Amoco's First Fifty Years in Canada: 1948 — 1998
By Peter McKenzie-Brown
Published by Amoco Canada Petroleum Company Ltd.
P.O. Box 200
240 4th Ave. SW
Calgary, Alberta T2P 2H8
Canadian Catalogue in Publishing Data
McKenzie-Brown, Peter
The richness of discovery: Amoco’s first fifty years in Canada (1948-1998)
Includes bibliographical references.
ISBN 0-9684022-0-8
1. Amoco Canada Petroleum Co. — History. 2. Petroleum industry and trade–Canada–History. I. Amoco Canada Petroleum Co. II. Title.
HD9574.C24A46 1998 338.7’622338’0971 C98-900757-X
Layout by Maskell Design
Printed in Canada
Table of Contents
Foreword
Introduction
1. The Early Years
2. Building an Oil Business
3. Natural Gas Comes into its Own
4. A Blueprint for Liquids
5. The Geographic and Technological Frontiers
Conventional Exploration
Table: Significant Discoveries
The Frontiers
Non-conventional Resources
6. The Acquisition
Table: Production Growth
7. This Decade
Acquisitions and Divestitures
Growth
New Times
Appendix 1: A Parable of Milestones
Appendix 2: Risky Business
Appendix 3: Out in the Cold
Profiles of Amoco People
Pulling through the Bad Times
Critical Start-up Years
One Terrific Company
Thirst for Knowledge
People, Policy and Paper
Exotic Recovery
Brantford Boy
Family Tradition
Authority to Act
Phantom Cartoonist
The Front Edge
Putting Down Roots
Acknowledgments
A Note on Sources
Canadian Metric Versus US Units
About the Author
Acquisitions and Divestitures
Foreword
This history offers a brief record of Amoco Canada’s first half century as a Canadian business. To understand the company’s story, however, it is important to place it within a larger context.
Amoco Canada’s shareholder, Amoco Corporation, began life as Standard Oil of Indiana in 1911. For its part, Standard of Indiana was one of 33 companies separated from John D. Rockefeller’s Standard Oil Trust by a landmark US Supreme Court decree. Now a world-wide corporation, Standard of Indiana and its subsidiaries have operated under many names over the years.
Standard of Indiana incorporated a wholly-owned subsidiary, Stanolind Oil and Gas Company, in 1930. Through acquisitions and discovery, Stanolind had become one of the largest petroleum companies in the United States when it set up operations in Canada 18 years later.
Today’s Amoco Canada was technically a division of Stanolind until 1956. At that time, however, Stanolind acquired the production properties and operations of Pan American Production Company — another Amoco subsidiary — and changed its name to Pan American Petroleum. Stanolind’s Canadian assets were subsequently operated as a division of Pan American.
In 1969, Amoco’s Canadian properties were incorporated under the Canada Corporations Act as Amoco Canada Petroleum Company Ltd., a wholly-owned subsidiary of Standard Oil of Indiana. Amoco Canada was created out of Pan American’s Canadian properties, which included two subsidiary companies — Winter Oil Company and Muskeg Oil Company.
To avoid confusion, in this publication the name Amoco will generally (but not exclusively) refer to Amoco operations in Canada. However, the phrase Amoco Canada will be used exclusively to distinguish the corporation’s Canadian operations. Similarly, references to the “corporation” will suggest the larger organization, while the term “company” will suggest Amoco Canada.
The responsibilities of Amoco Canada’s leaders have evolved substantially over the years. This was a natural development, reflecting both the company’s growth from exploration enterprise to integrated petroleum company and the changing business environment. The following table lists people who have held top jobs in Canada since the company arrived in this country. Unless these leaders retired immediately after their assignments in Canada, they went on to even more senior jobs in the Amoco world.
Year Person Title Most recent Amoco assignment Retired
1948 C.F. (Charlie) Schock Exploration Superintendent Division Manager 1951
1952 George H. Galloway Division Manager President, Amoco Production Company 1981
1959 Frank C. Osment Division Manager Executive vice president, Amoco Corporation 1982
1964 John C. Meeker Division Manager; later, President Executive vice president, International 1987
1973 Henry O. (Hank) Boswell President President, Amoco Production Company 1988
1976 Fraser H. Allen President 1982
1982 Norman J. (Norm) Rubash President Executive vice president, International 1991
1985 William J. (Bill) Lowrie President President, Amoco Corporation
1986 T. D. (Don) Stacy Chairman and President President, Amoco Eurasia 1997
1993 E. D. (Dave) Newman Chairman and President Group vice president, USA Operations
1996 Robert D. (Bob) Erickson Chairman and President Chief operating officer, Azerbaijan International Operating Company
1998 R. Gregory (Greg) Rich Chairman and President
Introduction
For Canada, the Amoco story is a key part of the post-war growth and development of the national petroleum industry. Against that background, three features are striking.
One is the imagination and energy with which the industry mapped and developed Canada’s petroleum resources. During those years the industry began to identify the potential of Canada’s offshore and northern frontiers (only recently being tapped to any large extent). But the bread-and-butter activity was in the western provinces, which became renowned for resources across the entire hydrocarbon spectrum. There are vast oil sands and heavy oil deposits in Alberta and Saskatchewan. There is outstanding natural gas potential in Alberta and northeastern British Columbia. There are conventional oil prospects in all four western provinces and the Territories.
As they defined the boundaries of this raw potential, a band of pioneers that included the people of Amoco began to develop the Canadian petroleum industry. Through their efforts, Canada became a net exporter of oil, created the world’s third largest natural gas business and developed the world’s third largest natural gas liquids sector. Despite relatively modest levels of light oil production, Canada is one of the world’s larger oil producers. One reason is the industry’s production of heavy oil; another is an oil mining and upgrading industry that is unique to Canada.
A second striking feature of petroleum history is the size of its economic impact. To a large extent because of the stimulus provided by oil and gas, Canada’s west is now a muscular part of the federation. Alberta has been the particular economic beneficiary, because the province is rooted in the most productive part of the Western Canada Sedimentary Basin.
But the economic advantages of oil and gas have spread far beyond their roots. In 1948, Canada relied primarily on coal for energy, and relied primarily on the United States for crude oil imports. Today, petroleum is Canada’s main source of energy and an extremely important export. In 1997, petroleum exports contributed $12.7 billion to Canada’s net balance of trade — half the total.
The early players in Canada’s modern oil industry had a disproportionate impact in the economic transformation of the most westerly provinces. To use the Amoco example, the company’s investment helped eliminate Canada’s need for oil imports; by 1955 the west’s productive capacity far outstripped the oil demand of all Canadian refineries. Besides helping Canada maintain a healthy balance of payments, the company has paid billions of dollars to governments in royalties, land bonuses and taxes.
Amoco’s oil and gas investment contributed to growth in many areas: manufacturing, the petroleum service sector, oilfield technology and infrastructure, petrochemical development. One outcome was the creation in western Canada of one of the world’s most competitive, technically advanced and respected national oil industries.
The third lesson from this history has to do with Amoco Canada’s impact on Amoco Corporation’s growth.
The company experienced spectacular exploration and development successes during the 1950s and 1960s. As a result, within 15 years of arrival Amoco Canada represented 5 per cent of the corporation’s world-wide assets. And even though the company’s shareholder has also grown rapidly since that time, at year end 1997 Amoco Canada represented 9.4 per cent of the corporation’s total assets (and 13 per cent of net income).
In 1997, Amoco Canada was the largest Canadian producer of natural gas, NGLs and sulphur. The company was the largest cold producer of heavy oil, the second largest in situ producer of heavy oil and one of the 10 largest producers of conventional oil. The company was also one of Canada’s top marketers of oil and natural gas.
Shipments through Amoco’s three oil pipelines averaged 120,000 barrels per day in 1997. The company also operates the Cochin liquids pipeline, which transports more than 100,000 barrels of NGLs per day; the Alberta Ethane Gathering system; and the Co-Ed NGLs pipelines. These facilities are key parts of Canada’s liquids infrastructure.
By revenue, in 1997 Amoco Canada was the 23rd largest Canadian company and the second largest oil and gas company. The company was also Canada’s 15th largest exporter, and the largest exporter of energy.
Amoco’s top rankings in Canada reflect many years of steady growth and innovation. What was the source of that growth? This book covers resources, investment, discoveries, technology, infrastructure and policy in varying degrees. It does not even pretend to give Amoco employees sufficient due, however. History can rarely see beyond great achievements and outstanding deeds to the countless actions of the men and women who made them possible.
1. The Early Years
Sidebar: Helen and Jack Cush
Photographs: James Miller Williams; 1914 Dingman well.
In Canada, the Amoco story begins with the birth of the modern petroleum industry. A business based on exploration and discovery, the Canadian industry predates that of the United States by a single year. But that year is one many Canadians take pride in.
James Miller Williams brought in North America’s first commercial oil well in southern Ontario in 1858 — the year before the much more famous Edwin Drake discovery at Titusville, Pennsylvania. After that start, the producing sector of Canada’s petroleum industry remained small for nearly a century.
But the oil fields of southern Ontario were small and of relatively poor quality — unable to compete with the huge discoveries later made in the United States, Russia, Indonesia and the Middle East. As importantly, the resources in Canada’s other sedimentary basins were too remote to find with the technologies of the day.
Commercial hydrocarbons exist in every Canadian province (except Prince Edward Island) and in the northern territories. But outside of southwestern Ontario, the only region with easily produced, accessible oil and gas resources in the industry’s early years was the Western Canada Sedimentary Basin.
Huge in aereal extent, that basin’s oil and gas resources are heavily concentrated in central and northern Alberta. Entrepreneurs and both levels of government made many early attempts to develop oil production from the immense Athabasca oil sands deposit, which Europeans have known about for some 200 years.
It is therefore a fluke of geology, geography and history that Calgary (in the south of the province) became the industry’s corporate centre and therefore home to Amoco Canada’s head office.
Shallow gas is plentiful in southern Alberta, where it has been providing light and heating fuel for the community of Medicine Hat since the 1890s. (After witnessing this phenomenon, Victorian writer Rudyard Kipling proclaimed that the town had “all Hell for a basement.”)
In 1912, the rapidly growing city of Calgary became the terminus for Canada’s first major pipeline, a 274-kilometre gas line from southeast Alberta. The pipeline’s Calgary-based owner, Canadian Western Natural Gas, Heat, Light and Power Co. (today Canadian Western Natural Gas) developed gas production and transportation expertise.
Calgary developed additional petroleum expertise after nearby Turner Valley went on production.
Western Canada has produced small amounts of oil since the beginning of this century. But the first really significant discovery was the Turner Valley find of 1914. For many years this field was, as early oilmen proudly proclaimed, “the largest oil field in the British Empire.” It was also Canada’s only large producing field until the late 1940s. A small petroleum industry began to grow as Calgary-based companies developed and produced its liquids-rich gas.
In Turner Valley’s early years, producers stripped natural gas liquids (known at the time as natural gasoline) from the field’s gas cap. Most gas from the Turner Valley field was then simply flared into a ravine called Hell’s Half Acre. These giant fires produced light that was clearly visible 35 kilometres away, in Calgary’s night-time skies.
The Midwest Refining Company, an Amoco subsidiary, asked geologist John Bartram to report on Canada’s oil prospects in 1926. According to his report, dated the following year,
The big gasoline well (Royalite #4) came in late in 1924 at a depth of 3750 feet, and in less than two years has marketed 11,064,000 Imperial gallons of 72 gravity gasoline and a production of about 20,000,000 cubic feet of gas a day....It is a very valuable property.
Bartram recommended a careful study of Alberta’s potential.
We know from our own experience that the geologists and also the officials of a company that operates in one area for a long time, tend to think along the same lines and to accept the same theories of oil occurrence. When other groups of men invade the same territory, the newcomers work with different methods, use different theories and drill structures the others condemned.
Before Bartram’s recommendations could be implemented, oil prices began to decline as new discoveries in the US mid-continent came on stream. Then came the Depression, followed by World War II. While Bartram’s ideas were prescient, it would be two decades before Amoco actually made the move to Alberta.
British statesman Winston Churchill — who began taking a keen interest in oil as a strategic commodity before World War I — visited the Turner Valley field in 1929. One companion was his adolescent son Randolph, who commented somewhat snootily on “oil magnates pigging up a beautiful valley to make fortunes,” and went on to criticize “their lack of culture.” As the younger Churchill recorded in his diary, “Papa flared up: ‘Cultured people are merely the glittering scum which floats upon the deep river of production!’ Damn good.”
This exchange typifies both sides of a recurring environmental debate — simplistically speaking, one between the romantic liberal and the pragmatic conservative. Over the years the debates have taken many forms, but each side has always had its faithful adherents.
Early conservationists — the predecessors of today’s environmentalists — were deeply concerned about protecting land and other resources from squander. The conservation movement got a boost in Alberta when the tragic waste of Turner Valley’s potential became understood.
In 1936, a company called Turner Valley Royalties discovered Turner Valley’s oil column — the deep reservoir of oil underneath the field’s liquids-rich gas cap. This discovery meant that in their quest for gas liquids, early producers had been wasting oil.
The reason is simple. In conventional production, oil is driven towards a well’s borehole by a number of forces, the most important of which is usually the pressure an expanding gas cap exerts. Because much of Turner Valley’s gas cap had been produced, the energy that could have helped produce oil from the field had been greatly diminished.
When these losses became known, Alberta’s media and public cried out against the waste. This is one reason the Alberta government established the Petroleum and Natural Gas Conservation Board in 1938. With headquarters in Calgary, the board’s early mandate was to make sure production from Turner Valley and Alberta’s other oil and gas fields was based on good production practices.
The board distinguished itself around the world with its technical expertise. If imitation is the sincerest form of flattery, then the board is probably Canada’s most sincerely flattered public agency. Many countries overseas copied the Conservation Board model when they developed regulatory systems for their emerging petroleum industries.
Thus, at the end of World War II Calgary had the corporate, production and regulatory expertise a petroleum centre needs. Problem was, there wasn’t much to produce. As the year 1947 began, Canada produced an estimated 15,000 barrels of oil per day, and 115 million cubic feet per day of gas. Even though Alberta was a small producer, it was already the source of most Canadian production.
It was clear that western Canada had potential, and Amoco actually performed a seismic test in Saskatchewan immediately after the war.
Seismology originated in part with defense technologies developed in Germany during World War II. When the fighting was over, the oil and gas industry began experimenting with seismic readings as an exploration tool.
One of Amoco’s first tests was in Saskatchewan’s Dirt Hills, south of Moose Jaw. Surface geology suggested there was a large anticline — a prime target for exploration — at that location. Amoco decided to see whether seismology could prove that geological theory. In fact, the structure turned out to be a huge mound of glacial till. The primitive seismic readings were therefore indecipherable. Amoco continued the seismology experiments in Kansas, however, with considerable success.
The geological clue to most of Alberta’s big fields came in early 1947, when Imperial Oil’s Leduc #1 well — drilled just south of Edmonton — came in. From the Leduc discovery, Canada’s petroleum industry learned that coral reefs from a warm Devonian sea had become prolific oil reservoirs. Thus, the birth of Canada’s modern oil industry can be given precisely: 6:10 p.m., on February 13th, 1947. That is when Alberta’s Minister of Mines and Minerals, Nathan Tanner, turned a valve to bring the first Leduc oil on production.
Word of the Leduc discovery traveled quickly around the petroleum world, especially in the United States. The result was an influx of companies wanting to explore western Canada.
In September, Amoco sent Gene Hughes, a promising young employee with an accounting background, to Calgary to investigate activity in Alberta. He spent several weeks on reconnaissance before returning to Tulsa. His report recommended that the corporation begin exploration in Canada. In December, Stanolind’s board made the decision to set up an office in Calgary.
The company acted quickly. Three hundred and fifty-five days after the modern era began (and ninety years after the seminal Oil Springs, Ontario discovery,) Amoco began operations in Canada. The event was a modest one. After train rides respectively from Oklahoma and Wyoming, office manager Gene Hughes and landman Willard Longshore set up shop in Palliser Hotel on February 3, 1948. A month later they moved into 2500 square feet of space in a building that eventually became downtown Calgary’s trendy Penny Lane shopping centre.
Amoco was one of the first large companies to arrive in Canada in the post-Leduc environment. The Canadian operation was the corporation’s first post-war exploration venture outside the United States.
During the company’s first four years in Canada, Alberta became one of the most active (and attractive) exploration regions in the world. The company’s competitors discovered six large new oil fields — Redwater, Golden Spike, Wizard Lake, Fenn Big Valley, Bonnie Glen and Westerose — to feed Interprovincial Pipeline, which began shipping oil to eastern markets in 1950. The industry also discovered some important gas fields, which mostly went unconnected until the late 1950s.
While Amoco arrived early, the company nonetheless missed out on the great land rush that followed Leduc. Industry players (including many speculators) had already snapped up the large parcels of mineral rights in the north-central Alberta reef trend that had yielded Leduc.
Amoco landmen were accustomed to acquiring small, freehold parcels of land. Initially, they applied this strategy within Alberta. However, they soon recognized the potential of acquiring land reservations from the provinces. By this time, however, large parcels were only available to the west and north of Alberta’s reef trend — areas that were largely unexplored.
These developments had two important implications. First, they meant Amoco would not be a player in north-central Alberta without first negotiating partnerships (“farm-ins”) with other companies. Second, they meant the company would need to explore for new types of play in what proved to be bountiful wildcat country.
The fact that Amoco was not part of the reef plays of central Alberta helps explain the company’s severe run of bad luck between 1948 and the end of 1952. Much of the company’s drilling would take place in rank wildcat country, where geological strata were poorly understood. Geologists would have to learn on the job.
The company drilled two gas wells. But while both had good potential, Alberta’s gas markets were glutted. The company shut them in. The search in western Canada was for oil.
The company also drilled a small, uneconomic heavy oil well near the northern Alberta village of Barrhead. Before the well was abandoned, an Amoco employee offered production from the well to the town for oiling the village’s dry, dusty dirt and gravel streets. Neither employee nor townspeople were very knowledgeable about the properties of heavy oil. The community accepted the offer gratefully — until residents began tracking the black, thick, viscous goo into their homes and buildings. Like it or not, this sorry mess was the outcome of Amoco’s first oil production in Canada.
Amoco’s other drilling yielded nothing. Thus, Amoco’s early “discoveries” were little better than expensive dry holes. The score as the year 1952 drew to a close consisted of two suspended gas discoveries, the abandoned heavy oil well at Barrhead, and 27 dry holes.
The tide turned when the company’s St. Albert well on the outskirts of Edmonton found oil. A Devonian reef discovery like Leduc, St. Albert was Amoco Canada’s first producing oil well. It soon went on production at 1328 barrels of light oil per day. And in 1953, the company made another important Devonian discovery southwest of Edmonton, at Pigeon Lake. Thus, as the year drew to a close, the company was in business.
Another company was also in business — one that would play a huge role in the Amoco story. Just after the Leduc discovery, Imperial had repatriated to Alberta a young geologist named Jack Gallagher. Gallagher had begun his career in western Canada before gaining international experience with the company’s majority shareholder, Standard Oil of New Jersey (now Exxon).
In 1950, he found US financing to start an independent oil company, which he first served as executive vice president. The company was Dome Exploration (Western) Limited. By the end of the year, Gallagher had invested more than $6 million in oil and gas leases and more than $600,000 on development. Dome was already producing from six sections of land in the expanding Redwater oil field. His company had enough cash flow to finance growth.
Having been transformed by agile management and visionary strategies, thirty-five years later Dome Petroleum would be — in terms of assets — the largest exploration and production company in Canada. But the company was also paying high interest rates on the huge debt load that resulted from a string of acquisitions. To make matters worse, oil and gas prices were declining and would soon collapse. Thus, Dome became a financial basket-case in need of rescue.
Amoco’s 1988 acquisition of the troubled company would consummate one of the most dramatic corporate engagements in Canadian history. By interweaving parts of Dome’s story with Amoco Canada’s, this history will offer a broad picture of the Canadian petroleum industry’s modern era. This approach will also present more complete background on the company’s present-day operations.
2. Building an Oil Business
Photographs: Pembian rig and batteries; early camp; hamlet of Drayton Valley, 1953; Swan Hills oil field (1970)
Sidebars: Jeannette Vatter, Jim Griffith
Although Amoco’s early years in Canada were disappointing in terms of discovery, after a sluggish start they became years in which the company positioned itself for growth by acquiring large land positions throughout Alberta. The availability of prospective land was one of western Canada’s feature attractions.
Roughly 85 per cent of the mineral rights in Alberta are owned by the provincial government (often referred to as the Crown). The rest are owned by railroads, by private landowners and by a clutch of other interests.
Amoco’s priority was to build a land base. One way to do so was to apply directly to Alberta’s Department of Mines and Minerals (today Alberta Energy) for land reservations. Companies received these rights in exchange for work commitments — typically, the agreement to invest in a standard program of geological surface work, subsurface work, seismic exploration and drilling. Once they began to develop oil or gas fields on these lands, companies had to return the unexplored portions to the Crown.
At the time, Alberta law limited each company to two land reservations of 100,000 acres each. As a result, the nameplates of a flock of new Amoco subsidiaries soon graced the division office’s door. Amoco’s subsidiaries included Winter Oil Company and Muskeg Oil Company which, when merged into Amoco Canada in 1969, had substantial producing assets.
Another way to build a large land base was to negotiate farm-ins (partnerships) on the desirable holdings of other companies. The discovery that made Amoco a serious player in Canada was a farm-in on land held by Hudson’s Bay Oil and Gas — another company that, 30 years later, would play a critical role in the Amoco story.
Indirectly, the HBOG (pronounced H’-bog) chronicles go back to the earliest years of contact between Europe and the indigenous peoples of western Canada — specifically, to King Charles II’s grant in 1670 of a royal charter for the Hudson’s Bay Company. The Bay, as it is known, is the oldest corporation in North America.
Until the 1860s, the Bay’s charter gave it claim to most of the land that eventually became the prairie provinces and the Northwest Territories. In 1869 Hudson’s Bay Company sold Canada its claim to Rupertsland, as it was then known, but retained title (including mineral rights) to 7.5 million acres of land.
Those lands were included in the surveying grid that the Dominion government authorized in preparation for the settlement of western Canada. And they were distributed at regular intervals between Winnipeg and the Rocky Mountains. Accordingly, they played a role in a number of pre-Depression Alberta oil and gas discoveries. The most important of these was Turner Valley.
In 1926, a partnership between the Bay and US-based Marland Oils led to the creation of Hudson’s Bay Oil and Gas Company Limited. HBOG received the option (eventually extended until December 31, 1999) to drill the Bay’s remaining 4.6 million acres.
In 1973, Siebens Oil and Gas Ltd., an independent Calgary-based producer, purchased the Bay’s mineral rights outright. As a result, HBOG’s option agreement was with Siebens rather than the Bay.
Those historic lands became part of the Amoco heritage through Amoco’s acquisition of Dome. During its period of rapid growth, Dome took over both Siebens and HBOG. But while these properties have unusual historical significance, they played a relatively minor role in the farm-in that proved to be the company-maker for Amoco Canada.
In 1954, Amoco drilled the Stanolind-Hudson’s Bay Pembina Crown D No. 1 well near the 75-person hamlet of Drayton Valley. The well location was southwest of Edmonton, on Crown land owned by HBOG. Amoco began drilling after signing a farm-in agreement for a 50 per cent interest in this property. The terms were simple: To earn its interest, Amoco had to spend $100,000 on geophysical work, and spend $300,000 drilling three wells to Devonian targets.
Amoco Canada brought in the #1 well on March 6, 1954. It was the most important in the company’s history.
To reach Devonian prospects, which are roughly 350 to 400 million years old, it is necessary to drill through more recent layers of sedimentary rock. The geological names for more recent hydrocarbon-bearing periods are (beginning with the oldest) Carboniferous, Permian, Triassic, Jurassic and Cretaceous.
A funny thing happened when Pembina Crown D. #1 entered the Cretaceous, which dates back 136 million to 65 million years. The well encountered a thick sandstone formation saturated with oil. The oil did not flow, but there was clearly a lot of it there. Amoco had drilled into what geologists call a supergiant reservoir. This was the Pembina field, Canada’s largest and one of the largest in North America — in fact, in terms of area it was until the late 1960s the largest oil field in the world. And the acreage the company shared with HBOG contained roughly half the total reservoir.
The company began developing the field quickly. A work force of 45 soon kept 18 drilling rigs running at top speed. They would drill some 600 wells the first year.
Another company, Mobil, had drilled into the Pembina field in 1953, so Amoco has no claims to discovery. However, in the field’s first years it was Amoco technology that offered the only practical way to produce it.
Pembina’s Cardium reservoir had a characteristic different from that being encountered in Devonian reefs. The permeability of the sandstone formation rock was low; thus, oil would not flow freely into the well. In fact, the permeability at Pembina is so poor that some earlier drillers had actually drilled through the reservoir without being aware of the volumes of oil in place.
But in the late ‘40s, Amoco had developed and patented a hydraulic fracturing technology — “Hydrafrac” — in Tulsa research labs. The technique consists of pumping a mixture of oil and sand into the well formation at very high pressures. This creates hairline fractures in the rock formation, which the grains of sand prop open. The result is sustained production as oil flows into the wellbore.
While Canadians have used Hydrafrac technology countless times since the Pembina discovery, it was first used in Canada on that field. And it unlocked an abundance of hydrocarbon riches.
In those early years, no one could have imagined the richness of that discovery. Drilling eventually proved the field to be 65 kilometres wide by about 100 kilometres long. And today, 44 years after Amoco’s well went on production, more than 100 companies hold interests in the field. Some 5,000 wells still produce oil and gas, which flow into 900-plus production facilities. This mighty reservoir has produced nearly 1.5 billion barrels already, and perhaps 300 million barrels remain to be produced (with existing technology).
By 1957, Pembina was producing more than 3 million barrels per year for the company. Those volumes made it the fifth largest producing oil field in the Amoco world — yet it would not reach peak productive capacity for another 15 years.
The impact of Pembina on Drayton Valley and other nearby hamlets was immense. The local economy had been built on trapping and some logging (with the logs floated downstream during the summer months). In addition, a few settlers armed with axes, plows and stubborn courage had cut fields for agriculture out of the area’s seemingly endless subalpine forests.
Infrastructure was, in a word, primitive. In 1954 there was one telephone in the village. The hamlet itself was a score of weathered buildings along a kilometre of rutted dirt road — a road that rattled another 50 kilometres to the Edmonton highway. Alberta’s capital city was roughly 125 kilometres away as the crow flies, but much farther for those traveling dirt and gravel roads.
When drilling and production operations were not frozen solid, they seemed to be drowning in a sea of mud. The mud was sometimes so pervasive that operators had to tend producing wells on horseback.
What happened in Drayton Valley in the years following the Pembina discovery is a story of rapid growth. And it is a story that can be told of many remote communities in western Canada as the industry developed large new oil and gas reserves.
Development outside the bald prairie followed a simple pattern. First, roads were constructed or improved, so rigs and equipment could get in and oil could be trucked out. Operations centres gradually became more than a trailer in a muddy waste. Production and processing facilities were installed in out-of-the-way places, and new pipelines began to deliver oil (and later, gas) to market. In most areas, trailers accommodated crews until houses were built, usually in the nearest hamlet. These activities created general prosperity and a tax base for rural municipalities.
The result? Prosperous, modern towns sprang up in previously unsettled areas. They housed stores, service stations and improving utilities, shops and yards for the industry’s suppliers, offices for regulators. Industry employees, who were now residents of these towns, frequently took lead roles in civic life. They often received financial help from Amoco and other employers as they led efforts to bring skating rinks, community halls and other amenities into existence. It was a remarkable period of prosperity and growth.
If the town of Drayton Valley exemplified Alberta’s hurly-burly growth of the 1950s, it was just one of many towns to do so. Amoco has played key roles in the civic, commercial and industrial lives of this town and many others since those boom years.
While Pembina was Amoco Canada’s most important field, the company made other oil discoveries during the decade. These included Giroux Lake in 1955, Silver Creek in 1957, Sarah Lake and Lobstick in 1959.
These were valuable discoveries, but they did not generate the excitement of another 1957 find. That field was Swan Hills, about 200 kilometres northwest of Edmonton. Home Oil Company drilled the discovery well, and Amoco sank a 2600-metre well on its own nearby acreage the following spring.
Amoco’s first Swan Hills well drilled into the Devonian reef reservoir and, when put on test, produced 2,568 barrels of oil per day. That is a huge flow: compare it to today’s average Alberta oil well, which produces about 30 barrels per day. To make matters better, Swan Hills oil is desirable light, sweet crude.
Although Swan Hills was more remote than Amoco’s other large early oil fields, it quickly became one of Canada’s largest-ever (at the time) industrial undertakings. And, of course, the hamlet of Swan Hills soon became a modern town.
Swan Hills did not require the intensive drilling needed at Pembina, because individual wells were much more productive. Nevertheless, the industry had drilled some 550 wells into the field by 1962, and found that it consisted of a north and a south pool. For maximum production efficiency, these pools were unitized into two different operating areas — that is, interests were combined in such a way that one company operated each pool on behalf of those companies with interests in it.
With a 45 per cent interest, Amoco operated the south unit. The company had already introduced a waterflood operation, by which injected water was used to increase oil production. Home Oil operated the north unit, in which Amoco had a 14 per cent interest.
Swan Hills has since proved to be Canada’s third largest oil field. It has produced more than 800 million barrels of oil.
By 1963, one decade after the company’s first Canadian oil discovery, Amoco Canada was producing more than 27,000 barrels of oil per day — four per cent of Canada’s total. And the 15-year-old company represented about 5 per cent of Amoco’s world-wide assets.
The most important of those assets were exploration acreage (12.1 million acres under lease or reservation) and the large and growing oil fields they contained. However, the company had already begun to build what would eventually become Canada’s largest natural gas business.
3. Natural Gas Comes into its Own
Photographs: Plant construction; exterior shot prior to opening; new Amoco-constructed bridge over Athabasca River; East Crossfield plant (1966)
Sidebars: George Goss, Don Smith (photo and cartoon)
Although oil and gas are energy commodities, for most of this century Canadian governments have treated them differently. Except for the twelve years beginning in 1973 (a period of apparent energy crisis), oil exports have not been subject to export restrictions.
By contrast, Canadians have generally viewed natural gas in a restrictive way — probably because it is a premium fuel for space heating in a large, cold country. As early as 1901, Ontario concerns about resource depletion led to consumers in Windsor successfully petitioning the Dominion government to prohibit the export of natural gas to the Detroit area. This happened again a few years later, in respect to gas exports from the Niagara area to Buffalo. Canadian gas exports did not resume for nearly 50 years — until Alberta gas was exported to Montana to meet industrial needs related to the Korean War.
As exploration boomed after 1947, it rapidly became clear that oil and gas were both abundant in western Canada. In 1948 the province appointed a Natural Gas Commission to recommend how much of this strategic commodity should be considered surplus to Alberta’s needs. After frequently vociferous debate, the commission suggested that the province might be justified in refusing gas export licenses until the province had a 50-year supply in hand.
Alberta then gave authority to the Alberta Oil and Gas Conservation Board to regulate exports and to decide on necessary reserves. The board made provisions for 25-year inventories (“reserves”) of gas as a requisite for export licenses. After receiving its regulatory mandate in 1959, the National Energy Board (NEB) also adopted this practice.
Yet there was so much natural gas in Alberta that it sold for pennies per thousand cubic feet. To make the business economic, pipelines were desperately needed. But reserves development, regulatory concerns (expressed by both Canadian and US agencies), territoriality issues (whether a pipeline to eastern Canada should cross US soil) and haggling among pipeline project consortia meant delay after delay in construction approval.
These obstacles overcome and construction complete, in 1957 Westcoast Transmission and TransCanada PipeLines both began piping gas. Together, they formed the nucleus of Canada’s export pipeline infrastructure: westwards to the lower mainland of BC and the US Pacific Northwest, and eastwards to Manitoba, Ontario and Quebec and to adjacent areas of the United States. That system today includes only three additional major export pipelines from western Canada, but it delivers nearly 30 times as much gas.
With the vantage of hindsight, it is obvious that Amoco was well positioned to grasp the prize offered by a rapidly expanding gas market. Some of the company’s oil reservoirs had a gas component (often reinjected into the reservoir as part of good field management). In addition, Amoco had made important stand-alone gas discoveries.
A number of Amoco’s prime early gas discoveries were in large reservations primarily held by HBOG. Amoco farmed into these lands after chief geophysicist Bill Matthews studied a regional geophysical line and saw evidence of what geoscientists call “pull-up.”
This probably meant there were large structures in the area, so Matthews proposed that Amoco try to gain entry in the area. Division manager George Galloway obliged by arranging the necessary farm-ins. These lands soon began proving to be very prospective indeed. Today they include key operations.
The first of these discoveries came at Whitecourt, some 250 kilometres west by northwest of Edmonton, in 1955. The nearby Pine Creek well was drilled two years later. Amoco held a 42 per cent interest in 1.1 million acres in this area.
Discoveries were coming in fast and furious. In 1957 alone, Amoco drilled 23 wildcat wells. Six of these came in as gas discoveries, two as oil. During those years, exploration and discovery were migrating ever farther north. Amoco’s exploration crews and supplies began traveling into the north country by a busy fleet of small company planes, the first of which took off in 1955.
During those pioneering years, the company reported some spectacular finds. In 1960, for example, the company reported two discoveries in northeast British Columbia (near the border with the Northwest Territories). One of those holes — the Beaver River discovery — tested natural gas at more than 200 million cubic feet per day. That is a monster well by any standard. When the field went on production, thermal expansion caused by the heat from the immense gas flow caused Beaver River wellheads to rise two metres or more.
But having the gas in the ground was just the beginning. It was important to process the stuff so it could be piped to market.
Gas processing has a variety of functions. At the very simplest, processing systems separate gas from oil production. When gas comes up with crude oil, it is generally separated out and pumped back into the reservoir. This is because the high-pressure gas cap in the reservoir helps drive the oil toward the wellbore. To get the most oil out of a reservoir, recycling the natural gas is essential. In the ‘50s, when Amoco focused on developing oil fields, this kind of gas processing was simply part of oil production.
At Swan Hills and other fields, the company removed the light hydrocarbons known as condensate (in Alberta often called pentanes plus) from the gas before reinjection. In the early days, condensate — so called because it condenses out of some gas streams — was treated simply as a form of very light crude oil. This was Amoco Canada’s earliest production of natural gas liquids, a range of commodities that also includes ethane, butane and propane. Liquids later became a critical part of the company’s business.
A second form of gas processing involves removing water and other simple impurities from natural gas. After this minimal processing, the gas can be piped to market. The company’s first gas sales had been processed in this uncomplicated way.
The third form of processing involves removing natural gas liquids and sulphur (in addition to other impurities) from natural gas. For Amoco Canada, this kind of processing represented huge technical challenges. But it also presented enormous commercial opportunities.
The reason is that so many of Canada’s very large gas fields are wet and sour. Wet means they contain large proportions of natural gas liquids. Sour means they contain hydrogen sulphide, a chemical that is fatal in concentrations as low as 350 parts per million. Processing wet, sour natural gas therefore results in marketable natural gas plus natural gas liquids and elemental sulphur.
While many of Amoco’s early gas discoveries were wet and sour, the most important of them all was Whitecourt. The company began planning the West Whitecourt gas plant in 1957. Those plans took three years and thousands of pages of specifications to complete, but the hard job started when construction began.
The only bridge across the Athabasca River to the plant site was not strong enough to bear heavy loads. So the heaviest equipment had to be brought across the ice in midwinter, when the river was frozen. One 120-ton tower did not arrive on schedule, so the contractor dammed the river to get it across.
And on the other side of the Athabasca, a 60-kilometre dirt road meant slow and treacherous progress for the big trucks. To make matters worse, a colony of beavers repeatedly dammed a culvert, flooding the road. The battle lasted all summer long.
When the plant started up in late 1961, there were bugs in the system. This was not particularly surprising then, just as it would not be today. So the company made a number of modifications to the plant, which passed its final performance tests in late 1962. When it then went on stream, West Whitecourt quickly reached its planned production levels.
In those days, West Whitecourt boasted the biggest volumes of condensate production in Canada (13,000 barrels per day) and the largest sulphur production (650 long tons per day). And it was number three in gas-handling capacity (177 million cubic feet per day). While bigger plants have since made the records of 1962 seem relatively small, West Whitecourt was nonetheless an industry pioneer.
When the plant first went on line, Amoco people were not sure whether available gas supplies would keep it running for more than five to 10 years. More than 35 years later, the expanded sour gas plant (its capacity at year end 1997 was 220 million cubic feet per day) is still operating at high levels. In 1996 the company added facilities to process an additional 50 million cubic feet per day from sweet gas reservoirs.
The Whitecourt venture put the company at the leading edge of sour gas processing technology. Among the plant’s unsung achievements, it applied technology that has since helped make Canada a world leader in sulphur-recovery systems. Many years later, Amoco would make another major contribution to that technology with the development of the Cold Bed Absorption Process. That process could extract more than 99 per cent of the hydrogen sulphide from a gas stream — a major technical advance. (The hydrogen sulphide is then further processed into elemental sulphur.)
Whitecourt’s sulphur plant was owned by Texas Gulf Corporation, a US firm interested in marketing the sulphur. Thus, while Amoco produced sulphur at Whitecourt, the company was initially not involved in sales. This changed when Amoco’s Crossfield plant went on stream in 1968. The company has since developed a world-class sulphur business.
Sulphur is primarily used in the manufacture of fertilizer. However, it also has a huge range of uses in the manufacture of plastics, petrochemicals and pharmaceuticals. Since an unusually large number of Alberta’s gas reservoirs contain sour gas, Amoco needed to construct sulphur plants at virtually every large gas plant.
Today, Amoco is Canada’s second largest producer and marketer of this commodity. The company produces 650,000 tonnes of sulphur per year. Amoco markets about 1 million tonnes per year, however — approximately 12 per cent of Canadian production. About 60 per cent of these sales go overseas. To put these numbers in perspective, Canada is the world’s largest producer of elemental sulphur from natural gas, and the world’s largest sulphur exporter.
In October 1961, Amoco Corporation acquired a company with large Canadian holdings. The purchase of Honolulu Oil Corporation increased Amoco Canada’s assets by 132 net wells, nearly 2.5 million acres of land and five gas processing plants.
During the decade that followed West Whitecourt, the company wrote natural gas sales contracts for trillions of cubic feet of natural gas. For example, the company agreed in 1965 to furnish TransCanada PipeLines with 1.8 trillion cubic feet of gas over a 25-year period, and in 1969 with another 2 trillion on the same terms. In 1966, Amoco agreed to provide Westcoast Transmission with 1.5 trillion cubic feet. The company signed numerous other (smaller) contracts during the decade. In those days, when gas deregulation was not even a gleam in an economist’s eye, pipelines provided both transportation and marketing services.
Construction of new plants made these natural gas sales possible. By 1973, Amoco Canada had built or taken a position in most of the plants that today make up the backbone of the company’s gas-processing infrastructure. These included relatively large plants at East Crossfield, Bigstone, Beaver River, Pointed Mountain, Marten Hills and Ricinus. Amoco also had working interests in major plants at Judy Creek and Kaybob.
Smaller plants went up at Waskahigan, Berrymoor, Bigoray, Lobstick, Three Hills Creek and East Crossfield Elkton.
In the industry’s early days, propane and butane — very light hydrocarbons — were often reinjected into the well, like natural gas. Amoco’s biggest plants had extraction facilities for condensate (a mix of natural gas liquids, or NGLs), which is sold as a very light crude oil. By the mid-1960s, the company could see that liquids production would continue to increase, and that NGL production could become an important business. For that to happen, new markets were essential. So was better infrastructure.
As the 1970s began, a liquids handling system was delivering natural gas liquids to a Dome/Amoco fractionation plant in Sarnia, Ontario. But that early operation was small. If it represented the footings, the company would soon begin to erect the foundations of a world-class liquids enterprise.
4. A Blueprint for Liquids
Map: NGL system
Photos: Fort Saskatchewan de-propanizer (1983); Sarnia plant (slide)
Sidebars: Tom Classen, Doug Dieno
Headquarters for Amoco Corporation have long been in Chicago, because that great midwestern city is close to Whiting, Indiana.
Whiting is home of Amoco’s largest refinery (and one of the largest in the world). In operation since 1890, Whiting originally refined sour oil from the neighbouring state of Ohio. And it was Standard of Indiana’s (Amoco’s) most important single asset after the US Supreme Court ordered Standard Oil broken up. In its early years, Amoco was primarily a refiner and a marketer of refined products to expanding midwestern markets. Whiting provided products that could be marketed from nearby Chicago — a city that was growing like Topsy and was itself a large market for petroleum products.
By 1970, Amoco had become one of the largest integrated oil corporations in the world through both acquisitions and internal growth. Besides being a large-scale refiner and distributor of refined products, it was a powerful force in petrochemicals, oil and gas exploration and production, pipelines, and in the marketing of oil, natural gas and natural gas liquids (NGLs).
The corporation was growing globally, but it was heavily focused in North America. And though its oil and gas activity was concentrated in the US southwest and in western Canada, its marketing presence was still strongest in the Midwest. From its Chicago base, the corporation had unrivaled intelligence about hydrocarbon demand in the US Midwest.
To understand the development of Amoco’s natural gas liquids business, this background is essential. While Amoco Canada’s liquids marketing group had a great deal of independence in the early years, many synergies were possible through cooperation between Chicago and Calgary.
Equally essential, however, is to understand that Amoco and Dome formed a number of strategic partnerships in the liquids business during the 1960s. So extensive were those partnerships that, when Dome went on the block in 1986, it was inevitable that Amoco would be an aggressive suitor.
But this anticipates later events.
Alberta’s liquids business dates to the development of the Pembina field, when Dallas-based Goliad Oil and Gas received rights to recover solution gas from the field. Also known as “casing head gas” or “associated gas,” solution gas is dissolved in reservoir oil at underground pressures. Released under the relatively low pressures at Earth’s surface, it usually includes natural gas liquids. Often, as at Pembina, these can be profitably extracted. While Goliad received the gas from Pembina, the separated liquids were returned to the producers.
At about the same time, Dome developed a solution gas gathering business at Steelman, Saskatchewan.
As plants like Whitecourt began processing Alberta’s liquids-rich gas during the 1960s, NGL production volumes rapidly increased.
Separated from a gas stream, NGLs are an undifferentiated batch of light hydrocarbons — ethane, propane, butane and condensate. To separate them into more valuable individual products requires fractionation facilities. Fractionation towers separate a stream of mixed NGL feedstock into specification-grade ethane, propane, butanes and condensate products.
Distillation is the process used to fractionate NGLs. The different components in a liquids mix evaporate at different temperatures. Thus, when heat is applied to a stream of product entering a fractionation tower, lighter components vapourize and move to the top of the tower; heavier components drop to the bottom. The amount of heat applied to the brew depends on which component is being separated out for sale to the customer.
The lighter product coming off the top of the tower as a vapour — called the overhead product — is then cooled so it will condense back into a liquid. To achieve full separation, a stream of product is processed through a series of towers. “Spec” or high-grade product is taken off the top of a tower, and the bottom product becomes the feedstock for the next tower.
In the mid-1960s, there were only two fractionation facilities in Alberta. One was a plant at Devon, owned by Imperial Oil. That facility processed liquids from Leduc, Redwater and other Imperial-operated fields. Later, it also processed liquids from Swan Hills, which was operated by other companies. The reason is that in 1964 Imperial had constructed a plant for solution gas/liquids extraction to service Judy Creek, Swan Hills and other area fields.
Originally, Hudson’s Bay Oil and Gas had applied to construct, operate and own that plant. Imperial then made a proposal of its own. Amoco and British American (B/A; later Gulf Canada) intervened at an Oil and Gas Conservation Board hearing with a proposal that would give all operators a share of the plant. Under pressure from the Amoco/BA plan, Imperial modified its proposal and was awarded the project. As a result of the Amoco/BA intervention, Imperial became operator, but Amoco and the other producers were partners.
Because Amoco would soon begin to receive its considerable liquids from Swan Hills in kind, the need to find ways to get optimum value from these liquids was clear. Markets in western Canada could not absorb the large and growing liquids volumes that Alberta was producing. However, markets in central Canada and the US Midwest could. Working with Chicago, Amoco began developing a marketing strategy — a critical part of which would be the delivery system.
Dome had built the other fractionation plant, known as the Edmonton Liquid Gas Plant, in 1962. As Amoco made plans to build liquids as a business, in 1967 the company bought a half interest in this facility. This arrangement was the beginning of a series of liquids-related deals that would soon see Amoco and Dome partnering to become the largest players in Canada’s NGLs business.
Another Amoco/Dome joint venture soon followed. At the end of the ‘60s, Alberta and Southern Gas Company began building a larger plant at Cochrane, a small town just west of Calgary. In industry parlance, this was a straddle plant. Another step in the development of the Amoco/Dome liquids system was Dome’s construction — in 1976 — of the Edmonton Ethane Extraction Plant. This straddle plant replaced an earlier facility.
Straddle plants extract ethane and heavier liquids from the gas stream, returning drier gas (by now almost entirely methane) to the pipeline. Liquids fetch a higher price (relative to their energy or BTU content) because they have uses other than firing furnaces — as gasoline additives and petrochemical feedstocks, for example.
While plant construction was underway, Dome and Amoco built a 320-kilometre pipeline from Cochrane to Edmonton (the Co-Ed line), with Dome as operator. This line fed liquids to Dome/Amoco’s new Fort Saskatchewan liquids terminal, and helped the company develop expertise in pipeline operations. Other Dome- and Amoco-operated lines were soon delivering NGLs to the Fort Saskatchewan plant.
Built in the early 1970s, Fort Saskatchewan supplemented the Edmonton Liquid Gas Plant. Key to the plant’s success was the existence underground of large salt formations. The operator was able to dissolve (“wash”) huge storage caverns in these formations. Those caverns provided large volumes of inexpensive, safe inventory capacity for the plant. Having storage capacity for NGLs enabled the company to buy and store surplus NGLs year round, including times when markets were soft and prices dropped to seasonal lows.
The Dome-operated plant quickly became a hub of western Canada’s liquids business. The reason is that Amoco and Dome created a partnership to do something that had never been tried before, anywhere. Using Fort Saskatchewan as a staging point, they batched natural gas liquids through Interprovincial’s oil pipeline to Sarnia, Ontario. In 1980, the partnership added fractionation facilities at Fort Saskatchewan.
The impact of this arrangement on the transportation economics of large volumes of NGL was considerable. To send propane that distance by rail at the time cost $3.50-$4.20 per barrel. Batching the stuff through Amoco/Dome facilities and IPL brought transportation costs down to approximately $1 per barrel.
Liquefied petroleum gases (or LPGs, another name for propane and butane) have to be contained well above atmospheric pressure to remain in liquid form. The partners therefore had to build special “breakout” facilities in Superior, Wisconsin, to enable this operation to work. They also had to construct batch receipt facilities, storage, and a fractionation plant at Sarnia. That plant went on stream in 1970.
Sarnia was chosen for several reasons. Most importantly, of course, it is the terminus of Interprovincial Pipeline’s main lines. The city itself is a big part of central Canada’s petroleum market.
Near the 1857 Oil Springs discovery, Sarnia became a refining centre during Ontario’s 19th century oil boom and a petrochemical centre during World War II. Sarnia has underground salt formations like those at Fort Saskatchewan. Caverns washed into those formations were used to receive NGL from IPL, and to store specification grade products to meet seasonal demand.
From the Sarnia plant, Amoco and Dome could meet regional requirements for liquids by rail, water and road links to central Canada and the US Midwest. (Also, of course, pipelines were constructed to local petrochemical plants.) Thus, Sarnia had the essential infrastructure for a successful marketing operation.
Initially, the plant was small. Daily capacity was 17,500 barrels of liquefied petroleum gases (propane and butane), and 12,500 barrels of condensate and crude oil. It grew quickly, however: salt storage caverns were soon added, and a 1974 expansion of the fractionation plant increased NGL processing capacity to nearly 50,000 barrels per day.
The early growth of Amoco’s liquids business was astonishing. By 1970 Amoco Canada’s NGL production had reached 25,000 barrels per day. Amoco Corporation’s North American liquids operations processed 2.9 billion cubic feet of gas per day to produce 105,000 barrels of liquids. Those volumes represented about 4 per cent of North America’s gas processing capacity, 5 per cent of the continent’s liquids capacity.
As Amoco prepared to increase market share for liquids in the Midwest, its US liquids subsidiary — Tuloma Gas Products by name — moved headquarters from Tulsa to Chicago. Clearly, the business would grow through partnership between Calgary and Chicago.
During this early period of growth, several other developments are worth noting.
One was a project initiated by Dome to construct a liquids recovery plant — in effect, a very large straddle plant — at the Empress, Alberta, delivery point to the TransCanada transmission line. The Empress plant sits just inside the Alberta/Saskatchewan border, partly for political reasons.
During inquiries into natural gas exports in the 1950s, the ERCB recommended the creation of a province-wide natural gas gathering system.
The thinking behind this idea was two-fold: first, it would be more efficient to develop a single gathering system than to let gathering systems evolve piecemeal. Second, such a system would eliminate the possibility of federal regulation of gas within the province. Alberta was jealous of its hard-won control over natural resources and saw gas transportation within the province as an aspect of resource management. The province was also very conscious of the potential of natural gas and its products for provincial industrial development.
Accordingly, Alberta passed the Alberta Gas Trunk Line Act. Alberta Gas Trunk Line (today known as NOVA Corporation’s Gas Transmission Division) would gather gas within the province, delivering the commodity to federally regulated TransCanada PipeLines and other export pipelines just inside the Alberta border. Empress was the site at which TransCanada PipeLines would receive gas for delivery to eastern markets.
Pacific Petroleums (acquired by Petro-Canada) had already built a straddle plant at Empress to extract liquids, so Dome’s idea was not new. However, Dome built a much larger facility there. The facility was constructed on a patch of bald prairie in the early 1970s. The owners were Dome and a TransCanada subsidiary, which later sold its interest to PanCanadian Petroleums.
The NGLs recovered at the new Empress plant needed to be transported to market, and the largest markets continued to be in the US Midwest. So Dome built injection facilities at nearby Kerrobert, Saskatchewan. Those facilities enabled Dome to inject additional liquids into the batches that were flowing from Fort Saskatchewan through Interprovincial Pipeline.
At the same time the team of Dow Chemicals, Nova and Dome put together the Alberta Ethane Project. This plan was essentially a $1.5 billion blueprint for the creation of a petrochemicals business in Alberta based on natural gas liquids, especially ethane. And the plan took on a political life of its own, since it offered the opportunity for value-added products to be manufactured in Alberta for export. The provincial government stood four-square behind it.
The plan consisted of four components. The straddle plants at Empress were the first.
The second was a petrochemical complex at Joffre — a village near the city of Red Deer — to convert ethane to the petrochemical feedstock ethylene. This would form the basis for a petrochemical manufacturing centre. That centre grew dramatically during the decades that followed. By the late 1990s, ten large-scale petrochemical plants were operating or under development there.
A third component was the Alberta Ethane Gathering System (AEGS,) which would deliver ethane from Alberta straddle plants to storage caverns at Fort Saskatchewan. This system would include a reversible connection to the Joffre petrochemical complex. In addition, one leg of the AEGS pipeline would connect Empress, which would soon become the largest gas processing centre in the world.
The fourth component was the Cochin Pipeline, which would ship ethylene from Alberta to Sarnia, and would also export ethane and propane to the US. The world’s longest NGL pipeline went on stream in 1978. Amoco had the opportunity to participate in this venture, but chose not to do so. (There is irony in this, since Amoco became operator of both the Cochin pipeline and Empress after the acquisition of Dome.)
To complete the picture of the making of Amoco’s Canadian liquids business, it is worth noting that in 1977 Amoco and Dome bought the Canadian assets of Goliad Oil and Gas Company. This increased the supply of liquids available to Amoco by about 1800 barrels per day. But this acquisition also had symbolic importance, since Goliad had such a key role in the early liquids business.
Although not primarily related to the liquids business, the merger with Dome brought Amoco another large transportation system. The Rangeland Pipeline, which was originally developed by Hudson’s Bay Oil and Gas, moves about 130,000 barrels of oil per day. Because the company developed pipeline expertise primarily through the liquids business, the line is operated by Amoco’s liquids organization.
While Amoco and Dome were the lead players in developing Canada’s liquids industry, neither company neglected exploration, development and production operations. Both companies helped pioneer conventional exploration and production in western Canada during the ‘50s and ‘60s. Beginning in the ‘60s, they were also pioneers in Canada’s geographic and technological frontiers.
5. The Geographic and Technological Frontiers
Photographs: Early wellsite office; service vessel approaching Glomar rig at Tors Cove well; refrigerated conductor pipe in high arctic; seismic shooting.
Sidebars: Leroy Field; Letter from W.H. Girling of Consumer’s Gas.
For its first century, the world’s petroleum industry produced almost exclusively from temperate and tropical regions. Once large-scale development began in western Canada, however, the industry had to develop cold-weather exploration, development and production technologies.
This often involved turning winter cold to advantage. For example, the industry began using freeze-up for access to the northern reaches of Alberta and British Columbia and for the Territories. The industry’s key drilling season became winter, when rigs can be transported and erected in swampy northern muskeg without getting stuck.
While winter freeze-up made access possible for heavy loads, crossing streams and rivers was problematic. Left to themselves, natural waterways took a while to develop the strength to bear heavily laden trucks. So companies began flooding the lightly-frozen surfaces of rivers, streams and lakes with water. In this way they could increase ice thickness by metres, creating strong driving surfaces for heavy trucks and equipment.
Companies also developed production, processing and pipeline technologies that could withstand extremes of heat and cold.
The extraordinary diversity of Canada’s petroleum resources and sedimentary basins also called for innovation. The growing industry had to develop new production technologies for Alberta’s enormous oil sands, for example. And drilling in the seasonally frozen Beaufort Sea, the permafrost areas of the Arctic Islands and offshore Newfoundland’s “iceberg alley” called for a clutch of new techniques.
Amoco helped pioneer technologies that have since helped make the Canadian petroleum industry perhaps the world’s most technically sophisticated.
Conventional Exploration
In Alberta and northeastern British Columbia, the company drilled numerous wildcats, making a number of important discoveries. In addition, however, Amoco participated in the development drilling that followed other discoveries. The following table shows the years of discovery and development of some key operations.
Table: Significant Discoveries
Year of Discovery Field Oil Gas Gas on Production
1952 St. Albert •
1954 Pembina Cardium •
1955 Whitecourt • 1961
1957 Pine Creek • 1961
1958 Swan Hills •
1958 Fox Creek (Kaybob South) • N/A
1958 Berland River • 1995
1960 Crossfield • 1968
1960 Kaybob South •
1960 Bigstone • 1968
1963 Pine Northwest • 1967
1965 Marten Hills • 1965
1965 Nipisi • • 1965
1965 Rainbow Lake • • 1965
1966 Pointed Mountain, NWT • 1968
1968 Ricinus • • 1972
1974 Leismer • 1978
1975 Elmworth • 1978
1977 Kirby • 1981
1978 Grande Prairie • • 1979
Especially during the 1950s and early 60s (when much of western Canada’s sedimentary geology was still largely unknown), exploration geologists did a great deal of surface field work in the remoter areas of Alberta and BC. A field crew might consist of two geologists supported by a wrangler and a packer, who looked after 18 horses and managed camp. Supplies were flown in from time to time, weather permitting. Home was a canvas tent, which was moved every few days. In the 1960s, helicopter transport began replacing pack horses.
This generation of explorers would examine exposed rocks to determine the direction of “strike” and “angle of dip” of rock strata. Guided by aerial photographs, they would use such simple tools as compasses, altimeters and binoculars to get a feel for the land. Hydrochloric acid was another essential part of field supplies. It would fizz and bubble on outcrops of limestone, which can form hydrocarbon reservoirs (Devonian reefs, for example) and is frequently associated with oil and gas in other ways.
Only the drill bit can prove up a discovery, of course. Each of Amoco Canada’s discoveries presented its own challenges, but their individual stories were similar. Someone — whether Amoco or a competitor — would drill a successful well. Amoco would then acquire offsetting acreage through land sales or negotiating a partnership deal. Additional wells to define the pool would follow. Then came development.
But there were marked differences between oil and gas development. Oil was more transportable and had a ready market. Sales contracts were also flexible. In the early days, companies wrote 30-day contracts with Imperial Oil for the oil production from a lease; renewal was generally automatic. Oil discoveries could therefore be developed quickly. For the most part, they went into production soon after discovery.
In contrast, gas development usually had to wait. It waited until the operator had defined sufficient reserves to justify a sales contract, until construction of a pipeline was justified, until provincial and federal regulators had completed their reviews, until gas marketing (which committed both parties for 25 years or more) was complete, and until a gas processing facility was ready. The development of natural gas was highly dependent on the field’s size and location. This was especially so when the gas was wet or sour.
Unfortunately, two Amoco wells from this era deserve special mention — not because they were technical successes (they were), but because they were drilling failures.
The first incident began at 4:45 p.m. on December 17, 1977. That is when an Amoco Pacific gas well at the important new Brazeau Devonian gas field (just west of Drayton Valley) blew out in -37o cold. The incident began as drillers were “tripping” — pulling the drill string from the hole. The well vented sour gas at such high pressures and volumes that it took nearly a month to bring the well under control.
Blowouts are uncommon, but hardly unknown in the petroleum industry. Nearly five years after the incident in 1977, another Amoco well blew out in the same field. This well was a major event for the natural gas industry — not just in Canada, but around the world. It took nearly two months to bring the blowout under control, and the process took the lives of two well control specialists. Sour gas can be smelled in minute quantities; in this instance the rotten egg odour was noticeable across a wide stretch of western Canada.
The second incident — they were both named after the nearby hamlet of Lodgepole — fundamentally affected the drilling and natural gas industries. An extended inquiry resulted in extensive new regulations for drilling contractors. These rules pertained to safe procedures for drilling sour wells and responding to sour gas blowouts. They addressed technical, environmental and public safety issues. The changes that came from Lodgepole were in everyone's best interest. Today, Alberta leads the world in safe sour gas drilling operations. And many of the regulations and practices resulting from the Lodgepole inquiry have been adapted for use around the world. Amoco fully supported the inquiry and the development of the new regulations.
The Frontiers
Apart from participating in technologies for cold-weather exploration and production in western Canada, Amoco helped pioneer exploration in Canada’s northern and offshore frontiers. The frontiers are the extensive sedimentary basins that ring the nation. They include the northern extension of the Western Canada Sedimentary Basin in the Territories, the Beaufort Sea and Arctic Islands, the offshore Atlantic in the east and offshore British Columbia in the west.
In the late 1960s, Amoco formed a partnership with Consumers Gas to drill gas wells in Lake Erie. The exploration program was successful, but Amoco sold its interests because the play was fairly small. Those wells were connected to the Consumers Gas distribution system in Ontario.
While production from a cold-water lake like Erie — albeit a very large one — presents distinct challenges, they are minor compared to those of Canada’s northern and offshore frontiers. In the north, Amoco acquired large land holdings in the southern portion of the Northwest Territories in 1959, and began drilling them shortly thereafter.
In 1964, Amoco acquired exploratory permits totaling 31 million acres on the Grand Banks off Newfoundland, and later augmented those holdings on the nearby Flemish Cap. By the end of the decade, Amoco had interests in 40 million acres off the east coast of Canada.
Starting in 1965, Amoco, Imperial Oil and US-based Skelly Oil carried out an extensive seismic and core-hole drilling program on these exploration properties. In one year alone, Amoco conducted nearly 7500 kilometres of offshore seismic. The company drilled two wells in the late ‘60s. One of these, Tors Cove, located a gas reservoir that — although not economic because of its offshore location — by land standards was exceptional. This was encouraging, and called for further drilling.
By 1971, the large Sedco I semi-submersible drilling vessel was testing the company’s offshore prospects. Amoco commissioned construction of this rig by awarding a two-year contract to drilling contractor Sedco in 1968. The vessel was built in Halifax and christened in December 1970. The company also contracted another drilling vessel, Sedneth, which began work in 1972.
But the Grand Banks were not kind to Amoco and partners. In 1971, the company drilled and abandoned three test holes. The following year another nine wells were abandoned, although two locations had non-commercial shows of oil and gas. The Puffin well located a 700-metre reservoir, according to one geologist, of “beautiful, clean sand.” The company may have found a supergiant structure — filled with one to two billion barrels of clear, fresh, potable water.
By the time the company suspended the Newfoundland exploration program in 1974, Amoco had invested nearly US$100 million in 32 dry holes. Amoco retained its offshore acreage for a few more years, but entirely withdrew from the area in 1977.
Amoco’s efforts were expensive by the standards of the day, and represented a major, sustained exploration effort off the east coast of North America. After the company left, other players continued to invest in the area, drilling another nine dry holes in the Grand Banks. Then, in 1979, a Chevron-operated well at Hibernia found a commercial field. Because of technical and jurisdictional disputes and project economics, bringing the 525 million barrel Hibernia field on stream would take nearly 20 years and cost more than $5 billion.
Although it would be another 20 years before Amoco would again become an operator in the offshore Atlantic, the company continued to participate in drilling in the area — including the Narwhal well in 1983/4. Drilled from a rig floating 1577 metres above the ocean floor, that well set a water depth record for Canada.
During these years, Hudson’s Bay Oil and Gas also participated in east coast drilling, including wells off Prince Edward Island and in the offshore Labrador Shelf.
In the Northwest Territories, Amoco discovered Pointed Mountain — the first producing gas pool in the Territories.
In the Mackenzie Delta — at the southern edge of the Beaufort Sea and 200 kilometres north of the Arctic Circle — the company drilled a number of wells. However, Amoco and others stopped exploration in this area when it became clear that project economics could not justify construction of a natural gas pipeline from the Delta to southern markets.
One of Amoco’s Delta wells, Inuvik A-1, is particularly noteworthy. One of the challenges of drilling in the far north is permafrost. Only a thin layer of the frozen soil ever melts, even under the summer’s midnight sun. However, when subjected to the circulation of drilling fluid, deeper melting occurs. And when this occurs, the permafrost upon which the drilling rig is sitting can become unstable. To prevent this, Amoco refrigerated the top 20 metres of the Inuvik hole during drilling. This 1969 innovation was almost certainly a first for Canadian Arctic drilling.
Dome Petroleum had been active in the far north since drilling an Arctic Islands well in 1962. And by the mid-1970s Dome was the undisputed leader in the Beaufort Sea.
Having acquired substantial acreage in the Beaufort, a Dome subsidiary, Canadian Marine Drilling Ltd. (CANMAR,) moved in a flotilla during the summer months of 1976. This fleet included three ice-reinforced drillships and a support fleet. Support craft included a supply freighter named CANMAR Carrier, four supply boats, a tugboat and barges.
In the 1977 Budget, the federal government introduced a superdepletion allowance of 120 per cent for the drilling of wells costing more than $5 million each — an immense incentive. The provision at the time applied generally to operations in the Beaufort, and Dome was doing all the drilling.
Over the next few years Dome would drill extensively in the Beaufort, with creditable results. The Beaufort Sea remains a geologically promising region, but one whose resources will not come on stream for some time to come.
Dome was a major participant in Panarctic Oils, an exploration company which, created in 1967, became operational in 1968. Dome, which had drilled the Winter Harbour well in Melville Island in the high Arctic in 1965, was the operator for Panarctic until 1970. In those early days, Panarctic staff were Dome employees.
Panarctic drilled most of the wells in the high Arctic, and found both gas and oil. In 1986, the company delivered a 100,000-barrel shipment of oil from the Bent Horn oil field on Cameron Island. Panarctic continued making regular deliveries of arctic oil for a decade.
This extraordinary exploration received encouragement from the government of Canada. The potential for economic development was one reason. Another reason, which in geopolitical terms was even more important, had to do with international relations. Federally regulated exploration in the high Arctic helped assert Canadian sovereignty over these remote islands.
Non-conventional Resources
As the frontiers required innovation and new technology, so did the oil sands and heavy oil deposits of western Canada.
Alberta’s oil sands — the four largest deposits are named Athabasca, Cold Lake, Peace River and Wabasca — are among the world’s great hydrocarbon resources. Underlying almost 700,000 square kilometres of northern Alberta, their immensity is hard to describe. These deposits plus the bitumen-drenched “carbonate triangle” associated with them contain nearly two trillion barrels of oil — several times the remaining reserves of the entire Middle East.
However, Canada’s oil sands are mostly resources, rather than reserves. The distinction is critical. It takes a combination of markets and technology to transform resources into reserves. Resources have an undefined economic value until they can be profitably produced. Not until they are realistically producible are they called reserves.
Efforts to develop these resources date back to the beginning of the century, but received a major boost in 1967 when Great Canadian Oil Sands (today Suncor Energy) opened a bitumen strip-mine and upgrader at a site just north of Fort McMurray. While this plant (and the Syncrude plant that opened up a decade later) solved the problem of how to recover surface deposits of oil, Amoco’s first attempt to develop new oil sands technology had deeper deposits as its target.
Long before the Great Canadian Oil Sands project went on stream, Amoco had been testing an entirely different production technique. In 1958, the company began a pilot project near Fort McMurray at Gregoire Lake on the Athabasca deposit. This facility tested in place (in situ) production techniques.
Partly as a result of this work, Amoco patented what became known as the COFCAW (“combination of forward combustion and waterflood”) production process. This technique involved simultaneously injecting air into the underground reservoir and igniting some of the bitumen with a chemical catalyst. The air would keep the fire burning, and the resulting heat would increase the reservoir formation’s temperature to 93o C. This heat would melt the oil, making it fluid enough to pump through a production well.
When the formation was hot enough, water was injected into the reservoir. This produced a complex set of drives, including forces from heat, gas and water that drove the hot, fluid oil into production wells.
Initial results from this pilot were promising. Amoco Corporation’s 1968 annual report said the company had applied for approval to expand production rates to 8000 barrels per day. It also added, “We contemplate expanding the project to about 60,000 barrels of oil per day after improving the production technique further.”
While Gregoire Lake did not reach those levels of production, it was a source of important technological innovation. In its later stages, this innovation was done in partnership with the Alberta Oil Sands Technology and Research Authority and with a consortium of oil industry partners.
Gregoire Lake was one of the first modern in situ pilot plants in Canada. The original plant — located on lands underlying a First Nations reserve — was decommissioned in 1984. Shortly thereafter, however, Amoco started up another experimental facility nearby. This second Gregoire Lake pilot was the company’s last thermal plant to use vertical wells exclusively. Amoco closed it down in 1989.
Amoco Canada’s first commercial heavy oil production came from the Elk Point project near Lloydminster, on the Alberta/Saskatchewan border. Elk Point production is known as conventional heavy oil, since it is light enough to flow to the wellbore without in situ production techniques. Begun as a primary heavy oil facility in 1984 (when production from the operation was selling for $33.50 per barrel,) the plant temporarily closed down in 1986 when its heavy oil fetched as little as $6.36 per barrel — less than a third of operating costs.
The Elk Point properties were 100 per cent Amoco owned. Through the Dome acquisition of 1988, Amoco acquired an additional 140 sections of land at Lindbergh, just to the east.
The company experimented unsuccessfully with steam flood at Elk Point in 1987. This was part of an effort throughout the petroleum industry to bring costs down in the wake of the oil price crash the previous year. Companies had to shift their thinking on the economics of heavy oil recovery. Primary production rather than thermal recovery became the goal.
An important breakthrough came when field engineers and operators noticed that the more sand that came out with oil produced through primary recovery, the more oil a well produced. The next step was stunningly simple: Operators removed sand control screens from the wells and otherwise modified the production system. Strange concepts such as "foamy oil" and "wormholes" have been developed to explain the otherwise impossible (with traditional fluid flow concepts) producing rates and recovery factors that resulted from this change.
This and other process changes enabled the company to take production from 2140 barrels per day in 1988 to 4500 barrels per day in 1991. More importantly, production costs declined to only $5.56 per barrel — a 73 per cent reduction.
During the 1970s and ‘80s, Amoco participated in several non-operated oil sands pilots. And in 1977, the company became part of the Shell-led Alsands consortium. That consortium was to construct a huge, Syncrude-style oil sands plant in the early 1980s.
However, in those years a combination of high inflation and high interest rates, declining commodity prices and unattractive energy policies created a crisis atmosphere within the industry. The Alsands project was shelved, as were many in situ oil sands pilot plants.
Although there was a flurry of oil sands development in response to government initiatives, the yeasty period of oil sands experimentation and frontier exploration ended when oil prices crashed in 1986. However, the industry had experienced boom and bust cycles for nearly a century and a half, so no one doubted that the industry would emerge from the gathering crisis different but stronger.
For every corporation in a period of change, the overwhelming concern is how to deal with the crisis today. Different companies take different paths.
6. The Acquisition
Map: Western Canada landholdings immediately after acquisition
Photo: J. Howard and T. Don
Graph: Production Growth (Amoco and Dome)
Sidebar: Ron Nicholls
To understand why everything seemed to go wrong for Canada’s oil industry in the 1980s, it is important to understand the political and economic climate of the previous decade.
In Canada, the ‘70s began with disputes between the newly elected Lougheed Conservatives in Edmonton and the minority Trudeau Liberals in Ottawa over petroleum revenues. This is an old theme in national politics. It goes back at least to 1905, when Alberta and Saskatchewan achieved province status without the control over natural resources that the other provinces already enjoyed.
On a global scale, the prosperous years following World War II had given impetus to world-wide oil consumption, which accelerated a century-old upward demand trajectory. By the 1970s, however, there was a widespread perception that discoveries and production were lagging consumption. Exportable oil reserves were disproportionately concentrated in the Middle East. These developments laid the groundwork for a series of three energy shocks — two in which oil prices shot up, one in which they plunged.
In 1973, the Arab/Israeli Yom Kippur War triggered intense hostility toward the West by the Organization of Petroleum Exporting Countries’ Arab members. As a political and economic tactic, they imposed oil embargoes on the countries supporting Israel — in practical terms, the United States and most of Europe. In addition, they introduced production cutbacks and began setting oil prices unilaterally.
This highly successful strategy gave OPEC the sweet taste of power. After the embargoes were lifted, the organization continued to manipulate the global energy market through production controls. These measures turned OPEC into a cartel capable of strongly influencing prices — a situation that lasted nearly a decade. Collectively, the industrial world had little alternative but to import oil from OPEC countries. Consumers therefore paid whatever prices OPEC set.
The result? Oil prices increased sharply in 1973-74, then rose steadily. Saudi Reference oil, for example, sold for US$3.01 per barrel in October, 1973. Three months later, the price had nearly quadrupled. Matters got worse in dollar terms during the Iranian Revolution of 1979/80. Panic buying compounded the problem of crude oil shortfalls, pushing some crude oil prices above US$40 per barrel. On average, a barrel of Arab Light (a high-quality oil) cost US$35.69 in 1980.
Canadian natural gas prices also rose steadily during the 1970s, pursuant to price controls and federal/provincial agreements. Alberta plant gate prices (producers’ receipts) rose from about $0.17 per thousand cubic feet in 1972 to $2.46 in 1981. But Canada’s export markets (primarily California and the US Midwest) paid far more.
In early 1980, the National Energy Board set export prices at US$4.17 per thousand cubic feet, a 30 per cent increase. In a celebrated move a year later, federal energy minister Marc Lalonde announced that they would be increased again to US$4.94, an all-time high and twice the prevailing domestic price in the US at the time. To put that number in perspective, Alberta gas prices in the first half of the 1990s rarely topped US$1.50 per thousand cubic feet.
These developments contributed to high inflation and the associated high interest rates. But an equally important outcome was a sense — common within and without the industry — that petroleum resources were scarce and that prices would therefore continue to rise indefinitely. Some companies actually based long-term business plans on assumptions of US$100 per barrel oil by the year 2000. This outlook helped stimulate frontier exploration and oil sands experimentation.
Despite extremely high commodity prices, Canada’s petroleum fiscal regime was such that industry returns were barely acceptable. In the early ‘80s, returns on capital employed (ROCE) were generally lower than the banking sector’s prime interest rate.
In concert with the provinces, the federal government had permitted domestic oil prices to rise in tandem with OPEC increases during the 1970s, but as a matter of politics maintained a lower-than-OPEC, “made in Canada” price. And through often bitter negotiations, Ottawa and producing province governments kept most of the revenue stemming from these price increases.
Ottawa bucked this practice with the announcement in October 1980 of the National Energy Program (NEP) — a policy that most western Canadians saw as a federal tax-grab. The feds imposed new taxes, but did not share them with the provinces. These included taxes on production revenues rather than profits. The program also provided exploration grants to companies that met certain Canadian ownership requirements. And it explicitly favoured Petro-Canada, which was then Canada’s national oil company.
One of the odd twists of this period was that the Government of Canada subsidized oil imports. Thus, Canadian consumers bought high from the industry’s offshore competitors while Canadian producers sold low (in netback terms) into both domestic and export markets. In addition, oil and gas exports were restricted, on the premise that Canada might run out of these critical commodities.
The effect of these measures was to reverse the business adage about buying low and selling high. One outcome was a set of energy price signals that were completely at variance with the perceived situation of energy shortage. Low prices discouraged production and encouraged consumption, thereby worsening the national energy balance.
Conventional light oil reserves and production had begun to decline in 1973, yet the already hefty taxes and royalties on petroleum increased. Besides lowering the industry’s ability and incentive to develop new supplies, high government take from oil and gas lowered industrial productivity nation-wide. While other countries focused heavily on energy conservation, made-in-Canada prices permitted Canadians to continue relying heavily on oil.
Events would soon show that none of this was sustainable policy. Canada could not create policy as if the country were isolated from world events.
In the environment of the day, a common business strategy was to buy oil and gas assets. The idea was that to purchase producing properties was cheaper than to find them through the drill bit. Dome was an early convert to this strategy, with acquisitions that included Siebens Oil and Gas, Sabre Petroleum, Kaiser Resources and the Canadian assets of Mesa Petroleum.
The NEP favoured Canadian oil and gas companies as a matter of policy and implicitly encouraged takeovers of foreign-owned companies with financial incentives for companies based on their Canadian content. This is one reason Dome launched what was at the time the biggest takeover in Canadian history. The company used debt to assume control of (and eventually acquire) Hudson’s Bay Oil and Gas (HBOG). One of Dome’s typically complex deals, the acquisition eventually cost more than $4 billion.
In terms of assets, the HBOG purchase made Dome the largest oil and gas company in Canada. However, the company was heavily in debt, and in the early 1980s interest rates were setting record highs. Dome began to shudder under the load.
As a foreign-owned company, Amoco could not buy large-scale Canadian assets without government approval. In the immediate aftermath of the NEP, approval for virtually any multi-million dollar acquisition would have been unlikely.
Through its history, Amoco Canada had generally been an exploration and development company, and probably would not have been interested in making a large acquisition at the high prices of the day. Instead, the company’s response to the worsening business environment was to batten the hatches. A major storm was brewing.
A sign of that storm was lowering activity. The National Energy Program’s new taxes and incentive programs caused the industry to reduce exploration in western Canada while increasing activity in the frontiers. However, only companies with substantial Canadian ownership could take advantage of the frontier financial incentives. Amoco did not operate in the frontiers during this period.
As it became clear to policy-makers that the National Energy Program was bad policy, they began to scramble for solutions. An important development came in 1982, when Petro-Canada and BP Canada (later Talisman Resources) sought approval for a commercial oil sands plant at Wolf Lake. Anxious to get such a project off the ground during a recession greatly worsened by the NEP, the governments of Canada and Alberta worked with the sponsors to develop a fiscal regime that would allow the project to proceed.
Known as the Wolf Lake formula, for a while this arrangement would be the long-awaited generic policy for oil sands development. Generally available to any company wanting to develop an in situ plant, by 1985 it had stimulated a boom in oil sands development. The Wolf Lake project did not do well for its original owners, however. In 1992 Amoco bought the plant.
Both Amoco and Dome cut back on field investment in the early 1980s, but for different reasons. In Dome’s case, it was because the company no longer had any free cash flow. In Amoco’s case, it was because of fiscal regimes that discriminated against foreigners and cash flows damaged by punitive taxation.
Interest rates remained stubbornly high as petroleum prices declined. The lower oil price resulted from energy conservation efforts world-wide, competition among international suppliers and the growth of global supplies, cheating on production quotas by OPEC members, and the severe recession of 1982/83. Natural gas prices also dropped as US consumers resisted the high prices set by Canada. Western Canada’s industry soon found itself able to produce far more natural gas than it could sell. The gas bubble, as it was then known, would take the better part of two decades to burst.
The dream appeared to be over. Market forces were reasserting themselves, and hydrocarbon supply and demand were seeking equilibrium. Dome soon recognized the HBOG acquisition as a blunder. The company was in trouble.
Dome had begun a period of phenomenal growth at the beginning of the ‘70s. The table below shows the comparative growth of Dome and Amoco during a 20-year period:
Table: Production Growth
Crude and condensate production,
(barrels per day, net before royalty) Natural gas production
(millions of cubic feet per day, net before royalty)
Year end Amoco Dome Amoco Dome
1967 48,000 17,652 210 120
1972 93,000 29,622 368 135
1975 89,419 51,802 382 276
1982 72,310 92,900 352 585
1987 71,767 87,000 415 548
Always alert to the political winds, Dome took advantage of the Canadianization incentives of the National Energy Program by establishing a new corporate entity, Dome Canada, which would own proportionate interests in Dome properties. The government of Canada was eager to help make the novel transaction occur. In the name of Canadianization, Parliament modified legislation (including lowering initial levels of ownership requirements) and the government gave swift approval to what was then the largest equity issue in Canadian history.
Just like the timing of the NEP, the timing of Dome’s gigantic expansion could not have been worse. Struggling under $7 billion of debt at high interest rates, Dome cut field investment to the bone. The company was a partner to almost every other large and middling Canadian producer, yet could not afford to invest in field operations. This worsened an already tough situation for the industry as a whole. Canada’s oil companies began laying off workers.
The banks and the federal government proposed a $1 billion bailout plan to save the crippled giant. While the bailout might have worked, it would have ended Dome’s independence, placing practical control in the hands of government and the banks. The plan was never implemented.
Through 1982 and 1983, however, the company did not have enough cash flow to meet its obligations. In late 1983, Jack Gallagher stepped down as board chairman in favour of J. Howard Macdonald, who had been treasurer of the Royal Dutch Shell Group in London. Macdonald negotiated an agreement to restructure the company’s debt.
The debt rescheduling plan sustained Dome from April 1984 through 1985. There was cause for considerable optimism in 1985, when the newly elected government of Brian Mulroney announced the Western Accord — an energy policy that scrapped the remnants of the NEP. The Accord reduced the government role in the oil business, eliminated the NEP’s taxes and grants, decontrolled prices, and provided for a phased-in deregulation of the natural gas business.
The celebrations were short-lived, however. In early 1986 conventional oil prices dropped from US$32 per barrel to below US$10 per barrel. Discipline problems within OPEC combined with Saudi Arabia’s decision to increase production and the combined effects of conservation, energy substitution and new production from non-OPEC countries were the main causes. Prices stabilized above US$10 but continued to fluctuate, sometimes wildly. The price crash of ‘86 dashed any hope that rescheduling debt would save Dome.
Macdonald began negotiations to restructure the debt, instead. His hope was that lenders would exchange some debt for equity. This would reduce debt, thereby creating manageable payments. As negotiations progressed, however, it became apparent that the lenders were unwilling to convert enough debt to make the plan work. In addition, they wanted a level of operational control that Dome found unacceptable. The only workable solution was to sell the company.
In 1986, Amoco began to seriously investigate the idea of buying Dome Petroleum. At the time, Amoco Canada was the fifth largest natural gas producer in Canada and the eighth largest producer of oil. For its part, Dome was the nation’s second-largest producer of natural gas and the fifth largest oil producer. Acquisition of Dome would create a company in first and second place, respectively.
The two companies were mutually involved in more than 130 producing oil and gas fields. Many of these properties, which represented 42 per cent of Amoco Canada’s conventional reserves, had come to Dome through the HBOG acquisition. In addition, of course, Amoco and Dome shared many liquids-related operations. It soon became clear that Amoco could not be less than an aggressive bidder. The two companies were an excellent fit. A combined corporation would have a lot of competitive advantages.
While Amoco Canada was concerned about its own exposure if Dome were forced into bankruptcy, the company’s real motivation was based on stronger stuff. Amoco liked Dome’s large resource base, especially in conventional areas. Dome owned the rights to explore and develop more land in the western sedimentary basin than any other company.
The Dome acquisition also reflected Amoco Corporation’s renewed emphasis on international activity. This impact can be shown in natural gas reserves. At the time, Amoco Corporation had proved net natural gas reserves of 10 trillion cubic feet in the United States. By comparison, Dome and Amoco Canada together had 5.1 trillion cubic feet of proved natural gas reserves. The addition of Dome’s holdings would send Amoco straight to the top among North American natural gas producers.
Under the leadership of T. Don Stacy, Amoco Canada was one of three bidders; the others were Imperial Oil and TransCanada PipeLines. Amoco put up the best offer in April, 1987: $5.1 billion. The largest industrial acquisition in Canadian history, the original offer was not signed by all secured Dome lenders until the ante was increased to $5.5 billion. September 1, 1988 was set as the official acquisition closing date.
Besides negotiations with lenders, Amoco Canada had to negotiate with such federal agencies as Investment Canada (formerly the Foreign Investment Review Agency), Revenue Canada (to whom Dome owed money) and the Department of Energy. After many years of public criticism of excessive foreign investment in Canada’s oil industry, the federal government was under pressure for allowing a foreign-controlled company to buy a “Canadian” company.
Amoco offered a number of concessions. These included an agreement to sell 20 per cent of Amoco Canada’s common shares, with the sale of the first five percent to occur within five years of the acquisition date. Canadians would have first chance to buy. The company also agreed to invest at least $2.5 billion in Canada over five years, including $100 million in research and development.
The acquisition also came under review by the federal government’s Competition Bureau. The federal watchdog for non-competitive business practices, this agency wanted to be sure that the acquisition would not give Amoco an unfair advantage in the liquids business. The bureau eventually opted for a three-year test period to determine whether there was reason for concern. In 1991, it ruled there was not.
The delay in completing negotiations was necessary to allow numerous deals and conditions to be fully negotiated. The company had to negotiate with Dome’s creditors, deal with different government departments and agencies, and fight some lawsuits from creditors and shareholders in the courts. While this work proceeded, the two companies planned their physical merger. The courting period, 16 months, was longer than Amoco expected.
Amoco wanted to operate as one company by closing day — a very ambitious goal. To give a sense of the immensity of change required, the acquisition produced an increase in Amoco Canada’s assets from $2.2 billion at year-end 1987 to $7.2 billion a year later. During the same period, the company’s debt rose from nil to $4.2 billion.
In the post-acquisition environment, Amoco faced two challenges. One was to get the company operating smoothly. The other was to become profitable again. To reach these ends, T. Don Stacy articulated the new company’s key strategies. First, Amoco would reduce its debt; second, the company would focus on developing those assets that could generate short-term cash flow.
Beginning in the early 1990s, the company would operate in four key areas. One focus would be to exploit and produce known conventional oil and gas reserves. Another would be exploration and development in these areas. Third would be heavy oil development. Fourth would be NGL production, transportation and marketing.
Notably absent from this list was frontier exploration — even though Amoco Canada was now the owner of CANMAR, the world’s largest private fleet of Arctic vessels. In 1989, CANMAR drilled the Kingark well in the Canadian arctic. But Amoco Canada needed cash immediately, and could not afford the luxury of extensive exploration on its own behalf in the frontiers. That kind of investment is for the longer term.
Besides having overlapping properties, Amoco and Dome had overlapping skills. For example, while Amoco and Dome were both major gas plant operators, Dome had expertise in liquids recovery and cryogenics — supercold technology to separate ethane from natural gas. Amoco’s expertise was in sulphur recovery, process design, and process optimization.
The chore of creating a single, integrated entity out of such totally different, culturally diverse companies took much longer than anyone could have imagined. Complex financial, land and accounting systems had to be merged and streamlined. So did geological and seismic data. Non-core properties had to go on the block. And the company had to manage existing operations more effectively.
If creating a smoothly operating company was difficult, becoming profitable again was harder still. In 1987, Amoco Canada showed a profit of $146 million. A year later, the company showed a loss of $52 million because of four months’ interest expense. Five years would elapse before black ink again graced the bottom line. In the meantime, Amoco Canada’s combined losses would total more than $1 billion.
During the years that followed the acquisition, Amoco made radical changes to the new organization. By year-end 1993, when the company recorded its first post-acquisition profit, the business was much more streamlined.
Although oil and equivalent production had declined from roughly 124,000 barrels per day to 97,000 (mostly because of divestitures), average production per employee (crude oil equivalent) had risen 180 per cent. In addition, per employee sales were up 120 per cent for natural gas, 118 per cent for liquids, and 194 per cent for oil.
The changes