listed on the TSX. Its Quoted Market Value was $84 billion, such that Suncor alone represented 3 percent of the TSX total. In 2017, the Big Five’s aggregate gross profit—a measure of their overall spending capacity—stood at nearly $47 billion. In contrast, the Government of Alberta’s total income for 2017 was about $45 billion. The Big Five thus collectively mustered as much spending capacity as the province from which they derive the vast majority of their profits.
In addition to their strategic control of extractive capacity, the Big Five also own a significant proportion of the extractable reserves of oil in Canada (see table 1.2). Bitumen deposits represent 97.4 percent of Canada’s remaining extractable oil reserves (Hughes 2018, 63, figure 57). The Big Five are thus positioned to dominate the future development of Canada’s oil sector. In a very real sense, they are the oil sands.
2017 oil (bbl)
2018 oil (bbl)
2017 gas (MMcf)
2018 gas (MMcf)
Source: Daily Oil Bulletin, Top Operators 2018: Two Steps Forward, One Step Back, 13.
Note: BOE = barrels of oil equivalent; bbl = barrels; MMcf = million cubic feet. A “proved” reserve is one that is considered to be reliably recoverable under current economic and political conditions.
In terms of their ownership of assets, the Big Five are both vertically and horizontally integrated within the fossil fuel industry, and therein lies the basis of their oligopolistic power. Three of the Big Five—Suncor, Imperial, and Husky—are active from pit to pump: extracting bitumen (upstream), upgrading and refining the bitumen, shipping various grades of petroleum products through commercial circuits across North America (midstream), and finally selling directly to consumers and businesses through downstream assets such as branded gas stations (Petro-Canada, Esso, and Husky, respectively). Their vertical integration is thus complete. Although Cenovus and CNRL do not own any downstream assets, they do have significant midstream assets (see table 1.3).
All five firms are horizontally integrated as well, their activities spread across the full spectrum of the fossil fuel sector. In addition to conventional oil and gas extraction, the Big Five are all active in the recovery of “unconventional” fossil fuels, including not only bitumen but also wet natural gas from the Montney Formation (located in northwestern Alberta and northeastern British Columbia).8 Most of the Big Five are also involved in deepwater oil and/or gas extraction, and Suncor has owned wind farms since 2002. All five firms are multinationals with subsidiaries operating in Africa, Europe, and Asia, but, more importantly, all five have significant midstream assets, such as refineries and storage facilities, in the United States.
This complex integration gives these large corporations strategic and operational flexibility: they can use their own products as inputs, they can shift activity from one component of the fossil fuel sector to another according to market conditions, and, through internal costing procedures, they can compensate for losses in one of their business operations with gains in another. This strategy was important during the oil price downturn from 2014 to 2016, where losses in the upstream segment of the integrated producers were offset by strong gains in midstream and downstream segments. Finally, because they are multinationals, and in particular because a significant amount of their activities span the Canada-US border, they also adjust their internal costing in response to foreign exchange and commodity-product spreads in order to mitigate the impact of the price discount for relatively low-quality Canadian crude. In short, they are able to minimize their fiscal exposure.
While integration is critical to the economic power of the Big Five, it is just one aspect of the corporate power at their command. As members of an oligopolistic core, they can exercise their economic power outward, effectively exerting control over the myriad of small and medium-sized service firms that depend on their activities. The Big Five can also combine forces, collaborating on research and technology development and forming partnerships for large-scale projects, as well as lobbying jointly with government regulators and public officials—thus transforming economic power into political power.
Midstream operations / assets
Downstream operations / assets
Foreign operations / assets
Operations / reserves in sectors other than oil sands
Shares principally held by various North American investors
Offshore Norway, offshore UK, Libya, and Syria;b refinery in Colorado (US), with pipeline link to storage facilities in Wyoming
Natural gas, conventional oil, ethanol, wind farms
Shares principally held by various North American investors; 9% Royal Dutch Shell (the Netherlands)
Offshore UK, offshore Côte d’Ivoire, offshore South Africa
Natural gas, conventional oil
Subsidiary of ExxonMobil (US)
Parent firm has foreign assets
Natural gas, conventional oil, asphalt
Majority of shares (70%) owned by Li Ka-Shing (Hong Kong)
Offshore China, offshore Indonesia; Lima Refinery (full owner) and Toledo Refinery (50% stake), both in Ohio (US)c
Asphalt, natural gas, ethanol
Shares principally held by various North American investors; 25% ConocoPhillips (US)
50% stake in Wood River Refinery (Illinois) and in Borger Refinery (Texas) (US)
Natural gas, conventional oil
a Information about ownership is taken from Hulshof et al. (2017).
b In December 2011, Suncor suspended its Syrian operations indefinitely. Its operations in Libya were suspended in June 2011 owing to the political turmoil that culminated in the October assassination of Muammar Gaddafi. Operations subsequently resumed but have remained limited.
c Late in 2017, Husky acquired a third US refinery—the Superior Refinery, in Wisconsin. The following April, a major fire broke out at the refinery, and Husky is now in the process of rebuilding.
The Economic Base for Capital Accumulation: Gross Profit
The capacity of these corporations to expand their power can be analyzed using two variables—gross profit and capital expenditure (capex)—that together shape the contours of their accumulation strategies. Gross profit is a measure of a corporation’s current economic power, and it is the foundation of capital accumulation. It is through gross profit that corporations not only cover their routine expenses but also finance capital expenditures—that is, long-term investments, whether they involve the maintenance or upgrading of existing assets or the acquisition of new ones. The nature of these capital expenditures is the principal signal of the accumulation strategy that a corporation is presently pursuing. In what follows, we examine the first variable, gross profit, before going on, in a subsequent section, to consider capex.
Gross profit is the revenue that remains to a company after direct costs—that is, the cost of goods sold—have been deducted. These are costs, whether of labour, materials, or energy, that can be traced directly to the production and sale of a specific item, such as a barrel of oil. Because these costs are directly linked to production, they will vary with the amount of output. In 2017, the total revenue of the Big Five stood at a little over $115.2 billion (see table 1.4, below), and, overall, direct costs consumed 59.5 percent of this revenue, leaving an aggregate gross profit of $46.7 billion, almost half of which was captured by Suncor. Although, on average, 40.5 percent of the revenue collected by the Big Five was gross profit, this average hides an important disparity. At the top end, Suncor’s gross profit, which stood at roughly $21 billion, represented 65.4 percent of its revenue, while, at the other extreme, a mere 17.5 percent of Imperial’s revenue ended up as gross profit. Yet, even at this low end, Imperial’s gross profit was upwards of $5 billion in 2017.9
It is out of gross profit that corporations then cover their indirect costs, or overhead—that is, what the company must spend simply in order to run its business. In contrast to direct costs, which vary with production output, indirect costs tend to be relatively stable, or fixed. They include routine expenses—such as rent and utilities, office equipment and supplies, and the salaries paid to administrative staff—that cannot be associated directly with the manufacture and sale of a specific product. In the case of the Big Five, indirect costs also include expenses necessary to sustain their oligopolistic power within the industry—in particular, the cost of maintaining large and complex corporate bureaucracies responsible for activities such as information gathering, financial strategizing, research and development, company advertising and public relations, and lobbying. Overhead thus covers the costs of both vertical and horizontal integration: it represents the costs associated with maintaining the full depth and breadth of a corporation’s operations. In 2017, overhead expenses amounted to $13 billion, or roughly 12 percent of the Big Five’s aggregate revenue, $10 billion of which was spent by Suncor alone. Overall, the ratio of overhead to direct costs for the Big Five was 20 percent in 2017, which means that for every dollar spent on direct costs, 20 cents were spent on overhead. But again, this aggregate figure hides a wide disparity, in this case between Suncor, whose ratio is 92 percent, and Cenovus, whose ratio is 3 percent.
It is also out of gross profit that corporations cover financial expenses such as interest on debt, as well as the repayment of loan principal. Debt represents assets that have already been acquired. When the asset in question is a tangible, or material, one (such as a major piece of equipment), which will eventually wear down and need to be upgraded or replaced, the cost of acquiring it is typically spread out its anticipated lifetime of use and, for purposes of accounting, itemized as depreciation. Similarly, loans, as well as expenses related to the acquisition of intangible assets (such as copyrights, trademarks, and other forms of intellectual property), are amortized—that is, paid off in installments.10 These costs are likewise deducted from gross profit.
Table 1.4 presents a breakdown of these expenses for each of the Big Five in 2017. Suncor appears as an outlier, having the highest revenue, the lowest direct costs by far, and thus the largest gross profit. This gross profit sustains a strikingly high level of overhead (which reflects a very top-heavy corporate structure), significant depreciation and amortization expenses, and a high net income (half of which was transferred to shareholders in the form of dividends in 2017). Imperial offers a clear contrast to Suncor, with very high direct costs and a correspondingly modest gross profit, very low overhead and relatively minor depreciation and amortization expenses, and a negligible net income.
Total revenue (millions)
Depreciation and amortization
Total ($) or average (%)
Source: Based on data from Morningstar, Inc.
Finally, gross profit is used to cover taxes and royalty expenses. In 2017, the Big Five paid roughly $1.6 billion in income taxes and another $3.1 billion in royalties to various governments (both in Canada and abroad), for a total of $4.7 billion. After all these expenses have been paid, what remains is net income, otherwise known as the bottom line. A portion of net income is then distributed to shareholders in the form of dividends, as well as through offers of share buybacks—an approach that has several advantages, notably the reduction of the number of shares outstanding, which increases the value of those shares. Whereas taxes and royalties represent a transfer of economic power to the state, dividends and buybacks transform industrial capital into financial capital available to investors and thus represent a shift of economic power from the extractive sector to the financial sector. In 2017, the Big Five returned approximately $4.2 billion to their shareholders in the form of dividends. (Figures for each of the five are provided in table 1.6, below.) They spent about another $2.0 billion of their income buying back shares from the market, meaning that the total transfer of value to shareholders in 2017 approached $6.2 billion.
Once funds have been disbursed to shareholders, the remaining portion of net income is held by a company as “retained earnings”—uncommitted capital that can be invested in the accumulation of assets, both tangible and intangible. For the Big Five, retained earnings amounted to $7.3 billion in 2017. These earnings can be used to expand extractive capacity and thus increase production output, which serves to build economic power, as well as to move into new areas of operation, thereby also enhancing strategic flexibility.
To summarize, in terms of capital accumulation, the higher the gross profit of these corporations, the larger the possible scale of their extractive capacity and the broader the possible scope of their business operations (the two economic foundations of the Big Five’s corporate power). This snapshot of the Big Five’s deployment of gross profit must, however, be complemented by an in-depth analysis of their accumulation strategies over the most recent commodity cycle. As an introduction to the analysis of this commodity cycle, we will begin by examining the nature of the commodities involved—bitumen and its upgraded derivatives—as examples of extreme oil.
The Political Economy of Extreme Oil
Over the past decade or so, concerns about “peak oil”—fears that the supply of oil is running out—have largely waned. As the climate crisis deepens, however, a world dependent on fossil fuels has been confronted with a new problem: oil that can be extracted from known reserves but cannot subsequently be burned. Extractive capitalists have sharpened their knowledge of the location, scope, and nature of these reserves and of possible ways to unlock their value. Yet these reserves consist mainly of unconventional sources of hydrocarbons, notably oil sands and oil shale. Because recovering oil from these sources is far more energy intensive than conventional oil extraction (and hence more expensive), their use increases emissions of greenhouse gases, thereby accelerating climate change. If the Paris Agreement’s 2°C limit to global warming is to be met, some 60 percent to 80 percent of global fossil fuel reserves must therefore remain underground, thereby becoming stranded assets (see Muttitt 2016; Thieroff et al. 2017; see also Hussey and Janzen 2018; Lee 2017).
Reliance on “extreme” oil generates a number of additional problems, foremost among them the need for new, and potentially conflict-ridden, industrial development. Accessing unconventional sources of hydrocarbons entails opening up hitherto undisturbed territories to oil extraction and generally requires the use of very invasive forms of extraction. This puts new pressure on ecosystems and communities and provokes new dispossessions and new environmental conflicts. In addition, the knowledge that the supply of oil is not in jeopardy—that vast reserves of unconventional forms of oil exist—creates a cultural and sociopolitical inertia in industrial societies that rely heavily on hydrocarbon combustion, dampening the collective will for transition away from fossil fuels. Finally, in the era of extreme oil, climate change is no longer a distant possibility but a contemporary fact, one that is creating extreme weather and related natural events, including catastrophic fires and unpredictable floods, which come with enormous social and economic costs.
In economic terms, the oil we burn and the plastic we eventually dispose of or recycle have a specifically capitalist use value. The production of fossils fuels is thus managed so as to maintain a rhythm of hydrocarbon consumption (a burn rate) that serves to enhance the value of extractive capital. Maintaining an optimal flow of production depends not only on the state of world markets for oil, where demand and supply are reflexively managed, but also on the development of infrastructure to support the extractive chain, from frontier to corridor to export gateway. The process whereby this capital is valorized is driven by an imperative of accumulation that attempts to anticipate, manage, and plan the acceleration of the extractive flow. Management and planning are necessary in a context in which the amount of fixed capital is large and the cycle of rotation long, such that investments are slow to yield a return. The valorization process thus generates an elongated temporal frame that both conditions demand and locks in the metabolic future of advanced capitalist societies presently in a state of carbon dependency.
Where extraction assumes a massive form, as it does in western Canada, space is likewise configured by the needs of the extractive commodity chain. The spatial and temporal matrix within which extractive industries operate further engenders an ensemble of economic linkages, in the form of related industries, in a process whereby extractive capital draws other sectors of the economy into its expanding circle of influence. Through these linkages—as well as through the development of a working class harnessed to, and hence allied with, fossil capital—extractivism imprints its logic on state priorities and on an economy vulnerable to reprimarization. Finance capital is also tied into this logic: its own accumulation process comes to depend on the expansion of extractive capital, at the same time that it advances this ongoing development. In a financial sector dominated by institutional investors, entrusted with managing funds on behalf of others, and by state-sponsored savings plans, the logic of extractivism effectively mobilizes a broad segment of society in support of extractive capital accumulation, as pensions and savings become dependent on profits generated by the exploitation of extreme oil (see Pineault 2018).
It is within an era shaped by the political economy of extreme oil that the Big Five’s accumulation strategies unfold. With this context in mind, let us now turn to a consideration of the most recent commodity cycle, which began with a decade-long boom in the fossil fuel industry.
The Commodity Cycle
The second major factor in our analysis of the Big Five’s accumulation strategies is capital expenditure, or capex. A capital expenditure is not an operating expense but rather an investment in the survival and long-term growth of a business. Although such expenditures typically involve the acquisition of tangible assets, they extend to the purchase of intangible assets (such as a licence or copyright) or to funding research and development. These investments may aim to strengthen a company’s core business, by augmenting or improving its existing assets, but they may also represent an entry into new areas of operation (as when a firm engaged in bitumen extraction expands into fracking for natural gas). As the most recent commodity cycle moved from boom to bust to recovery, the Big Five adjusted their accumulation strategies accordingly, and these shifts are reflected in their capex.
From Boom to Bust
Early in 2004, oil prices, which had hovered around US$30 per barrel for many years, began a steady climb, with the price of a barrel of WTI reaching record highs of more than US$130 in June and July 2008. The boom lasted almost unbroken until the autumn of 2014, and as it progressed, the aggregate productive capacity of the Big Five surged. In 2005, the Big Five’s cumulative capacity for the production of bitumen was 1 million bbl/d; by 2009, it stood at about 1.5 million bbl/d, and, by 2015, it had risen to 2.5 million bbl/d.11 As table 1.5 illustrates, this expansion of the extractive capacity of the oil sands was spurred by substantial capital expenditures. Our analysis begins in 2009 because that was year in which Cenovus came to exist, when the Encana Corporation split into an oil company (Cenovus) and a natural gas company (Encana).
Source: Data from Morningstar, Inc. Figures are in nominal dollars.
Over the period from 2009 to 2014, the aggregate capex of the Big Five totalled nearly $146.8 billion, the figure rising to a whopping $195.9 billion by 2017. Suncor and CNRL are the largest producers of bitumen among the Big Five (see table 1.1), and, unsurprisingly, they consistently outspent the others during the period from 2009 to 2017. Newcomer Cenovus had the lowest capex of the five firms, spending roughly $11 billion less over these nine years than the firm with the second-lowest capex, Imperial Oil.
Over the same period, the Big Five paid substantial dividends to their shareholders, as table 1.6 shows. In the aggregate, the Big Five disbursed $31.76 billion in dividends over the nine years, with one-third of this total coming from Suncor. Suncor’s annual dividend total increased substantially every year, even during the downturn. The firm’s consistently large capex throughout this period clearly paid off for shareholders. Similarly, CNRL’s substantial capex over the nine years resulted in dividend payments in 2017 that were more than 500 percent higher than those in 2009. The firm’s dividends grew for the first seven of the nine years and then lost about 40 percent of their value in 2016, before bouncing back in 2017 to match the 2015 total.
Imperial had the smallest nine-year total, although the company’s dividend payments rose each year. For a corporation its size, Husky paid out relatively high dividends until 2016 and 2017, when its dividend payments almost dried up completely—although Husky still had the second-highest nine-year total of the Big Five. Cenovus’s annual dividend payments increased steadily over the first six years but declined significantly in 2015 and then dropped off quite sharply in 2016. The company’s dividend payments bounced back a bit in 2017, but the total was still less than half of what it was in 2015.
Source: Data from Morningstar, Inc. Figures are in nominal dollars.
In short, during the years of the boom, the Big Five flourished financially and were able to focus on expanding their oil sands operations. The growth in production was facilitated in part by the development of so-called in situ methods of extraction that use thermal technologies, such as steam-assisted gravity drainage (SAGD), to extract bitumen from deeply buried deposits. As the consistent growth in their capex indicates, the Big Five all made significant investments in fixed assets during this period, through which they could in turn further their capital accumulation—at least as long as oil prices remained high.
The Immediate Impact of the Downturn
In the autumn of 2014, the price of oil fell by nearly half, with the price of WTI dropping from over US$100 a barrel in August to under US$60 by the end of the year, and the aggregate capex of the Big Five quickly followed suit. Between 2014 and 2015, expenditures dropped by about 40 percent and then decreased a further 25 percent in 2016, before recovering slightly in 2017. The one exception to this trend was Suncor, whose capex fell only slightly (see table 1.5). All the same, the Big Five’s total capex in 2017 was only 50.8 percent of what it was at the spending peak in 2014.
The abrupt downturn in the oil industry had a devastating impact on employment: 2015 was the worst year for job losses in Alberta since the 1982 recession—a year in which a staggering 45,000 jobs were lost in the province. While the loss of 19,600 jobs in 2015 might seem comparatively modest, the total exceeded the 17,000 jobs lost in Alberta as a result of the 2009 global financial crisis (Parkinson 2016). Overall, employment in Alberta’s mining, quarrying, and oil and gas extraction sector declined precipitously, with the number of salaried employees falling by 18.7 percent, from 85,487 in 2014 to 69,516 in 2015. The number of salaried employees working in supporting activities dropped by 38.1 percent, from 34,277 in 2014 to 21,225 in 2015.12
At the same time, there was a slight rise in the number of employees paid by the hour. In mining and oil and gas extraction, numbers increased by 4.6 percent, from 42,730 in 2014 to 44,678 in 2015, and, in support industries, by 2.6 percent, from 33,014 in 2014 to 33,875 in 2015.13 These increases were, however, offset by a steady decline in wages. In the mining, quarrying, and oil and gas extraction sector, the average hourly earnings (including overtime) for employees paid by the hour dropped by 6.5 percent, from $43.42 in 2014 to $40.61 in 2016. Workers in support industries suffered an even larger cut, with the average wage falling by 10.8 percent, from $42.54 in 2014 to $37.95 in 2016. Across Canada, spending on support activities for mining and oil and gas extraction decreased by 38.4 percent from 2014 to 2016, and most of these cuts were in Alberta.14
The Big Five reacted to the downturn in somewhat different ways, although all five companies cut costs. In January 2015, Suncor delayed a planned expansion of its MacKay River project (an in situ mining operation) owing to the decline in prices, and, over the course of the year, the company laid off 12 percent of its workforce (roughly 1,700 employees). It also began using automated trucks at some of its oil sands mines, a technology that could eventually replace some eight hundred drivers. At the same time, as table 1.5 shows, Suncor largely maintained its capex during the bust. The company considered the downturn an opportunity and made several significant investments. As part of a larger strategy to focus on its core assets (including its Petro-Canada stations), Suncor sold its 50 percent share of Pioneer Energy, another gasoline retailer, in September 2014. Then, in July 2015, the company traded two of its six wind farms to TransAlta in exchange for TransAlta’s stake in the Poplar Creek co-generation facility (which provides steam and electricity for oil sands production). Under the terms of the agreement, Suncor will gain full ownership of the Poplar Creek facility in 2030.
Suncor made its biggest move in 2016, however, when it became the majority shareholder in Syncrude, in which the company already held a 12 percent share. In February, in a deal worth a total of $6.6 billion, Suncor purchased Canadian Oil Sands Limited, the owner of a 37 percent share in Syncrude stock. Then, in April, Suncor acquired an additional 5 percent share from Murphy Oil, giving Suncor 54 percent ownership of Syncrude. (Suncor went on, early in 2018, to acquire another 5 percent of Syncrude by a purchase of shares from Mocal Energy.) In a second substantial move, made in September 2016, Suncor—one of two principal partners in the Fort Hills Oil Sands Project—acquired an additional 10 percent from the project’s other major partner, Total E&P Canada, a subsidiary of Paris-based Total SA. Although Total retained roughly a 29 percent share, this purchase gave Suncor nearly a 51 percent share, making it the majority owner of Fort Hills as well.
Unlike Suncor, CNRL substantially reduced capex during the bust (see table 1.5), in addition to cutting $2.4 billion (about 28 percent) from its 2015 budget. As a result, CNRL substantially delayed a planned expansion of its Kirby North Oil Sands Project. The company laid off 5.1 percent of its “permanent” employees in 2015 and 2016, as well as imposing a hiring freeze. It also cut senior managers’ salaries by 10 percent and reduced the pay of other salaried employees, although it chose not to cut the hourly wages of oilfield workers. Like Suncor, however, CNRL saw the downturn as an opportunity, in this case to diversify its assets. In February 2014, CNRL had acquired liquids-rich natural gas assets from Devon Energy, along with six natural gas processing plants and related infrastructure. Between 2014 and 2016, CNRL further acquired about twelve thousand natural gas wells, positioning the company as Canada’s largest natural gas producer, above Encana. In addition, CNRL continued with the expansion of its Horizon Oil Sands Project, with Phase 2B completed in 2016 and Phase 3 in construction.
Imperial Oil slashed its capex in 2015 by more than 40 percent, and in 2017 its total expenditures were more than 80 percent lower than in 2014 (see table 1.5). In March 2014, Imperial—then in the process of expanding two existing oil sands projects and seeking regulatory approval for a third—sold several of its conventional oil assets to Whitecap Resources for $855 million. During the bust, however, the company delayed the development of Phases 3 and 4 of the Kearl Oil Sands Project and, in 2016, sold 497 Esso-branded gas stations to five fuel distributors for $2.8 billion. In the face of ongoing debates about the future of various pipeline proposals, Imperial opted to develop rail infrastructure. Its Edmonton rail terminal began operating in mid-2015, with the capacity to ship up to 210,000 barrels per day.
Husky’s reaction to the oil price decline was likewise to cut its capex by 40 percent, from $5 billion in 2014 to $3 billion in 2015 (see table 1.5), while also reducing administrative expenses by 41 percent, from $156 million in 2014 to $92 million in 2015. Over the course of 2015, Husky also cut 22 percent of its workforce, eliminating about 1,400 jobs. The same year also saw two existing projects come to fruition. In March 2015, Husky’s Sunrise Energy Project, located northeast of Fort McMurray, began bitumen production, and, in May, a heavy oil plant at Rush Lake, Saskatchewan, likewise became operational. Husky’s planned development of its heavy oil assets in western Saskatchewan continued into 2016. At the start of March, its Edam East plant—a thermal facility located about 115 kilometres east of Lloydminster, Alberta—was brought online, soon followed by two more thermal plants in the same area, the Vawn facility (in May) and the Edam West plant (in June). The company soon suffered a setback, however, when, on July 20, approximately 225,000 litres of heavy oil leaked out of a Husky pipeline near Maidstone, Saskatchewan, not far southeast of Lloydminster—much of it ending up in the North Saskatchewan River, where it polluted the drinking water supply of 70,000 people. Quite apart from the damage done to its reputation, Husky was obliged to undertake a clean-up operation and was eventually fined $3.8 million in connection with the spill.
Cenovus reacted to the downturn largely by cost reductions, slashing its capex by about two-thirds in 2015 and 2016 (see table 1.5). In particular, the firm scaled back spending on oil sands projects: it suspended a pilot project at its Grand Rapids facility, put the Christina Lake Phase G expansion on hold, and deferred development at the Telephone Lake project. It also laid off 25 percent of its workforce in 2014 and 2015, as well as cutting costs through a salary freeze and reductions to discretionary spending. All the same, in January 2016, Cenovus and Suncor announced a $100-million investment—$50 million from each over ten years—directed to Vancouver-based Evok Innovations to accelerate the development of “clean” technologies that reduce the environmental costs of oil sands production, including carbon emissions, water consumption and pollution, and the disposal of toxic waste in the form of tailings.
Restructuring and Consolidation
The 2014 downturn was precipitated by a glut in global oil markets, which proved to be prolonged, extending throughout 2015, 2016, and most of 2017. The resulting depression of oil prices altered the investment environment and drove a restructuring of the Alberta oil sands industry. This restructuring saw several global oil giants sell their oil sands assets, with the Big Five subsequently acquiring much of this productive capacity. In May 2015, Total SA, headquartered in France, indefinitely suspended development of the Joslyn North oil sands mine, an $11-billion project in which it partnered with Suncor, in addition to selling 10 percent of its stake in the Fort Hills Oil Sands Project (the share that Suncor acquired). In late 2016, Norway’s Statoil decided to exit the oil sands altogether, selling its assets to the Athabasca Oil Corporation. Early in 2017, Netherlands-based Royal Dutch Shell sold most of its Alberta assets to CNRL (with Shell then acquiring a 9 percent share in CNRL), while the US-based ConocoPhillips sold most of its Canadian assets to Cenovus (with ConocoPhillips then becoming Cenovus’s largest single shareholder, with a 25 percent stake in ownership).
During the downturn, banks and other investors in the United States seized on the decline in Canadian stock prices to buy up shares in both Suncor and CNRL (Hulshof at al. 2017). At the same time, the exodus of global oil giants from direct involvement in the Alberta oil sands (apart from retaining certain stock holdings) coincided with a continuing shift in the North American investment market toward shale oil basins in the United States, another unconventional source of hydrocarbons. In 2016, for example, ExxonMobil, the parent company of Imperial Oil, wrote off 3.5 billion barrels of its oil sands reserves in its annual accounting. Then, in January 2017, the firm announced US$5.6 billion in spending to double its shale oil reserves in the Permian Basin in Texas, thereby adding 3.3 billion barrels to its production capacity. Perhaps ironically, the sudden upsurge in shale oil production and hence in the global oil supply was one of the factors centrally responsible for the decline in oil prices that threatened the financial viability of bitumen production.
Royal Dutch Shell made two major transactions on the heels of the moves by ExxonMobil, one of Shell’s main competitors. In February 2017, Shell purchased the British oil and gas corporation BG Group for £36 billion (roughly US$53 billion) in a move to strengthen its presence in liquefied natural gas (LNG) production and consolidate its portfolio of offshore deepwater wells. In order to reduce its debt, Shell then made its second major transaction—the sale of its oil sands assets to CNRL. Shell’s global strategy bets on LNG and deepwater wells, so it was logical for the firm to divest from the oil sands. Before the sale to CNRL, oil sands holdings represented nearly 43 percent of Shell’s global portfolio of proved oil reserves. So the decision to divest amounted to a major shift in Shell’s strategy.
Back in Alberta, during the prolonged period in which oil prices remained below $60 per barrel, developing new extractive facilities in the oil sands was not economically feasible, although running existing facilities was, as long as firms controlled production costs. This is precisely the strategy that the Big Five adopted. CNRL led the oil sands industry in cost-cutting efforts, reducing its production costs to the low twenty dollars per barrel. Other oil sands majors—including Syncrude (in which Suncor now owns a majority stake)—also reduced their costs, to somewhere between the mid-twenty to low thirty dollars per barrel. The cost reductions came through improvements to technology and the squeezing down of labour costs. As oil prices gradually climbed back up, hovering in the range of $60 to $70 per barrel throughout most of 2018, oil sands majors saw their existing facilities become increasingly profitable assets, generating stable and predictable returns.
In the years immediately following the downturn, the Big Five were all very vocal about what this phase of consolidation meant for the future of the industry. All five downplayed the possibility of any large-scale expansion of productive capacity through new investments in mining or in situ facilities in the near term. There would be an expansion of production, but this would largely be achieved through an increase in the efficiency of current facilities and through realizing the benefits of past investments. The shift from a booming, high-investment, high-growth, high-innovation environment of intensive capital accumulation to a more gradual pattern of accumulation characterized by cost cutting has indeed proved to be permanent (see Hussey 2020). Even before the price war that began in March 2020 precipitated a new crisis, it was clear that many of the jobs lost during the previous downturn would never return.
Conclusion: The Big Five and the Future of Extreme Oil in Alberta
Extreme oil can be defined as hydrocarbons that should have remained in the ground but were driven into the world economy by the capitalist pressure to extract. During the decade-long boom phase of the commodity cycle that began in 2004, unconventional sources of hydrocarbons, including oil sands, were normalized, and northern Alberta became home to the world’s third-largest reserve of oil. In the years from 2008 to 2014, as the price of a barrel of WTI peaked at more than US$130 in the summer of 2008, falling briefly during the global recession only to rise again to over US$100 early in 2012, authorities ranging from state regulators to energy-sector agencies and auditors changed the valuation of oil sands reserves from the status of risky and marginal assets to that of standard exploitable assets. Crucially, as the commodity cycle moved from boom to bust and prices dropped to lows of under US$40 a barrel early in 2015, this process of normalization was not reversed. And when prices slowly began to recover late in 2017, bitumen had survived as an accepted form of crude oil, and the Alberta oil sands had retained their symbolic promise of abundance and future prosperity.
During this process of normalization, an oligopolistic bloc of seven large firms—the Big Five producers plus two pipeline corporations, Enbridge and TransCanada (now TC Energy)—gradually extended their control over the flow that transforms deposits of bitumen into barrels of heavy crude that will eventually become burnable oil. As figure 1.1 illustrates, the capacity to extract bitumen has exploded over the past decade, through massive investments in fixed capital and in research that led to the refinement of in situ extractive technologies, with the pace of this buildup slowing only after 2014. Not only did the Big Five expand their extractive capacity exponentially, but they also consolidated their control over the potential flow of bitumen, marginalizing other corporations in the process.
If the potential output controlled by the Big Five forms the basis of their oligopolistic power over the resource and its capitalist development, the concrete flow of bitumen generates the income that realizes the value locked in the oil sands. Over the commodity cycle, as the boom turned to bust, the Big Five were able to maintain their gross profit, out of which they could continue to repay debt, cover their overhead, and pay out dividends. They did this chiefly by cutting direct production costs. In the case of Suncor, for example, direct costs consumed an average of 54 percent of gross revenue in the years from 2008 to 2015 but fell to 37 percent in 2016 and 2017.
As we have argued, gross profit is the key to accumulation strategies: it is what corporations use to finance past, current, and future investments in fixed capital. Gross profit also provides the economic means by which the Big Five can deploy and reproduce their hegemonic power over the market, the state, and society. The accumulation strategies we have surveyed evolved in reaction to the phases of the commodity cycle. The boom period is characterized by an escalation of extractive capacity, coupled with the development of new, more technologically sophisticated, in situ methods of extraction. The bust and restructuring phases are marked by a wave of concentration of control over the resource base itself and over fixed extractive capital, as well as by the consolidation of ownership and the protection of stock value through share buybacks.
It is this flexibility with regard to accumulation strategies that sustains the hegemonic power of the oil sands industry within the Canadian capitalist landscape. As long as the bitumen flows, it will generate the gross profit that forms the material base of this hegemony. In May 2015, the Alberta New Democratic Party (NDP) came to power with several objectives, including general commitments to improve the province’s climate policies and to review royalty rates for various fossil fuels. However, the boom was already becoming a bust before the 2015 election. In this context, and because of stiffening competition from shale oil producers in the United States, the NDP’s royalty review resulted in the reduction of some rates. Now, with the United Conservative Party firmly ensconced in power, it seems very unlikely that the generous royalty and tax regime that has existed in Alberta since the late 1990s will change significantly in the foreseeable future.
With the Big Five gradually increasing production while squeezing costs and slowing down investment, a significant chunk of Alberta’s (and Canada’s) carbon budget is currently reserved for a slow-growing, environmentally destructive sector with weak fiscal, investment, employment, and innovation benefits. To thrive in the long term, the Big Five, along with the two pipeline companies, will require fiscal, energy, and climate policies that suit their needs. To put it bluntly, their survival rests on their ability to capture and control these policies at both the provincial and federal levels, and that ability rests on a sustained deployment of corporate power.
At a time when other jurisdictions are taking steps to transition away from fossil fuels, Canada’s current policy trajectory would strengthen the country’s ties to oil and gas production over the next three decades. If the oligopolistic bloc that controls fossil fuel production is able to continue steering provincial and federal fiscal, energy, and climate policies, then Canada will not be able to live up to its Paris Agreement obligations, and its professed commitment to the future will be shown to be hollow.
- 1. West Texas Intermediate is a crude oil that is used as a benchmark in oil pricing, particularly in North America. In August 2014, WTI was selling at an average price (in US dollars) of $103.54 a barrel; by December, the price was down to $57.24 a barrel—a drop of about 45 percent. During the more recent crash, in the spring of 2020, the price of WTI fell as low as $11.57 a barrel (on April 21), according to https://oilprice.com/oil-price-charts/ (accessed September 2, 2020), before recovering to roughly $42 a barrel by the end of the summer.
- 2. The two corporations that dominate the pipeline industry in Canada are TC Energy (formerly TransCanada Corporation) and Enbridge. A third company, US-based Kinder Morgan, sold most of its Canadian assets to the Government of Canada in 2018, including the existing Trans Mountain Pipeline (in operation since 1953).
- 3. On January 4, 2021, Cenovus’s takeover of Husky became finalized, reducing the Big Five to four.
- 4. Figures calculated on the basis of data provided in Table 33-10-0025-01 (formerly CANSIM 551-0001), “Businesses by Industry and Employment, December 2011,” Statistics Canada, https://www150.statcan.gc.ca/t1/tbl1/en/tv.action?pid=3310002501&pickMembers%5B0%5D=3.1. The following industry classifications were used in the analysis: “Conventional oil and gas extraction,” “Non-conventional oil extraction,” “Oil and gas contract drilling,” and “Services to oil and gas extraction.”
- 5. In its raw state, bitumen is a thick, tarlike substance that must be partially processed in order to meet pipeline specifications. In some cases, bitumen can be diluted with lighter hydrocarbons to produce a heavy “sour” crude oil (that is, one with a relatively high sulphur content) and then sold directly to high-conversion refineries, which are able to convert it into petroleum products such as gasoline or lubricants. In other cases, however, bitumen must be further upgraded into relatively sweet synthetic crudes before it can be sold to refineries. (Crude oil is considered “sweet” if its sulphur content is less than 0.5 percent.)
- 6. National Energy Board, “2017 Estimated Production of Canadian Crude Oil and Equivalent (b/d),” table now archived by the Canada Energy Regulator, available at https://www.cer-rec.gc.ca/nrg/sttstc/crdlndptrlmprdct/stt/archive/stmtdprdctnrchv-eng.html.
- 7. Calculated from Excel data underlying JWN Energy’s Oilweek 2018 Top 100: An Uneven Recovery report (prepared by KPMG), June 2018. In addition, with a collective capacity for bitumen upgrading of 1.23 million bbl/d, the Big Five controlled almost 96 percent of the total capacity for upgrading.
- 8. Conventional “dry” natural gas is basically methane (although it does contain certain impurities that need to be removed). Natural gas is called “wet” when, in addition to methane, it contains NGLs, or natural gas liquids—that is, hydrocarbons such as butane, propane, and ethane. While these additional ingredients have their own uses, they lower the methane content of the gas. Note also that, properly speaking, “unconventional” refers not to the hydrocarbons themselves but to the context and location in which they occur and, by extension, the methods required for their extraction.
- 9. Here and below, financial data were obtained through Morningstar, Inc.
- 10. Depreciation and amortization are not expenses per se but are rather accounting manoeuvres that serve to spread costs out over a number of years (rather than assigning these costs only to the year in which a purchase was made). Doing so serves to free up a proportion of gross profit each year for other uses, while also allowing for ongoing annual reductions in taxable income.
- 11. Calculated from Excel data underlying JWN Energy’s Oilweek 2018 Top 100 report.
- 12. Table 14-10-0202-01 (formerly CANSIM 281-0024), “Employment by Industry, Annual,” Statistics Canada, https://www150.statcan.gc.ca/t1/tbl1/en/tv.action?pid=1410020201.
- 13. Ibid.
- 14. Table 14-10-0206-01 (formerly CANSIM 281-0030), “Average Hourly Earnings for Employees Paid by the Hour, by Industry, Annual,” Statistics Canada, https://www150.statcan.gc.ca/t1/tbl1/en/tv.action?pid=1410020601.
- Canadian Press. 2018. “Suncor Hikes Its Stake in Syncrude to 58% in $920 Million Deal.” Financial Post, February 18, 2018. https://financialpost.com/commodities/energy/suncor-energy-increases-stake-in-syncrude-acquires-stake-in-fenja-development.
- Hughes, J. David. 2018. Canada’s Energy Outlook: Current Realities and Implications for a Carbon-Constrained Future. Vancouver: Canadian Centre for Policy Alternatives, BC Office. https://www.policyalternatives.ca/energy-outlook.
- Hulshof, Menno, Aaron Bilkoski, Juan Jarrah, Josie Ho, and Jin Yan. 2017. Testing the U.S. Investor ‘Capital Drain’ Thesis. Industry Note, July 20, 2017. Equity Research, TD Securities. Toronto: Toronto-Dominion Bank.
- Hussey, Ian. 2020. The Future of Alberta’s Oil Sands Industry. Edmonton: Parkland Institute. https://www.parklandinstitute.ca/the_future_of_albertas_oil_sands_industry.
- Hussey, Ian, and David W. Janzen. 2018. What the Paris Agreement Means for Alberta’s Oil Sands Majors. Edmonton: Parkland Institute. https://www.parklandinstitute.ca/what_the_paris_agreement_means_for_albertas_oil_sands_majors.
- Lee, Marc. 2017. Extracted Carbon: Re-examining Canada’s Contribution to Climate Change Through Fossil Fuel Exports. Vancouver: Corporate Mapping Project. https://www.corporatemapping.ca/extracted-carbon-re-examining-canadas-contribution-to-climate-change-through-fossil-fuel-exports/.
- Muttitt, Greg. 2016. The Sky’s Limit: Why the Paris Climate Goals Require a Managed Decline of Fossil Fuel Production. Washington, DC: Oil Change International. http://priceofoil.org/content/uploads/2016/09/OCI_the_skys_limit_2016_FINAL_2.pdf.
- Parkinson, David. 2016. “Alberta Endures Most Annual Job Losses Since Early 1980s Recession.” Globe and Mail, January 26, 2016. https://www.theglobeandmail.com/report-on-business/economy/jobs/alberta-job-losses-last-year-worst-since-early-1980s-recession-statscan/article28393681/.
- Pineault, Éric. 2018. “The Capitalist Pressure to Extract: The Ecological and Political Economy of Extreme Oil in Canada.” Studies in Political Economy 99, no. 2: 130–50. https://doi.org/10.1080/07078552.2018.1492063.
- Thieroff, John, Rebecca Greenberg, Steven Wood, Brian Cahill, Vikas Halan, and Elena Nadtotchi. 2017. Oil and Gas Industry Faces Significant Credit Risks from Carbon Transition. New York City: Moody’s Investor Service. https://www.divestinvest.org/wp-content/uploads/2017/09/Moodys.April2017.Oil-and-Gas-Industry-Faces-Significant-Credit-Risks-from-Carbon-transition.pdf.
- * This chapter was first published as a Corporate Mapping Project report (Edmonton: Parkland Institute; Vancouver: Canadian Centre for Policy Alternatives, BC Office, 2018). It is reprinted here, in somewhat revised form, by permission of the publishers.