The Roller Coaster
From Stability to Chaos
From its earliest days the oil industry in both the United States and Canada had been plagued by boom and bust cycles, with crude prices escalating from $1 to $10 per barrel and back again within a matter of months. Rockefeller made price stability a major objective for his strategy of integration and amalgamation, which was attained by the 1880s, but the challenges persisted through more than half a century. The discovery of large oil fields in the early twentieth century in Texas, Mexico, Russia, Persia, and the Dutch East Indies brought new competitors onto the scene, and the forced breakup of the Standard Oil Trust exacerbated the situation. Each new discovery attracted hordes of enterprising wildcatters, reproducing the cycles that had roiled the oil fields of Pennsylvania and Petrolia.
The 1920s–30s witnessed the biggest finds yet in Oklahoma and Texas. The effort of the large international companies to impose price stability through the “As Is” cartel arrangement in 1928 was undermined by these developments. The Texas Railroad Commission, backed up by the US federal government in the depths of the Great Depression, established some degree of price stability. Because the oil output of the Texas fields was so large, accounting for almost half the world’s crude production, the system imposed by the state regulatory commission in effect achieved a degree of predictability in oil prices that Rockefeller would have appreciated. After the Second World War, the measures of the “As Is” cartel (dubbed the “Seven Sisters”) and the Texas Railroad Commission resulted in an unprecedented period of price stability that lasted until the early 1970s, absorbing and coordinating the growth of large new producers in the Middle East, Venezuela, and Canada.1
This period also saw the dramatic growth of petroleum consumption, with the vast expansion of the auto industry, accompanied by increased use of oil for residential heating, electrical power generation, and as a feedstock for petrochemicals. Escalating market demand also lured more entrepreneurs into the industry, not just into the search for new sources but also into refining and marketing. The appearance of new would-be players on the scene provided bargaining leverage to political leaders in the countries graced with the resource base, particularly those in the “concession states” of the Middle East who controlled access to these oil riches and increasingly felt that the big companies were retaining the lion’s share of the revenues.2
Tensions between the producing countries and the international oil companies grew in the 1960s. The “official” crude oil prices, which determined tax sharing and royalty payments to the producing states, hovered around $1.00/bbl. (USD). But the entry of oil from the Soviet Union affected actual market costs for refiners. The oil majors, particularly Jersey Standard, believed that the gap between the official and market costs of crude placed them at a disadvantage with independent refiners, particularly the Italian company ENI. To offset that problem, the big oil companies unilaterally reduced the official crude oil price in 1959. This move led to the creation of an alliance of the producer states, led by Venezuela and Saudi Arabia and called the Organization of Petroleum Exporting Countries (OPEC), a year later.
For much of the following decade the oil majors regarded OPEC as a “paper tiger.” A test of this view came during the Arab-Israeli war of 1967 when the Arab member states of OPEC sought to embargo the shipment of oil to countries such as the US that were perceived as supporting Israel. The failure of that effort appeared to demonstrate that OPEC was an inherently unstable cartel of countries with wildly different objectives. But by 1970–71 the situation was changing dramatically. Despite the Prudhoe Bay discoveries the United States had become a net importer of petroleum, while demand in Western Europe and Japan provided increasing leverage to the OPEC states. In 1971 Jersey Standard found itself in an awkward position in Libya, where it had made substantial investments, forced to accept concessions to the new ruler of that country—Muammar Qadaffi—that resulted in a wider price rise from $1 to $2/bbl. (USD).
Two years later emboldened members of OPEC met in Vienna and proposed to more than double the posted price of their oil exports, based on the value of Saudi Arabian light crude, to $5/bbl. (USD). In the midst of their deliberations another Arab-Israeli war erupted, and the Arab oil states once again agreed to cut production and mount an embargo against countries supporting Israel. In this situation, the US did not have the excess capacity to offset the Middle East supplies, and other OPEC members including Iran chose to stand on the sidelines. By the end of the year the OPEC posted price had spiked to $11.65/bbl. (USD) while “spot prices” rose even higher, as traders from non-OPEC countries exploited panic buying. The embargo was lifted in March 1974 but posted prices remained above $10/bbl. (USD) and the producing states extracted further concessions from the large refining companies, including nationalizing the fields and refineries in their own countries. The era of price stability in world oil markets had unravelled.3 Another round of price spikes came in 1979–80 when the Iranian revolution and Iran-Iraq war disrupted exports from the Middle East. Even before the fall of the Shah of Iran, spot oil prices surged from $12.80 to $21.80/bbl. (USD) and then on to $40/bbl. (USD) by the end of 1979. OPEC, which had not created this chaotic situation, nevertheless exploited the crisis. By 1981 the OPEC posted price was $34/bbl. (USD). Just as significantly, the major consuming countries, including the United States and Canada, began to frame energy policies based on the assumption that high oil prices were here to stay.4
But OPEC, much like the early producer cartels, was inherently unstable. Many member countries habitually exceeded their quotas, selling advantageously on the spot market. Fundamentally the organization was divided between countries like Iran and Venezuela with diminishing reserves and large politically volatile populations, and the oil-rich, thinly populated Arab nations of the Persian Gulf, particularly Saudi Arabia. Wary of the expansionist inclinations of their bellicose neighbours, Iran and Iraq, and with ties to the United States going back to the Second World War, the Saudis sought stability in the market, with prices set at a level that would sustain the consuming countries. The disruptive circumstances of the 1970s favoured the views of OPEC hardliners.
In 1981, however, market conditions began to change. Oil demand fell, due in part to a hard recession in the industrialized nations and conservation measures that were particularly effective in Japan and Western Europe. North Sea oil began to come on-stream and new discoveries in Africa offered the prospect of larger non-OPEC reserves. For several years Saudi Arabia tried to sustain a benchmark price of $29/bbl. (USD) but by 1985, with its OPEC partners cheating by sales on the spot markets, the Saudis deliberately lifted production limits, although it tried to maintain prices that would ensure marginal profits to the big refining companies. By the middle of 1986 Arab light crude prices fell from $28/bbl. (USD) to $11/bbl. (USD).5
After this triumph, Saudi Arabia exercised leadership of OPEC, with tacit support from the United States, through its potential capability to discipline the other members by increasing or reducing production. Cheating continued to be a problem for the cartel, and prices could spike up when unforeseen events intruded, as happened in 1990–91with the collapse of the Soviet Union and the Gulf War. But markets achieved relative stability between 1991 and 2003, with price ranges fluctuating between $18/bbl. (USD) and $30/bbl. (USD), and OPEC retained a 35 to 40 per cent market share.6
This happy equilibrium began to unravel after 2003. The Iraq War temporarily removed a major producer from the field, and the expansion of Russian production stalled in the context of power struggles within the post-Soviet elite. More significantly, the rapid industrial development of “emerging economies,” particularly China (as well as India and Brazil), boosted demand. By 2005 Saudi Arabia indicated that its production capacity was being strained, although it subsequently announced plans to develop hitherto untapped fields. By this time “peak oil” warnings resurfaced for the first time since the 1970s, feeding speculation in oil futures. During 2004–05, posted prices rose from $28/bbl. (USD) to $42/bbl. (USD), and continued to surge, climbing to $140/bbl. (USD) in 2008.
By this time both producers and governments were returning to the mindset, which prevailed in 1980, that high oil prices would be a permanent feature. The oil sands once again attracted new entrants, Arctic dreams resurfaced, and projects involving exploitation of higher-cost sources in places like Kazakhstan and Chad looked more feasible. But as before, the market began to shift. The collapse of the US real-estate bubble in 2008 spread to Europe, leading to the worst recession in the industrialized nations since the 1930s. Although continuing economic growth in China propped up demand, by 2016 crude prices were plummeting from over $115/bbl. (USD) to less than $30/bbl. (USD), reminiscent of the early days of the industry in North America. By 2017 prices seemed to have firmed up to over $40/bbl. (USD) but the underlying uncertainties remained.
Developments on the supply side played an important part in this downturn. After 2006 when Saudi Arabia embarked on a costly expansion into refining and natural gas production, the country had become reluctant to take on the task that it had pursued in the 1980s, using its own oil production rate to determine OPEC prices. None of the other cartel members had the capacity to play this role, and in any case they all wanted to continue to increase their production while the price was high. Inevitably this course led to saturation of a diminishing market.
But another element significantly affected this situation. The “shale revolution” began in the 1980s when the Houston oil and gas producer George Mitchell (and others) developed a hydraulic fracturing process to reach petroleum in shale rock areas that had defied conventional drilling. Initially expensive, by the year 2000 “fracking” techniques were yielding profitable quantities of gas from shale, enabling the dramatic growth of natural gas to replace both coal and oil in the heating and industrial fuel markets. By 2015 fracking had also expanded production of shale oil particularly in the United States. Since shale oil wells had a much shorter lifespan than conventional wells, producers were driven to exploit them as fast as possible and expand to new reservoirs constantly. Assumptions that shale production, like that in the oil sands, required oil prices in the $60+/bbl. (USD) range to be profitable proved wrong—at least in the short run—given the incentives to keep producing while trying to achieve cost efficiencies.7
The gyrations in oil prices from 1971 through 2016 (and likely beyond) affected the entire industry, but particularly the big oil companies that had exercised dominance in the preceding era, and Exxon perhaps most of all. For one thing Exxon had the misfortune of holding a stake in virtually all of the OPEC countries. It had been one of the first oil majors to move into Venezuela in the early 1900s, and gained a foothold in each of the Middle East oil consortia: Iraq in the 1920s, Aramco in the 1940s, and Iran after the 1953 coup. It had a large investment in the Libyan oil fields in the 1960s. Of course Exxon had many other commitments (including Canada), but upheavals in some of its largest supplier nations were bound to have serious consequences.
By the mid-1980s, Exxon found itself in a situation similar to the one that confronted Walter Teagle as head of Jersey Standard in 1918: a company with huge refining capacity, well-running transportation and distribution systems, strong research capabilities—but limited access, let alone control over crude oil reserves. One of the major goals of the company’s chief executives, from Ken Jamieson in the 1970s to Rex Tillerson in the second decade of the twenty-first century, was to secure reasonably predictable supplies of oil and gas for its far-flung operations.
In the 1970s this quest led Exxon to expand offshore drilling, from California and the Gulf of Mexico to the North Sea and Malaysia. It also supported the development of Imperial’s ventures in the oil sands and the Arctic, until the price collapse of 1985–86. By the 1990s post-Soviet Russia’s newly privatized resources beckoned, leading to intricate and often frustrating “oil diplomacy” with that country’s feuding power brokers. Exxon also sought footholds in undeveloped oil fields in the African states of Chad, Cameroon, and Angola, embroiling the company with dictators and revolutionaries reminiscent of its experiences in Mexico and Venezuela in the early twentieth century.8
Despite these difficulties and recurring controversies at home—US Congressional investigations of alleged profiteering by oil majors during the energy crises of the 1970s, environmental protests following the Exxon Valdez disaster in 1989—the company retained its powerful role in the industry, in part due to its organizational capabilities honed over more than a century, technological leadership, and the sheer size of its financial resources. As the twentieth century ended, a new struggle for power among the largest global oil companies ensued, culminating in a series of gigantic mergers in the industry that were themselves triggered by a price fall in the wake of the sudden financial collapse of the “Asian Tigers”—South Korea, Taiwan, Hong Kong, and Singapore, followed by other, larger East Asian economies—in 1998. BP [British Petroleum] pursued Mobil [Standard of New York] but eventually settled for a takeover of Amoco [formerly Standard of Indiana], and then Arco [Atlantic Richfield] with its large holdings in Alaska. These events precipitated more mergers, and Exxon’s chief executive Lee Raymond—wary of the growing strength of BP and seeking to overtake the dominant player, Royal Dutch Shell—quickly orchestrated an agreement with Mobil. By the end of 1999 the world of oil had come resemble the one that existed before the breakup of the Standard Oil Trust in 1911, with four giant companies left standing: Shell, BP, Chevron [Standard of California], and Exxon Mobil.9
Canada was not immune to the wild gyrations in oil prices throughout this period, although the fluctuations were attenuated by the unusual circumstances of being both an exporter and importer of petroleum. Between 1974 and 1985, the Canadian government imposed controls on crude oil prices, which involved export taxes and import subsidies as well as regulations on the price of domestic production, leading to tense confrontations with the producing provinces, as discussed below. During that time period Canadian oil prices rose from less than $5/bbl. (CAD) to a peak of $37.50/bbl. (CAD) in 1984. Government regulation generated a gap with world oil prices that ranged as high as $10/bbl. (USD) in the “second energy crisis” of 1979–81.
In 1985 the “Western Accord” between the federal government and the western oil-producing provinces removed the regulatory regime. From that point, Canadian crude oil prices began to track two oil major global price benchmarks, West Texas Intermediate (WTI) light crude and Brent Crude, based on North Sea production. As these were valued in US dollars, fluctuations in the US-Canada exchange rate contributed to variations between Canadian and benchmark price ranges. From a low of $18/bbl. (CAD) in 1985, crude prices rose to $30/bbl. (CAD) in 1990 but fell back again by the end of the decade.
Canadian prices continued to track the benchmark indicators, but after 2004 a new marker was established by four of the largest oil sands producers—EnCana, Petro Canada, Canadian Natural Resources, and Talisman Oil—designated Western Select Crude (WSC). The pricing was applied to heavy crude oils with high acidic content with a limited range of refineries suited to process the product. As world oil prices began to rise again after 2005, WSC oil became more attractive, despite its high cost of production and processing and the continuing challenges of transportation to major consumer markets. But WSC prices trailed the other benchmarks throughout the ensuing boom and bust between 2008 and 2016. In 2013, WSC reached a peak of $82/bbl. (USD) while WTI and Brent ranged between $100–$110/bbl. (USD). WSC prices fell to $38/bbl. (USD) in 2016 with WTI and Brent hovering in the $60–$64/bbl. (USD) range. By this time heavy oil and upgraded bitumen comprised the preponderance of Canadian oil exports; conventional crude oil production had declined steadily since the 1980s to less than 1 million bbl./day while oil sands output had risen to 2.5 million bbl./day.10
The Energy Crises, 1973–1985
Even before the OPEC price hikes and the Arab oil embargo in the autumn of 1973, the conditions that shaped Canada’s National Oil Policy were changing. In 1968–69 new political administrations took power in Washington and Ottawa, and both had agendas that embraced a more nationalist perspective than their predecessors. The Republican president Richard Nixon sought to straddle a political party populated by internationalist and protectionist factions. Although the Liberal party remained in power in Canada, the new leader, Pierre Trudeau, displayed a greater interest than had his predecessors in expanding the role of government in economic affairs.
In 1970 the US government unilaterally terminated Canada’s exemption from the Mandatory Oil Import Control program. This was a preview of tough measures Nixon imposed on Japan and other US trading partners a year later, but it came as a shock to the Canadian government. During the 1960s continentalist trends had prevailed: the Lyndon Johnson administration had supported the extension of Canada’s Interprovincial Pipeline system to Chicago, which opened the huge Midwest market to Imperial and other exporters—despite protests from some US producers.11
Meanwhile, in Canada, the new Department of Energy, Mines and Resources (EMR) was infiltrated by advocates of a “national” oil company to offset the influence of foreign-owned majors like Imperial Oil and Shell. Trudeau was not prepared to endorse such a venture at this point, but elevating the EMR fit into his efforts to centralize control of government policymaking in the prime minister’s office.12
Nixon’s move against Canadian exports backfired because of the growing US demand for oil and gas products. Oil exports surged through 1971–72, to the point where the Canadian government became alarmed: exports rose from 49 per cent of domestic production in 1969 to 63 per cent by 1973. In March 1973 the cabinet ruled that further exports would require approval by the National Energy Board, which imposed a restriction on exports to 1.25 million bbl./day, a relatively minor cut but symbolic of the changed circumstances. Six months later, the Trudeau government unveiled a more comprehensive plan—in advance of the OPEC crisis. A 15 per cent tax was imposed on oil exports, petroleum prices were to be “frozen” for five months, and a pipeline would be built between Toronto and Montreal, with government subsidies if necessary: the project would be completed by Interprovincial in 1976.13
The OPEC crisis dictated further actions. In November 1973 Prime Minister Trudeau announced that the price for Alberta crude oil would be regulated to prevent unsustainable price hikes for eastern Canada. The oil export tax, which had already been raised by 40 cents per barrel in September, was increased again by $1.90 per barrel. The rationale was that adequate reserves of heating fuel were needed for the ensuing winter months and that US refiners, clamouring for Canadian crude supplies, could deplete domestic oil sources. Soon the temporary restrictions on exports to the US were moving toward permanence: in November 1974 Donald MacDonald, the Energy Minister, unveiled a plan that would phase out oil exports completely within eight years.14
Meanwhile, the Trudeau government had to manoeuvre its way between the producing provinces, particularly Alberta, which wanted to see oil prices rise to “international” levels and the New Democratic Party, which opposed any increase in domestic prices. Since 1972 the Liberals, to buttress their minority government, had formed a tacit alliance with the NDP, but by early 1974 Trudeau hoped that the measures imposed during the energy crisis would boost his party’s fortunes in an upcoming election. In March 1974 the federal government reached an agreement with Alberta that raised the domestic crude price from $3.80/bbl. (CAD) to $6.50/bbl. (CAD), roughly $4 per barrel less than the export price, while retaining the taxes on exports. An exception to the regulated price of domestic oil would be made for oil sands production. Two months later Trudeau led his party to a majority electoral victory.15
The combined impact of the imposition of regulated prices on western Canadian oil and the virtual ban on exports encountered pushback, from the oil industry as well as the producing provinces. The oil majors, including Imperial, were accustomed to being consulted by the National Energy Board about prospective policy changes, but the initiative had now shifted to the Department of Energy, Mines and Resources and new measures, often taken in haste, were made without consultation. In April 1974, Alberta increased its royalties, while Ottawa refused to allow the oil companies to apply them against federal taxes—a by-product of the continuing feud between the federal and provincial governments. A report to Imperial Oil’s Executive Committee noted that while federal tax revenues and provincial royalty revenues would both quadruple as a result of these arrangements, the oil producers’ revenues would decline from $1.18/bbl. to 0.71/bbl. (CAD)—a formula that would reduce “the viability of cash flows.”16
Many conventional oil producers in Canada cancelled plans for exploration and development and “drilling rigs fled south.” With its large long-term investments in the oil sands and Arctic exploration, Imperial Oil could not just pick up its marbles and leave the scene. Jack Armstrong, however, vented the company’s frustrations in remarks to shareholders a year later: “Less than two weeks following the 1974 Annual Meeting we . . . faced . . . a situation where federal, as well as provincial policies . . . switched from being venture-oriented to revenue-oriented . . . No one anticipated an intensification of the federal/provincial struggle over resource revenue sharing with ensuing tax/royalty legislation that would jeopardize Canada’s future supply of oil and natural gas.”17
For all the grumbling, Imperial Oil did not come out too badly from the energy crisis of 1973–74. Total revenues doubled between 1972 and 1975, with petroleum products contributing over 50 per cent; earnings per share rose from $1.18 to $1.92 (CAD), and working capital increased from $375 million to $572 million (CAD). Royalties did indeed take a bite, rising from $81 million in 1972 to $273 million (CAD) in 1975, an increase of 237 per cent. As Armstrong implied, Imperial’s conventional crude reserves declined in this period but exploration expenditures held steady and Imperial doubled its commitment to Syncrude, rising to over $100 million (CAD) by 1975—an acceleration occasioned in part by the reorganization of the consortium after Atlantic Richfield withdrawal and the exemption of the oil sands from price regulation.18
The first energy crisis left one more legacy in Canada. In October 1974, three months after a Liberal majority government was elected, a bill in Parliament was introduced establishing Petro Canada, which among a range of capabilities was given a mandate “for public intervention in the Canadian energy industries.” The New Democratic Party had been agitating for a “national oil company” for several years, but the genesis of Petro Canada probably owed more to the nationalist wing of the Liberals, going back to the days of Walter Gordon, the scourge of the multinationals in the 1960s. Trudeau was hardly a nationalist in the conventional sense, but he was willing to wield the full powers of the state when he chose, as demonstrated by the invocation of the War Measures Act during the October Crisis in 1970. The designers of Petro Canada—Joel Bell and Wilbert Hopper—had large ambitions for their creation, and Hopper would run the crown corporation until the 1990s.19
If Petro Canada was a stick to beat the oil industry, the federal government also offered carrots, beginning with a “super-depletion allowance” for a fast write-off of exploration and drilling costs, intended particularly to promote Arctic and offshore Newfoundland resource development. In 1977 Donald MacDonald, now Finance Minister, announced that certain “frontier” oil exploration costs could be written off within two years at a 66.67 per cent rate (which combined with a revised regular depletion allowance of 33.33 per cent amounted to a full write-off). In industry circles this was referred to as the “Gallagher allowance,” as a major beneficiary was Jack Gallagher’s Dome Petroleum, which he was positioning to be a “chosen instrument” for Canada’s northern oil development. This was a precursor to the “Petroleum Incentive Program” (PIP) grants that were incorporated into the National Energy Program unveiled in 1980.20
In 1979 the Liberals were turned out of office in Ottawa for the first time since 1962. The Progressive Conservative government under Joe Clark proved to be short-lived for a variety of reasons, including the onset of a second international energy crisis precipitated by the revolution in Iran and the Iran-Iraq war. Once again the New Democratic Party joined forces with the Liberals to topple Clark. Trudeau led the Liberals to victory in an election in February 1980 promising lower energy prices, security of supply, and protection of “Canadian” oil. Trudeau personally was more interested in securing repatriation of the Canadian constitution, but a “strategy committee” under his close aide Marc Lalonde, who would become Minister of Energy, Mines and Resources, spent the Liberals’ months in exile designing a comprehensive interventionist energy policy for the country.
The National Energy Program (NEP), unveiled on October 1980, was a complex array of subsidies, taxes, and regulatory measures that “turned the West against the East and manufacturers against natural energy suppliers while simultaneously enriching the coffers of the central government.”21 Consumers would continue to be subsidized, indirectly, by the establishment of a “blended” national price that would include imported oil, synthetic oil, and domestic conventional oil, to be administered through an Oil Import Compensation Program, that had already proven to be a disaster in the United States. Oil exports were (again) to be phased out, this time by 1990. “Frontier” oil exploration and development would be subsidized, emphasizing the role of the publicly owned Petro Canada and Pan Arctic Oils.
To pay for the projected $11 billion (CAD) cost, an 8 per cent Petroleum and Gas Revenue Tax (PGRT) would be imposed on net production revenues of oil and gas companies, with the provision that it could not be deducted from other taxes due. The most politically controversial measure was a new revenue-sharing formula between the federal government, the “producing provinces” (mainly Alberta), and the industry, so that the federal share would triple to 30 per cent—at the expense of the other two “partners.”22
For the oil companies, and particularly for the multinationals like Imperial, there were some key irritants in addition to the tax and revenue-sharing components. The depletion and “super-depletion” allowances were terminated, to be replaced by federal grants under the Petroleum Incentives Program (PIP), which would give preferential treatment to companies with more than 50 per cent Canadian ownership. Dome Petroleum, which did not qualify, scrambled to set up an affiliate, Dome Canada, selling 52 per cent of the shares to Canadians. Imperial Oil did not have this opportunity, although it did farm out some of its holdings in the Beaufort Sea area to companies that met the “Canadian content” requirement. As a further aggravation of the private oil industry, another tax on oil products was included to enable Petro Canada to buy up other companies.23
In the meantime Alberta, in retaliation against the revenue sharing revisions of the NEP, vowed to cut its production by 15 per cent commencing in March 1981, and held up approval of Imperial’s Cold Lake expansion project, as well as Alsands, another large oil sands undertaking by a consortium led by Shell. Once again the oil companies were caught in the middle of a constitutional struggle between the federal government and Alberta.
At this point, despite their preference for settling such issues behind the scenes, Imperial’s executives mounted an unusual public counterattack. On November 19, Lalonde spoke to investment advisers in New York, cautioning them not to overreact to the NEP, and maintaining that the foreign-owned oil companies in Canada were on board. Later that day, Jack Armstrong, now the board chairman of Imperial, announced that his company was shelving further development of the Cold Lake oil sands project. This was a somewhat improbable move, since earlier in the year Imperial had issued $1 billion (CAD) in new stock, at below-market prices, to its shareholders, to help finance projects over the next decade, including a $7 billion (CAD) commitment to Cold Lake. Nevertheless, the very next day Lalonde met with Armstrong and offered Imperial at $40 million (CAD) loan to cover continuing development costs at Cold Lake, with no “Canadianization” strings attached, even though Petro Canada was exhibiting an interest in entering one of the oil sands consortia.
Cynical observers speculated that these were pre-rehearsed events intended to put pressure on Alberta to lift its restraints on oil sands development. But a few days later Armstrong indicated Imperial might halt a $300 million (CAD) “enhanced oil recovery” project at Judy Creek in Alberta. Imperial’s president J.R. Livingstone argued that the $38/bbl. (CAD) “blended” price for synthetic crude was insufficient to justify expanding Cold Lake. In early January 1981 Armstrong asserted that if NEP passed, Imperial would cut capital spending by $2.5 billion (CAD) over the next four years, and in a presentation to the National Energy Board, Imperial warned it would reduce estimated production by 180,000 bbl./day, a 14 per cent cut.24
Through the spring and summer of 1981, Alberta and the federal government bickered over the NEP, as Premier Peter Lougheed threatened more production cuts. In July Imperial announced that, despite the $40 million loan, it was suspending further work at Cold Lake, a move Lalonde denounced in Parliament as “blackmail.” But by September, with the independents as well as multinational companies up in arms over NEP, Ottawa was prepared to cut a deal with Alberta, giving the province more control over PIP grants and agreeing to reduce its share of oil revenues to 25.5 per cent. The price of domestic oil was allowed to rise by revising the “blending” formula to recognize the higher costs of “new” oil from the Arctic and the oil sands.25
Even as Lougheed and Trudeau were (warily) toasting their agreement, the real world of oil prices was sliding out from under them. In May 1982 the Alsands “megaproject” dissolved; Dome Petroleum careened toward bankruptcy; the federal deficit had doubled to $20 billion (CAD). Although the decline in oil prices was less severe than the big drop to come in 1985–86, even a modest change was sufficient to puncture the speculative bubble in Canadian oil markets, aggravated by a deepening recession across the industrial world. The Liberal government in Ottawa tottered on until 1984 when a newly energized Progressive Conservative party led by Brian Mulroney displaced them. The NEP was rapidly dismantled by the new Energy Minister, Patricia Carney, rolling back many of the program’s tax measures. The PIP was replaced with new tax incentives that were extended to foreign-owned companies, and in 1985 a new “Western Accord” was signed with Alberta and the other western oil-producing provinces. In 1989 a Free Trade Agreement was signed between the US and Canada that was intended to prevent the recurrence of the kind of nationalist approach represented by the NEP.26
For Alberta, the confrontation with Ottawa during the NEP era was seared into political memory for the next generation. Imperial Oil too experienced turmoil through the NEP years, although the impact may have been less lingering. Between 1975 and 1980 the company’s revenues more than doubled from $3 billion to $6.2 billion (CAD) and net earnings grew even more from $263 million to $682 million (CAD). Between 1981 and 1985 even as rising oil and gas prices pushed revenue upwards, the rate of growth slowed, going from $8 billion in 1981 to $8.8 billion in 1985 (CAD). But net earnings fell most sharply from $465 million in 1981 to $289 million (CAD) in the following year, and only recovered its pre-1980 level after 1985. Return on investment dipped from 8.9 per cent in 1981 to 5.3 per cent in 1983, rising to 9.2 per cent in 1985.27
Taxes and levies imposed through the NEP contributed to this slackening: the Petroleum and Gas Revenue tax alone took $91 million (CAD) of Imperial’s earnings in 1981. But there were other factors at work. During the late 1970s exploration and development of conventional oil wells spiked in 1978 but then subsided. Proved reserves of natural gas fell steadily. Synthetic oil production at Syncrude and Cold Lake grew after 1977 but only accounted for 12 per cent of total output. The controversy between Alberta and Ottawa in 1980–81 led Imperial to shutter Cold Lake for several years. Drilling in the Arctic and Atlantic shelf produced mostly natural gas or dry holes. The restrictions on non-Canadian investment in frontier areas under the NEP limited Imperial’s opportunities to expand although in 1982 the federal government contributed $600 million (CAD) to a Beaufort Sea venture with Imperial. Meanwhile, however, the company shelved a joint venture with Alberta Energy to build a new petrochemical plant, sold its interest in Trans Mountain Pipe Line and instituted staff cuts for the first time in many years.28
Imperial Oil’s troubles occasioned some sympathetic journalist, expressed concern that Imperial had made misjudgments, not so much in its business strategy as in underestimating its public relations and the ability of political foes and business rivals to exploit its vulnerabilities.29
Nevertheless, Foster also argued, “rumours of Imperial’s demise . . . have been greatly exaggerated.” By 1984 Cold Lake was back in operation with plans for further expansion, and Syncrude increased output to 129,000 bbl./day. An enhanced recovery operation at Judy Creek and completion of Norman wells expansion increased conventional oil production by 8 per cent in 1986. Service stations were upgraded, featuring convenience stores and automated bank machines—another turn in the cyclic evolution of gas retailing. Exxon’s agricultural chemicals division was assigned to Esso Chemical Co. in Redwater, Alberta. Although the company was to experience financial setbacks following the takeover of Texaco Canada and the recession of the early 1990s, it remained the industry leader in Canada in 1996, holding one third of the assets of the sector and accounting for 34 per cent of the sales of petroleum products ahead of Nova (22 per cent), Shell Canada (16 per cent), Amoco (16 per cent), and Petro Canada (15 per cent).30