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Restructuring in Alberta’s oil industry

Internationals pull out, domestic majors double down

Last month, Shell and ConocoPhillips became the latest global oil giants to pull back from the Alberta oil sands. On March 9, Royal Dutch Shell (Shell Canada’s parent company) sold most of its Alberta assets to Canadian Natural Resources Limited (CNRL), Canada’s largest hydrocarbon corporation by volume of production. On March 29, US-based ConocoPhillips sold its Canadian assets to Cenovus Energy, another top Canadian oil producer.

These sales follow on ExxonMobil’s massive write-down of its oil sands reserves a few weeks earlier, the decision in December 2016 by Norway’s Statoil to exit the oil sands altogether, and the sale of major assets by France’s Total in 2015.

Exactly what this shift means for the future of the oil and gas industry in Alberta—and Canada more generally—has been the subject of much speculation, including claims that Alberta's new climate policies are to blame. Instead, we should understand the recent large purchases by CNRL and Cenovus as part of an ongoing restructuring of the oil industry, both here in Canada and at a global level.

Supply glut, low prices drive restructuring

Taking a step back from specific business transactions, it is clear that what’s currently driving oil industry restructuring is (unfortunately) not climate policies, but rather a prolonged glut in global oil markets and the resulting lower-price environment that is likely to remain over the medium term.

The global oil glut, which is keeping prices in the $45–60 per barrel range, is caused by complex global economic dynamics, including competition between Russia, Iraq, and Iran for market share; the growing incapacity of Saudi Arabia to manage global oil supply levels through OPEC; and—most importantly for Canada—the rise of shale oil, a competing form of unconventional hydrocarbons.

The new price context is forcing major oil corporations, both here in Canada and globally, to review their strategies. The status and value of oil sands assets—both extractive facilities and reserves—are being revised in the process.

Alberta oil sands vs. US shale oil

It is important to remember that the global rush towards oil sands assets was in the context of the sustained rise of oil prices in the first decade of the 21st century and an underlying concern that we had entered a world where conventional oil and gas supply had nearly peaked while demand continued to grow. This ushered in a race to exploit unconventional oil and gas deposits. In this context, the Alberta oil sands were considered to be the largest reserve of extractable unconventional oil in the world.

That was before fracking technologies, developed in the US to extract shale gas, were applied to known shale oil basins. The Bakken oil fields, and the much-larger Permian oil fields in northern Texas, have changed the status of oil sands as the de facto alternative to peaking conventional oil here in North America.

Shale oil and oil sands extraction couldn't be more opposed. With shale oil you have relatively cheap drilling and well setup costs combined with very short and unpredictable well life cycles, which forces producers to continuously drill new wells to keep production volumes at economically viable levels. In the oil sands you have very expensive initial costs, but long-term predictable extraction volumes and known and controllable production costs.

Shale oil extractors can easily adapt to sudden shifts in demand, rapidly expanding their production by increasing the number of wells drilled, but the constant renewal of wells means that available cash must be plowed back into drilling. Oil sands producers, in contrast, can generate profits by operating existing developed assets. These profits can then accumulate as retained earnings to the corporations and their shareholders.

Canadian majors bet on profitability of existing Alberta oil sands operations

All of this means that with oil prices in the range of $45–60 a barrel it is economical to expand and develop new shale oil production in North America, but it isn't economical to develop new extractive facilities in the oil sands. However, in this price range it is economical to run existing facilities in Alberta—as long as firms can control production costs.

This is precisely the strategy that domestic oil sands majors like CNRL, Suncor, and Cenovus are betting on. CNRL leads the oil sands industry in cost-cutting efforts. CNRL projects its production costs will be down to $20 per barrel by the end of 2017. Other domestic majors have reduced their costs to range from the high-$20s to low-$30s per barrel; this includes Syncrude, which Suncor now owns a majority stake in.

Oil sands majors could see their existing facilities become cash cows, generating low but stable and predictable returns. But as the North American investment boom in unconventionals moves south towards shale oil basins in the US, Alberta’s oil sands are going through a phase of consolidation and restructuring, with firms rethinking their strategy and role in the global economic relations of the oil industry. The exodus of global oil giants like Shell, ConocoPhillips, Statoil, and others must thus be examined in this context.

Global majors rethink their strategies

Royal Dutch Shell bought BG Group on February 15, 2017 for US$49 billion in a move to strengthen its presence in Liquefied Natural Gas (LNG) production and consolidate its portfolio of offshore deepwater wells. After that purchase Shell needed to offload some of its other assets, leading to last month's Shell/CNRL deal.

Divesting from oil sands was one move in a larger global strategy for Shell, through which it is trying to reduce its debt and remain competitive with ExxonMobil in the ultra-major league of global hydrocarbon production. ExxonMobil’s strength is in unconventionals, shale in particular, and Shell’s is in LNG and deepwater wells. Both companies are forecast to produce 4.3 million barrels per day in 2020. 

It was thus logical for Shell to move away from an asset base that was no longer a part of its new strategy. Before the Shell/CNRL transaction, oil sands represented nearly 43% of Shell's global portfolio of proven developed and non-developed oil reserves, so this represents a major change in Shell's strategy.

The move by Shell came on the heels of a major revision in February by ExxonMobil of the status of its proven and recoverable oil sands reserves, which in accounting terms have been written off. This means that ExxonMobil doesn’t plan on extracting an estimated 3.5 billion barrels from the oil sands in the near future. On the other hand, ExxonMobil announced spending US$5.6 billion in January to double its shale oil reserves in the Permian basin in Texas by adding 3.3 billion barrels.

Canadianization, consolidation, and cost-cutting

While global oil corporations are moving towards more economical sources of hydrocarbons in the ongoing $45–60 price environment, the oil sands are growing through a process of consolidation. This consolidation is marked by the dual characteristics of Canadianization and concentration of assets and productive capacity among the top five firms: CNRL, Suncor, Cenovus, Imperial, and Husky.

According to data compiled by energy sector observer JWN, after the latest wave of buyouts, divestments and write-offs, Canadian firms own 81% of total oil sands production volume. However, this claim of four-fifths Canadian ownership is misleading. While the five biggest domestic producers are all publicly traded on the Toronto Stock Exchange, Imperial is a subsidiary of US oil giant ExxonMobil, and the majority owner of Husky is Hong Kong billionaire Li Ka-Shing. A more accurate statement than JWN’s claim is that the Canadianization of the oil sands is mostly limited to asset purchases in the last two years by CNRL, Suncor, and Cenovus.

The five biggest domestic producers have all been very vocal on what this phase of consolidation means for the future of the industry. All five downplay the possibility of large-scale expansion of productive capacity through investment in either new mining or new in situ facilities in the near term. There will be expansion of production, but largely through increased efficiency of current facilities and because of past investments. All five domestic producers are now focusing on cost reduction through better use of technology and by squeezing down labour costs.

After the boom, after the bust, the oil sands may now be headed toward a period of normalized slow growth typical of other mature extractive industries. But what does this new context mean for the political economy of the oil sands industry in Alberta and in Canada?

The switch from a booming, high-investment, high-growth, high-innovation context of intensive capital accumulation to a more normal, slowed pattern of accumulation characterized by cost-cutting will have important implications for employment and economic growth in other sectors of Alberta’s and Canada’s economies.

Even during the boom years, the oil sands were not responsible for as much employment as some claimed. In 2006, at the height of the boom, the mining and oil and gas extraction industry accounted for just 6.7% of Alberta’s total employment. But the oil sands were still a determining force in Canadian and most especially western Canadian labour markets. This force has declined in the last two years, and for the moment no other sector seems poised to pick up the slack. Cost-cutting and consolidation might also translate into intensified pressure on wage levels, and lead to growing confrontations with labour in Alberta.

What happens next?

Oil sector investment grew during the boom to 20% of gross fixed capital formation in Canada. This high level of investment in the oil sands contrasted with the moribund growth rates in other industrial and manufacturing sectors in Canada. Precisely what the normalization of slow growth in the oil sands means for the overall dynamism of the Albertan and Canadian economies remains to be seen.

The Alberta NDP came to power with several objectives; among them were 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 and, in this context and because of stiffening competition from shale oil producers in the US, the NDP’s royalty review resulted in some rates being reduced. If the current low oil price levels become the new normal for the industry, it seems the generous royalty and tax regime that has existed in Alberta since the late 1990s is unlikely to be significantly changed any time soon.

The same can be said for the oil sands emissions cap, which allows emissions to grow to 100 Mt per year—a 47.5% increase in production over 2014 levels. If companies increase production while squeezing costs and slowing down investment, it also means that a significant chunk of Alberta’s (and Canada’s) carbon budget will be reserved for a slow-growing, cost-cutting sector with weak fiscal, investment, employment, and innovation benefits.

The future development of the oil sands industry is now controlled by an oligopolistic bloc of eight large firms: the big five producers (two of which are controlled by international capital) plus pipeline corporations Enbridge, TransCanada, and Kinder Morgan Canada (a subsidiary of a US firm). To thrive in the long term, these companies will require fiscal, energy, and climate policies to meet 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.

The increasing-but-not-total Canadianization of the sector also means that it is now to a greater extent funded and controlled by Canadian capital, enmeshed in financial relations with Canadian banks and institutional investors, and tied to the savings of everyday Canadians through pension funds, mutual funds, and insurance companies.

If the oligopolistic bloc of eight corporations is able to continue to steer provincial and federal fiscal, energy, and climate policies, then Canada will not be able to live up to our Paris Climate Agreement obligations. In the next three decades, this policy trajectory would strengthen Canada’s ties to oil and gas production during a period in which other countries are undergoing a deep transition away from hydrocarbons.

Photo credit: Pembina Institute under a Creative Commons licence

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