Is the Thai Baht in Play?

By Peter McKenzie-Brown Take a look at this chart. It is a foreign exchange picture of the Thai baht versus the US dollar. I wrote this article in response to the huge spike in the baht at the end of January, 2007. As you will notice, at that time something extraordinary happened to the baht: a strengthening of the baht by more than 5 per cent in only two days. In foreign exchange terms, that is huge. Volatility of this kind hasn’t happened since 1997’s Tom Yum Gung Crisis in Thailand led to the horrific Asian Financial Crisis later that year. (Although in that year, of course, the volatility was generally in the other direction.) I have drawn charts for all comparable currencies in Asia - the Malaysian ringgit, for example - and the pattern in those currencies is the same: There has been a steady rise in their values relative to the US dollar since the end of November, 2006. In the case of the currencies of such developed countries as Japan and Korea, the change in value has been marginally down. (See the charts for the Korean won and the yen). Only in Thailand is great volatility in evidence. I believe the currency could be in play. Something comparable happened in the mid-1990s, when speculators wrote so many options contracts (using a relatively sophisticated financial maneuver technically known as "covered calls") on the New Zealand dollar that the currency went through the roof. At one point in that speculative bubble, the amount of currency on contract was greater than the total the Bank of New Zealand had issued since the colony became a country. The speculators who got in at the beginning made a fortune, before the currency’s eventual, and inevitable, collapse. I am not speculating on the Thai baht. But I am speculating on an idea - namely, that if currency speculation has begun in this country, it is somehow connected to the putsch against Thaksin Shinawatra, the billionaire ex-prime minister who has been skulking around east Asia for the last few weeks. As Thailand's richest businessman, he has the most to gain from an appreciation in the baht. As an ousted former head of government, he could also benefit from destabilization of the political system here. Would continuing increases of this magnitude lead to economic and political instability? I think so. It would keep inflation down by lowering the cost of imported goods, but it would hurt the key export and tourism industries by increasing the cost to foreigners of Thai goods and services. The present military government showed at the end of last year that it is frightened of a strong baht, and made some ham-handed efforts to reduce the currency's relative value. Now those efforts are coming back to haunt them. If Mr. Thaksin is somehow behind this, what would he gain? At the very least, he could thumb his nose at the people who drove him out of office. And if the system got completely out of control, it is possible to imagine him being permitted back into the country to bring a return to order. Stranger things have happened in the last, tumultuous, year.

Classroom Management and Student Discipline

I recently updated my book, Teach and Leorn: Reflections on Communicative Language Teaching, from which this is a chapter, and made it available on Kindle and as an inexpensive book. To enjoy a read, please click here.

By Peter McKenzie-Brown

I recently encountered two of my former students in a Chiang Mai restaurant, and asked them how they were doing in the job market. They had completed their training in December, and both quickly began to teach. But their working situations are as different as chalk and cheese. One teaches six classes of young Thai teenagers in a public school, and each of her classes has perhaps 50 students enrolled. The other works as a one-to-one English tutor, and teaches only 18 hours per week. His students are mostly Thai adults, but they also include two Korean teenagers.

As far as classroom management is concerned, this study in contrasts illustrates the extremes that English language teachers are likely to experience.

Think about it: The teacher with hundreds of students is dealing with individuals she will never know by name. The situation militates against her being able to give personal attention to anyone. Her students are there because the law requires them to study English. Their previous English teaching has been from teachers with mixed (generally poor) language instruction skills. The distractions of the classroom are legion for both teacher and student. Many of her students have raging hormones and little motivation to learn English.

In the tutor-teacher’s case, the situation is upside down – or, some would say, right side up. The students only get personal care. The teacher gets to know them quite well. They are studying English because they want to learn the language, and are therefore highly motivated. Their previous language instruction is irrelevant, because their tutor rough tunes to their level, and heals the areas important to them. And besides having motivation, his students are more mature. They do not let their hormones disrupt the operation of the classroom.

Without a doubt these classes illustrate two extremes in classroom management. But has one of these teachers been dealt a bad hand in the gin rummy of teaching, while the other got a royal flush? I suggest not. When I asked the two teachers how their first month had gone, both said “I love it!” Different strokes for different folks.

Classroom Management: And this brings us around to the issue of good classroom management. Teachers have to manage their classrooms well so their teaching can be effective. Good management creates an environment that helps students learn. Good classroom management reveals and influences your attitude, talents, perceived role, voice and body language. It strongly affects teacher-student interactions, including the challenges associated with teaching to large groups.

Okay, enough of the abstractions. What exactly is classroom management? It is what you do to make your teaching area a good place to learn in. For example, the physical environment of the classroom can contribute to student learning; while all classroom seating arrangements have strengths and weaknesses, you have to decide which one works best for you. There are ways to arrange classroom seating to encourage student interaction. Should you set your students’ chairs in a horseshoe? A circle? How about the old standby, rows of student desks? Each works best in different situations. As a classroom manager, your job is to think through seating plans and other physical arrangements (like making sure the classroom isn’t too hot) that will work best for your students.

What else can you do to optimize the learning process? Perhaps nothing is more important in a classroom than letting your students feel safe – the process Stephen Krashen calls lowering the affective filter. A huge part of your role as a teacher is to build a positive climate, letting your students know there are rewards for taking risks in your classroom. Classroom management involves looking after such details as having a place to post student essays, for example.

One way to make students feel safe is to clarify classroom procedures and rules. Part of helping students feel secure is to establish clear rules and class routines. And it involves discipline. Let’s talk about that.

The Learner’s Age: One place to start is to consider that each class you teach is likely to include students of about the same age. Thus, your students will probably be children, adolescents or adults, not all three. So let’s look at those three groups in age rank.

1. When you teach children, it is important to differentiate between two life stages – young children who are 5-8 years old, and mature children who are 8-11. In terms of how their minds work, the mature children are cognitively close to adolescents and adults. Young children, by contrast, are cognitively closer to Martians. According to one popular text on teaching English to children,

The adult world and the child's world are not the same. Children do not always understand what adults are talking about. Adults do not always understand what children are talking about. The difference is that adults usually find out by asking questions, but children don't always ask. They either pretend to understand, or they understand in their own terms and do what they think you want them to do.

In both cases, young learners have special requirements. They have short attention spans, and require lots of physical play and teacher patience. They sometimes have trouble differentiating between fact and fiction. They have little life experience, but buckets of honesty. And while they may have respect for authority, they have a great deal of imagination. A teacher may feel that on some levels communication is impossible.

2. When you teach adolescents, you are dealing with a different crowd. They often have attitude. They respond to peer-pressure. They are often insecure, their hormones may be running wild, and they are developing life experience. As they go through the rapid transition between childhood and adulthood, they are often seeking knowledge and self-identity. Many challenge authority, and in the language classroom that means you.

3. Adults are another story. They have life experience and, because they are unlikely to be taking English because they have to, they are likely to be well motivated. They are also likely to be more tolerant and self-aware, but they may be status conscious. This latter issue can be an issue in a number of ways. For one, in terms of age they are peers of the teacher. If they are wealthy, older or high-status professionals, they may consider themselves to outrank you. Therein lay minefields. Don’t ever believe that adult students won’t ever give you discipline problems. Most won’t, but some do.

An article by US educator Budd Churchward suggests a way to apply the thought of psychologist Lawrence Kohlberg to the problem of classroom discipline for children and adolescents. His ideas put the lie to the urban myth that a class full of young adolescents is a class out of control. Purveyors of this notion, which is common in the United States, for example, support it with such unexamined statistics as the one that the dropout rate for America’s urban teachers is 40-50 percent. Does this mean the students were out of control, the teachers got offers for better jobs, or the teachers were ready for a change?

Kohlberg developed theories about the stages of moral and ethical reasoning among people. Through his work, which included in-depth studies of youngsters from many parts of the world, he developed a scheme of moral development consisting of three levels (each made up of two separate stages). He suggested that almost everyone, regardless of culture, race, or sex, experiences at least the first four stages.

The Encyclopedia of Psychology explains the four stages thus:

Each stage involves increasingly complex thought patterns, and as children arrive at a given stage they tend to consider the bases for previous judgments as invalid. Children from the ages of seven through ten act on the pre-conventional level, at which they defer to adults and obey rules based on the immediate consequences of their actions. The behaviour of children at this level is essentially pre-moral. At Stage 1, they obey rules in order to avoid punishment, while at Stage 2 their behaviour is mostly motivated by the desire to obtain rewards. Starting at around age ten, children enter the conventional level, where their behaviour is guided by the opinions of other people and the desire to conform. At Stage 3, the emphasis is on being a "good boy" or "good girl" in order to win approval and avoid disapproval, while at Stage 4 the concept of doing one's duty and upholding the social order becomes predominant. At this stage, respecting and obeying authority (of parents, teachers, God) is an end in itself, without reference to higher principles. By the age of 13, most moral questions are resolved on the conventional level.

For purposes of classroom discipline, Churchward says that only these four of Kohlberg’s stages are important.

The Learner’s Stage: At the risk of over-simplifying his ideas, here is a brief review of the approach to discipline that Churchward develops. It strongly reflects Kohlberg’s stages.

1. Stage 1 discipline problems, he argues, involve recalcitrant behaviour. This is the power stage, in which might makes right. The students refuse to follow directions. They are defiant and require a great deal of attention. “Fortunately, says Churchward, “few of the students we see in our classrooms function at this stage. Those who do, follow rules as long as the imbalance of power tilts against them. Assertive teachers with a constant eye on these students can keep them in line. Turn your back on them, and they are out of control.”

2. Self-serving behaviour is the ruling characteristic of Stage 2; Churchward calls it the reward and punishment stage, in which the student’s key question is, “What’s in it for me?” In class, these students behave either because they will receive candy, free time or some other reward, or because they do not like what will happen to them if they do not behave. “Most children are moving beyond this stage by the time they are eight or nine years old”, Churchward explains. “Older students who still function at this stage do best in classrooms with assertive teachers.” Assertive teachers – the ones who insist on class control – are the ones who fare best with stage 1 and 2 students.

3. Churchward characterizes Stage 3 as one of interpersonal discipline, in which the student is out to make the teacher’s day. In this stage the student’s main question is “How can I please you?” He adds, “Students functioning at Stage 3 make up most of the youngsters in our middle and junior high schools. These kids have started to develop a sense of discipline. They behave because you ask them. This is the mutual interpersonal stage. They care what others think about them, and they want you to like them.” These children need little discipline. Ask them to settle down and they will. They rarely need a heavy-handed approach to classroom discipline.

4. The last stage of classroom discipline involves self-discipline. This is the social order stage, characterized by the student belief that “I must behave because it is the right thing to do.”

“Students functioning at Stage 4 rarely get into any trouble at all,” Churchward says. “They have a sense of right and wrong. Although many middle school and junior high school students will occasionally function at this level, only a few consistently do. These are the youngsters we enjoy working with so much….You can leave these kids alone with a project and come back 20 or 30 minutes later and find them still on task.” Many adolescent students do not operate at this stage, but they are near enough to it that they understand how it works. “Cooperative learning activities encourage students to function at this level,” he adds. “The teacher who sets up several groups within the classroom gives students a chance to practice working at this level.” You should wait close by, though, ready to step in when needed.

Churchward’s ideas are useful and relevant, and he does a good job of developing a practical application for Kohlberg's theoretical concepts. Put in the context of managing the classroom, his thinking offers a helpful understanding of the psychology of our younger learners, and contributes to the larger issue of class management.

On Churchward's website – which also promotes a computer system for managing classroom discipline (free trial available) – is a description of 11 techniques for better classroom discipline. I recommend you take a look at it.

History of the Petroleum Industry in Canada, Part Two

This history is part two of a history of the Canadian petroleum industry, which I wrote for Wikipedia. It is about northern and offshore petroleum frontiers and oil sands. For early development of Canada's conventional petroleum resources and pipelines, see History of the petroleum industry in Canada, part one.

Canada's petroleum frontiers are of two types. The technological frontiers include the oil sands of Alberta, and the huge heavy oil belt that stretches from central Alberta into Saskatchewan, and straddles the borders between the two provinces. Here the resources are known, but technologies to produce oil from them in cost-effective ways are still being developed. The geographical frontiers are the vast petroleum basins in the north, in the Arctic Islands and offshore, and off the coast of Atlantic Canada. These areas are difficult and expensive to explore and develop, but successful projects can be profitable using known production technology. This article covers the early development of both.


Oil sands and heavy oil Chemistry of Petroleum: An early history of Canada’s petroleum industry would not be complete without a chronicle of pioneering efforts to produce the tar sands (now commonly called “oil sands”) of northern Alberta.

To appreciate these resources, it is important to understand the "gravity" of oil and gas. Gravity refers to the weight spectrum of hydrocarbons, which increases with the ratio of hydrogen to carbon in a chemical compound's molecule. Methane (CH4) - the simplest form of natural gas - has four hydrogen atoms for every carbon atom. It has light gravity, and takes the form of a gas at atmospheric pressure. The next heavier hydrocarbon, ethane, has the chemical formula C2H6 and is a slightly heavier gas.

Gases, of course, have no gravity at atmospheric temperatures and pressures. Organic compounds combining carbon and oxygen are many in number. Those with more carbon atoms per hydrogen atom are heavier, and less likely to be gaseous. Most hydrocarbons are liquid under standard conditions, with greater viscosity associated with greater gravity.

The American Petroleum Institute has developed a formula to measure the API gravity of petroleum liquids. Heavy oil and bitumen, which have more carbon than hydrogen, are heavy, black, sticky and either slow-pouring or so close to being solid that they will not pour at all unless heated. Although the dividing line is fuzzy, the term heavy oil refers to slow-pouring heavy hydrocarbon mixtures.

Bitumen refers to mixtures with the consistency of cold molasses that pour at room temperatures with agonizing slowness. It is difficult to grasp the immensity of Canada's oil sands and heavy oil resource. Sand deposits in northern Alberta include four major deposits which underlie almost 70,000 square kilometres of land. The volume of bitumen in those sands dwarfs the light oil reserves of the entire Middle East. One deposit, the Athabasca oil sands, is the world's largest known crude oil resource.

Early Exploration: Explorer and fur trader Peter Pond noticed the deposits when he travelled the Clearwater River to its junction with the Athabasca in 1778 - the first European to do so. He noted “...along the banks of the river are found springs of bitumen which flow along the ground.” Reaching the same area nearly a decade later, Alexander Mackenzie also became interested in the oil sands and the way the Ojibwe Indians used the thick black oil for water-proofing their canoes. Despite the fascination of the early explorers, however, the existence of the sands did not excite commercial interests for more than a century.

In 1875, John Macoun of the Geological Survey also noted the presence of the oil sands. Later reports by Dr. Robert Bell and later by D.G. McConnell, also of the Geological Survey, led to drilling some test holes. In 1893, Parliament voted $7,000 for drilling. This first commercial effort to exploit the oil sands probably hoped to find free oil at the base of the sands, as drillers had in the gum beds of southern Ontario a few decades earlier.

 Although the Survey's three wells failed to find oil, the second was noteworthy for quite another reason. Drilled at a site called Pelican Portage, the well blew out at 235 metres after encountering a high-pressure gas zone. According to drilling contractor A.W. Fraser,

The roar of the gas could be heard for three miles or more. Soon it had completely dried the hole, and was blowing a cloud of dust fifty feet into the air. Small nodules of iron pyrites, about the size of a walnut, were blown out of the hole with incredible velocity. We could not see them going, but could hear them crack against the top of the derrick . . . . There was danger that the men would be killed if struck by these missiles.

Fraser's crew unsuccessfully tried to kill the well by casing it, then abandoned the well for that year. They returned in 1898 to finish the job, but again they failed.

In the end, they simply left the well blowing wild. Natural gas flowed from the well at a rate of some 250,000 cubic metres per day until 1918. In that year a crew led by geologist S.E. Slipper and C.W. Dingman finally shut in the well.

These wells helped establish that the bitumen resource in the area was huge. There was now clear recognition of the commercial potential of the oil sands, and a long period of exploration and experimentation followed. The point of this research was to find a method of getting oil out of the tar sands at a reasonable price. Alfred Von Hamerstein, who claimed to be a German count, was one of the colourful early players in the oil sands. He had been en route to the Klondike, but stayed and turned his interest from gold to the oil sands. In 1906 he drilled at the mouth of the Horse River, but struck salt instead of oil. He continued working in the area, however.

In 1907 Von Hamerstein made a celebrated presentation to a Senate committee investigating the potential of the oil sands.

I have all my money put into (the Athabasca oil sands), and there is other peoples' money in it, and I have to be loyal. As to whether you can get petroleum in merchantable quantities . . . I have been taking in machinery for about three years. Last year I placed about $50,000 worth of machinery in there. I have not brought it in for ornamental purposes, although it does look nice and home-like. 

History has not been kind to the count, however. He is now generally thought to have been a bit of a dreamer, a lot of a con.

In 1913, Dr. S.C. Ells, an engineer with the federal department of mines, began investigating the economic possibilities of the oils sands. It was then that the idea of using the sands as road paving material was born. In 1915, Dr. Ells laid three road surfaces on sections of 82nd Street in Edmonton. Materials used included bitulithic, bituminous concrete and sheet asphalt mixtures. A report, ten years later, by a city engineer stated that the surface remained in excellent condition. McMurray asphalt also saw use on the grounds of the Alberta Legislature, on the highway in Jasper Park and elsewhere in Alberta. Although private contractors also mined oil sand as a paving material, the proposition was not economic. Fort McMurray (the village closest to the near-surface deposits) was small and far from market, and transportation costs were high.

Bitumen Production: Instead, researchers began to look for ways to extract the bitumen from the sand. The Alberta Research Council set up two pilot plants in Edmonton and a third at the Clearwater River. These plants were part of a successful project (led by the Research Council’s Dr. Karl A. Clark) to develop a hot water process to separate the oil from the sands. In 1930, the Fort McMurray plant actually used the process to produce three car loads of oil.

At about that time two American promoters, Max Bell and B.O. Jones from Denver, entered the oil sands scene. They reportedly had a secret recovery method known as the McClay process, and they claimed substantial financial backing. They negotiated leases with the federal and Alberta governments and also bought the McMurray plant of the Alberta Research Council. In 1935, Abasand Oils Limited, Bells’ American-backed operating company, started construction of a new plant west of Waterways.

Under the agreement with the government, the plant was to be in operation by September 1, 1936. But forest fires and failure of equipment suppliers to meet delivery dates delayed completion. The agreement called for mining 45,000 tonnes of sands in 1937 and 90,000 tonnes each year after 1938. The 1,555-hectare lease carried a rental of $2.47 per hectare per year. There was to be a royalty of $0.063 per cubic metre on production for the first five years, and $0.31 per cubic metre thereafter. Mining at the Abasand plant began May 19, 1941. By the end of September, 18,475 tonnes of oil sand had produced 2,690 cubic metres of oil, but in November fire destroyed the plant.

Rebuilt on a larger scale, it was fully operational in June 1942. Between 1930 and 1955, the International Bitumen Company Limited under R.C. Fitzsimmons operated a smaller scale pilot plant at Bitumount. In 1943, the federal government decided to aid oil sands development, and took over the Abasand plant. The federal researchers concluded that the hot water process was uneconomic because of the extensive heat loss and proposed a “cold” water process. But work at the plant came to an end with a disastrous fire in 1945. 

Meanwhile, in July 1943, International Bitumen Company reorganized as Oil Sands Limited. When the Alberta government became disenchanted with federal efforts in the oil sands and decided to build its own experimental plant at Bitumount, the province engaged Oil Sands Limited to construct the plant. The company agreed to buy the plant within a period of ten years for the original investment of $250,000. The cost of the plant was $750,000, however.

A legal claim against Oil Sands Limited resulted in the province taking possession of the plant and property at Bitumount. The plant consisted of a separation unit, a dehydrating unit and a refinery. The plant conducted successful tests using the Clark hot water process in 1948/49 then closed, partly because the recent Leduc discoveries had lessened interest in the oil sands. Oil Sands Limited eventually reorganized as Great Canadian Oil Sands Limited (now Suncor), which built and started operation of the first commercial-sized integrated oil sands project in 1967.

It had found solutions to the problems of extracting a commercial grade of oil from the sands - problems that had been the concern of financiers, chemists, petroleum engineers, metallurgists, mining engineers, geologists, physicists and many other scientists and pseudo-scientists for may decades. A much later development - although its roots go back to the 1940s, the massive Syncrude plant did not go into operation until 1978 - now supplies some 14 per cent of Canada's crude oil production, in the form of synthetic oil.

Heavy Oil Story:Heavy oil is a sister resource to bitumen. It is lighter than bitumen and its reservoirs are much smaller than the great oil sands deposits. Even so, its dimensions are impressive. But like the oil sands, only a small percentage is producible. Often called conventional heavy oil, this low-density oil can be recovered by conventional drilling techniques or by waterflood, a technique of injecting water into the reservoir to increase pressure, thus forcing the oil toward the well bore.

When these techniques work, heavy oil is like the more commercially attractive lighter grades of oil. But heavy oil can also be quite viscous. It can need some form of heat or solvent and pressure before it can flow into a well bore to be produced. When heavy oil requires these techniques to go into production, it is known as non-conventional heavy oil.

The first heavy oil discoveries came with the pursuit of conventional light and medium crude oil. Because much of western Canada's heavy oil is in pools close to the surface, early explorers using older rigs discovered many of those pools before they came upon the deeper light oil reservoirs. One of the first finds was in the Ribstone area near Wainwright, Alberta in 1914. The province's first significant production of heavy oil came from the Wainwright field in 1926. Producers drew almost 6 000 barrels of heavy oil from the field in that year. A small-scale local refinery distilled the heavy goo into usable products.

Elsewhere in Alberta, petroleum explorers made other heavy oil finds as they pursued the elusive successor to the Turner Valley oil field. They developed production from many of these fields, but only in small volumes. The recovery techniques of the day combined with the low price of oil and the nature and size of the finds meant that most of the oil remained undeveloped.

The most important exception was at Lloydminster. While the first discovery occurred in 1938, serious development did not begin until Husky Oil moved into the area after the second world war. Husky Oil was born during the Depression through the efforts of Glenn Nielson, an Alberta farmer driven to bankruptcy when the bank called a loan on his farm. Nielson had moved to Cody, Wyoming, by the time he founded Husky as a refining operation.

He turned his attention back to Canada after the second world war, and decided to set up a refinery at Lloydminster. Steel was scarce, so Husky dismantled a small Wyoming refinery constructed during the war to provide bunker fuel to the American Navy. It loaded the pieces onto 40 gondola cars and shipped them north by railway. The company began reassembling the 400 cubic metre per day facility in 1946, and the refinery went on production the following year. Strategically located between the Canadian Pacific and Canadian National railroad tracks in Lloydminster, the refinery soon began to get contracts for locomotive bunker fuel. The company also found a strong market for asphalt for road building. 

Husky's move into the area spurred drilling and production. Within two years of Husky's arrival, there were oversupplies of heavy oil and shortages of storage space. Producers solved the problem by storing the oil in earthen pits holding up to 16,000 cubic metres each. For a while Husky bought the oil by weight rather than volume since it was clogged with earth, tumbleweed and jackrabbits. The company had to strain and remeasure the stuff before it could begin refining. Husky began producing heavy oil from local fields in 1946, and by the 1960s was easily the biggest regional producer.

In 1963 the company undertook another in a series of expansions to the refinery. To take advantage of expanding markets for Canadian oil, it also began a program to deliver heavy oil to national and export markets. The key to the $35 million project was the construction of a reversible pipeline which could move the viscous heavy oil into the marketplace. The 116-kilometre "yo-yo" pipeline - the first in the world - brought condensate from the Interprovincial Pipe Line station at Hardisty, Alberta. The company began mixing this very light hydrocarbon with heavy oil, enabling it to flow more easily. The company then pumped the blend through its pipeline (hence the nickname "yo-yo") back to Hardisty. From there the Interprovincial took it eastward to market.

These developments made heavy oil for the first time more than a marginal resource. Within five years, area production had increased five-fold to nearly 2,000 cubic metres per day. By the early 1990s, production from the heavy oil belt was some 40,000 cubic metres per day. And Husky was still one of Canada's biggest heavy oil producers.

True North: The first great story in Canada's exploration of the geographical frontiers is that of Norman Wells in the Northwest Territories. During his voyage of discovery down the Mackenzie River to the Arctic Ocean in 1789, Sir Alexander Mackenzie noted in his journal that he had seen oil seeping from the river’s bank. R.G. McConnell of the Geological Survey of Canada confirmed these seepages in 1888. In 1914, T.O. Bosworth, later Imperial Oil’s chief geologist, staked three claims near the spot. Imperial Oil acquired the claims and sent two geologists there in 1918-1919. They recommended drilling.

Led by a geologist, a crew comprised of six drillers and an ox (Old Nig by name) began a six-week, 1,900-kilometre journey northward by railway, river boat and foot to the site now known as Norman Wells. They found oil - largely by luck, it turned out later - after Ted Link, the geologist, waved his arm grandly and said, “Drill anywhere around here.”

The crew began digging into the permafrost with pick and shovel, unable to put their cable tool rig into operation until they had cleared away the mixture of frozen mud and ice. At about the 30-metre level they encountered their first oil show. By this time, the river ice had frozen to 1.5 metres and the mercury had plunged to -40 degrees. The crew decided to give up and wait out the winter. They survived, but their ox did not. Old Nig provided many a meal during the long, cold winter. Drilling resumed in the spring and a relief crew arrived in July. Some of the original crew stayed around to help the newcomers continue drilling. On August 23, 1920, they struck oil at 240 metres.

The world’s most northerly oil well had come in. In succeeding months, Imperial drilled three more holes - two successful, one dry. The company also installed enough equipment to refine the crude oil into a type of fuel oil for use by church missions and fishing boats along the Mackenzie. But the refinery and oil field closed in 1921 because northern markets were too small to justify the costly operations. Norman Wells marked another important milestone when in 1921 Imperial flew two all-metal 185-horsepower Junkers airplanes to the site. These aircraft were among the first of the legendary bush planes which helped to develop the north, and forerunners of today’s commercial northern air transport.

 A small oil refinery using Norman Wells oil opened in 1936 to supply the Eldorado Mine at Great Bear Lake, but the field did not take a significant place in history again until after the United States entered World War II.

When Japan captured a pair of Aleutian Islands, Americans became concerned about the safety of their oil-tanker routes to Alaska and began looking for an inland oil supply safe from attack. They negotiated with Canada to build a refinery at Whitehorse in the Yukon, with crude oil to come by pipeline from Norman Wells. If tank trucks had tried to haul the oil to Alaska, they would have eaten up most of their own load over the vast distance. This spectacular project, dubbed Canol - a contraction of “Canadian” and “oil” - took 20 months, 25,000 men, 10 million tonnes of equipment, 1,600 kilometres of road, 1,600 kilometres of telegraph line and 2,575 kilometres of pipeline. The pipeline network consisted of the 950-kilometre crude oil line from Norman Wells to the Whitehorse refinery. From there, three lines carried products to Skagway and Fairbanks in Alaska, and to Watson Lake, Yukon.

Meanwhile Imperial was drilling more wells. The test for the Norman Wells oilfield came when the pipeline was ready on February 16, 1944. The field surpassed expectations. During the one year remaining of the Pacific war, the pipeline pumped about 160,000 cubic metres of oil to the Whitehorse refinery. The total cost of the project (all paid by US taxpayers) was $134 million, in 1943 US dollars. Total crude production was 315,000 cubic metres (7,313 cubic metres of which spilled.) The cost of the crude oil was $426 per cubic metre ($67.77 per barrel). Refined petroleum product output was just 138,000 cubic metres. Cost per barrel of refined product was thus $975 per cubic metre, or 97.5 cents per litre. Adjusted to current dollars using the US Consumer Price Index, in 2000 dollars the oil would have cost $4,214 per cubic metre ($670 a barrel), while the refined product would have been worth an astonishing $9.62 a litre.

 After the war, there was no use for the Canol pipeline. It simply fell out of use, with pipe and other equipment lying abandoned. But the Whitehorse refinery kept on going - in a different locale. Imperial bought it for $1, took it apart, moved it to Edmonton and reassembled it like a gigantic jigsaw puzzle to handle production from the fast-developing Leduc oil field.

But the Norman Wells story is not yet complete. The field entered its most important phase in the mid-1980s, when a pipeline connected the field to the Canada-wide crude oil pipeline system. Oil began flowing south in 1985. Norman Wells was a frontier discovery.

It was not Arctic exploration, however, since it was located south of the Arctic Circle. The definitive push into the Arctic took place in 1957 when Western Minerals and a small exploration company called Peel Plateau Exploration drilled the first well in the Yukon. To provision the well, some 800 kilometres from Whitehorse at Eagle Plains, Peel Plateau hauled 2,600 tonnes of equipment and supplies by tractor train. This achievement involved eight tractors and 40 sleighs per train, for a total of seven round trips. Drilling continued in 1958, but the company eventually declared the Peel Plateau well dry and abandoned. Over the next two decades, however, Arctic exploration gained momentum.

Arctic Frontiers: Stirrings of interest in the Arctic Islands as a possible site of petroleum reserves came as a result of "Operation Franklin," a 1955 study of Arctic geology directed by Yves Fortier under the auspices of the Geological Survey of Canada. This and other surveys confirmed the presence of thick layers of sediment containing a variety of possible hydrocarbon traps. The petroleum industry applied to the federal government for permission to explore these remote federal lands in 1959, before the government had begun regulating such exploration. The immediate result was delay. But in 1960, the Diefenbaker government passed regulations, then granted exploration permits for 16 million hectares of northern land. These permits granted mineral rights to companies in exchange for work requirements.

 The first well in the Arctic Islands was the Winter Harbour #1 well on Melville Island, drilled in the winter of 1961-62. The operator was Dome Petroleum. Equipment and supplies for drilling and for the 35-man camp came in by ship from Montreal. This well was dry, as were two others drilled over the next two years on Cornwallis and Bathurst islands. But all three wells were technical successes. There was no doubt now that high Arctic drilling was possible.

The federal government's eagerness to encourage Arctic Islands exploration, partly to assert Canadian sovereignty, led to the formation of Panarctic Oils in 1968. That company consolidated the interests of 75 companies and individuals with Arctic Islands land holdings plus the federal government as the major shareholder. Panarctic began its exploration program with seismic work and then drilling in the Arctic Islands. By 1969 its Drake Point gas discovery was probably Canada's largest gas field. Over the next three years came other large gas fields in the islands. Those years of drilling established reserves of 500 billion cubic metres of sweet, dry natural gas. Panarctic also located oil on the islands at Bent Horn and Cape Allison, and offshore at Cisco and Skate.

Exploration moved offshore when Panarctic began drilling wells from "ice islands" - not really islands, but platforms of thickened ice created in winter by pumping sea water on the polar ice pack. The company found lots of gas but also some oil.

In 1986, Panarctic became a commercial oil producer on an experimental scale. This began with a single tanker load of oil from the Bent Horn oil field (discovered in 1974 at Bent Horn N-72, the first well drilled on Cameron Island). The company delivered its largest annual volume of oil - 50,000 cubic metres - to southern markets in 1988. Panarctic's ice island wells were not the first offshore wells in the Canadian north. In 1971, Aquitaine (later known as Canterra Energy, then taken over by Husky Oil) drilled a well in Hudson Bay from a barge-mounted rig. Although south of the Arctic Circle, that well was in a hostile frontier environment. A storm forced suspension of the well, and the ultimately unsuccessful exploration program languished for several years.


Mackenzie Delta and the Beaufort Sea: The Mackenzie delta was a focus of ground and air surveys as early as 1957, and geologists drew comparisons then to the Mississippi and Niger deltas, speculating that the Mackenzie could prove as prolific. For millions of years sediments had been pouring out of the mouth of the Mackenzie, creating tremendous banks of sand and shale - laminates of sedimentary rock warped into promising geological structures. Drilling began in the Mackenzie Delta-Tuktoyuktuk Peninsula in 1962, and accelerated during the early 1970s.

The mouth of the mighty Mackenzie River was not a Prudhoe Bay, but it did contain large gas fields. By 1977, its established gas reserves were 200 billion cubic metres, and a proposal to construct a pipeline to tap these resources had become a hot political issue. An inquiry by Justice Thomas Berger resulted in a moratorium on such a pipeline, which today is again under consideration. The petroleum industry gradually shifted its focus into the unpredictable waters of the Beaufort Sea. To meet the challenges of winter cold and relatively deep water, drilling technologies in the Beaufort underwent a period of rapid evolution. The first offshore wells drilled in the Beaufort used artificial islands as drilling platforms. But the artificial island was a winter drilling system, and was only practical in shallow water.

In the mid-1970s, the introduction of a fleet of reinforced drillships extended the drilling season to include the 90 to 120 ice-free days of summer. This also enabled the industry to drill in the deeper waters of the Beaufort Sea. By the mid-1980s, variations on artificial island and drilling vessel technologies had extended both the drilling season and the depth of water at which the industry could operate. They had also reduced exploration costs.

The first well to test the Beaufort was not offshore, but was drilled on Richards Island in 1966. The move offshore came in 1972-73 when Imperial Oil built two artificial islands for use in the winter drilling season. The company constructed the first of these, Immerk 13-48, from gravel dredged from the ocean floor. The island's sides were steep and eroded rapidly during the summer months. To control the erosion, the company used wire laid across the slopes and anchored, then topped off with World War II surplus anti-torpedo netting. The second island, Adgo F-28, used dredged silt. This proved stronger.

Other artificial islands used other methods of reinforcement. In 1976, Canadian Marine Drilling Ltd., a subsidiary of Dome Petroleum, brought a small armada to the Beaufort. It included three reinforced drillships and a support fleet of four supply boats, work and supply barges and a tugboat. This equipment expanded the explorable regions in the Beaufort Sea. Drillships, however, had their limitations for Beaufort work.

Icebreakers and other forms of ice management could generally conquer the difficulties of the melting icecap in the summer. But after freeze-up began, the growing icecap would push the drill ship off location if it did not use icebreakers to keep the ice under control.

The most technologically innovative rig in the Beaufort was a vessel known as Kulluk, which originated with Gulf Oil. Kulluk was a circular vessel designed for extended-season drilling operations in arctic waters. Kulluk could drill safely in first-year ice up to 1.2 metres thick. Dome eventually acquired the vessel, which then passed progressively through acquisitions to Amoco and then BP. BP sold this venerable tool for scrap at the end of the millennium. The major Beaufort explorers experimented with a variety of new technologies and produced some of the most costly and specialized drilling systems in the world. Some of these were extensions of artificial island technologies; design engineers concentrated on ways to protect the island from erosion and impact. In shallow water, the standard became the sacrificial beach island. This island had long, gradually sloping sides against which the vengeance of weather and sea could spend themselves.


East and west coasts Scotian Shelf: The site of Canada's first salt water offshore well was 13 kilometres off the shores of Prince Edward Island. Spudded in 1943, the Hillsborough #1 well was drilled by the Island Development Company.

The company used a drilling island constructed in eight metres of water of wood and some 7,200 tonnes of rock and concrete. The well reached 4,479 metres at a cost of $1.25 million - an extremely expensive well in that era. Part of the Allied war effort, Hillsborough was declared dry and abandoned in September 1945. In 1967 Shell drilled the first well off Nova Scotia, the Sable Island C-67 well. Located on desolate, sandy Sable Island (best known for its herd of wild horses), the well bottomed in gas-bearing Cretaceous rocks.

Drilling stopped there because the technology did not exist to handle the super-pressures the well encountered. Shell's experience at this well foreshadowed two future developments on the Scotian Shelf. First, major discoveries offshore Nova Scotia would generally be natural gas reservoirs. Second, they would involve high pressures. In the early 1980s, two discovery wells - Shell's Uniacke G-72 and Mobil's West Venture N-91 - actually blew wild.

The Uniacke well took about ten days to bring under control. By contrast, the blowout at West Venture took eight months. West Venture started as a surface blowout, and was swiftly shut in. But the well then blew out underground. High-pressure natural gas burst through the well's casing, and began rushing from a deep zone into a shallow one. In oil industry parlance, the blowout "charged" the shallower geological zone, drastically increasing reservoir pressure. The cost of bringing this one well under control was a phenomenal $200 million.

The industry made other modest oil and gas discoveries in its early years off Nova Scotia - for example, Shell's Onandaga E-84 gas well, drilled to a depth of 3,988 metres in 1969. And in 1973, Mobil spudded the D-42 Cohasset well on the western rim of the Sable sub-basin. Mobil's bit found almost 50 metres of net oil pay in eleven zones of Cretaceous lower Logan Canyon sands. However, a follow-up well five years later found only water-bearing sands, and the company suspended work on the field.

Mobil moved to other Scotian Shelf locations, discovering the promising Venture gas field in 1979. Located on a seismic prospect which had been recognized some years earlier, Mobil had waited to drill the Venture probe because the structure was deep and could contain high-pressure zones like those which had halted drilling at Sable Island in the previous decade. The Venture discovery well cost $40 million, then a startling price for a single well.

Ironically, the first commercial offshore discovery, Mobil's 1973 Cohasset discovery, appeared relatively inconsequential when found. But toward the end of the 1980s, a combination of exploration successes and innovative thinking led to development of a field which most of the industry had seen as uneconomic. In December 1985, Petro-Canada spudded the Cohasset A-52 step-out well to explore the Cohasset structure southwest of Mobil's 1973 discovery well.

Unlike the disappointing 1978 stepout, that hole tested oil at a combined rate of 4,500 cubic metres per day from six zones. Following up on the positive results of the A-52 well, Shell drilled a discovery well at Panuke, eight kilometres southwest of Cohasset. The Shell Panuke B-90 wildcat encountered a relatively thin zone that tested light oil at a rate of 1,000 cubic metres per day. The following year, Petro-Canada drilled the F-99 delineation well at Panuke. That well tested oil at 8,000 cubic metres a day for six days.

While the Cohasset and Panuke discoveries were marginal by themselves, a consulting firm hired by Crown corporation Nova Scotia Resources Limited seized on the idea of joining them together. By forming a joint venture with British-based LASMO plc., which formed a Nova-Scotian affiliate to operate the field, NSRL was able to make the project a financial and technical success, although in the end production was much less than expected.

Newfoundland and Labrador: The bitter-cold Labrador Shelf of Newfoundland and Labrador was another prospective exploration province in the early period of eastern offshore exploration. First drilled in 1971, all wells in those deep waters were drilled from dynamically positioned drillships. Icebergs calved from the glaciersof Greenland and Labrador soon earned this stretch of water the unaffectionate nickname "Iceberg Alley." Icebergs drifting toward drilling equipment posed a unique hazard for the industry in that forbidding environment. But using a blend of cowboy and maritime technology, Labrador drillers handled the problem by lassoing the bergs with nylon ropes and steel hawsers, then towing them out of the way.

 In the end, however, worsening exploration economics and poor drilling results dampened the industry's enthusiasm for the area. Drilling stopped in the early 1980s. It continued, however, in the more southerly waters off the Rock of Newfoundland. The most promising drilling off Canada's east coast took place on the Grand Banks - particularly the Avalon and Jeanne d'Arc basins. Exploration began in the area in 1966 and, save one oil show in 1973, the first 40 wells on the Grand Banks were dry.

Then, in 1979, came the Hibernia oil strike, which changed the fortunes of the area. Although not large enough to be commercial at the time of discovery, the next nine wildcats were important. However, two discoveries from the mid-1980s - Terra Nova and White Rose - proved to be more easily producible than Hibernia. Chevron drilled the Hibernia discovery well to earn a commercial interest in that Grand Banks acreage. The field is 315 kilometres east-southeast of St. John's, and water depth is about 80 metres.

Between 1980 and 1984, Mobil drilled nine delineation wells in the field at a cost of $465 million. Eight of those wells were successful, and they enabled the industry to establish that the field has recoverable oil reserves of around 100 million cubic metres. Bringing the field on production would still be a long time coming. It involved settling a jurisdictional dispute between Newfoundland and Canada over ownership of offshore minerals and other issues. Lengthy fiscal negotiations began in 1985, shortly after Mobil submitted a development plan to the two governments.

Not until 1988 did the two governments reach agreement on the development with Mobil, Petro-Canada, Chevron and Gulf - the companies with interests in the Hibernia field. By the terms of this agreement, the federal government would provide $1 billion in grants, $1.66 billion in loan guarantees and other assistance to the $5.2 billion development project. These concessions were necessary because government insistence on a huge, expensive concrete production platform (the Gravity Based System) had made the field uneconomic. A floating platform like those used in the North Sea would be far less expensive, since construction of a Gravity Based System was labour-intensive. However, it arguably has safety advantages in the iceberg-prone Grand Banks. For governments, the high cost factor was actually appealing from a regional development standpoint, since Newfoundland has chronically high unemployment.

In fact, one appeal to governments of this vast project was that, whether profitable to its owners or not, it would generate revenue which would stimulate the economy of Canada's poorest province. The importance of safety was also critical, especially because of an industrial disaster off Canada's east coast early in the 1980s. Since the oil industry began, periods of discovery have occasionally taken a human toll. For Canada's petroleum industry, the worst incident was the Ocean Ranger disaster of 1982. In that terrible tragedy, a semi-submersible offshore drilling rig working in Canada's east coast went down in a winter storm, taking 84 hands into the sea. None survived.

West Coast: A sedimentary basin also exists off the west coast of Canada, and some exploratory drilling has taken place there. From 1967 to 1969, Shell drilled 14 deep dry holes - some west of Vancouver, others in Hecate Strait beside the Queen Charlotte Islands. Exploration off the west coast stopped in 1971 when the federal and British Columbia governments agreed to a moratorium on exploration pending the results of studies into the environmental impact of drilling.

In 1986 a government-appointed commission recommended an end to the moratorium. The province had still not acted by 1989, however, when an American barge spilled oil off the British Columbia coast. A few months later came the disastrous Exxon Valdez oil spill off Alaska. Although neither of these spills was related to crude oil exploration or production, they made it politically impossible for governments to lift the moratorium.


And the Future? Two global questions have particular resonance for the sector. One pertains to the matter of supply. An increasingly widespread notion has it that the world's oil production will soon peak. This hypothesis is widely known as the Hubbert peak theory, or peak oil. If true, it has huge implications for oil prices, which could become economically destabilizing. The other trend to which petroleum production is inextricably linked is that of global warming. Fossil fuels like oil and gas are the primary contributors to this phenomenon. As these issues play out in coming decades, they could have huge impacts on economic and environmental matters in Canada as throughout the world.

History of the Petroleum Industry in Canada

The Canadian petroleum industry arose in parallel with that of the United States, but developed in quite a different way. Canada's unique geography, geology, resources and patterns of settlement have been key factors in the history of Canada. The development of the petroleum sector helps illustrate how they have helped make the nation quite distinct from her neighbour to the south.

Although the conventional oil and gas industry in western Canada is mature, the country's Arctic and offshore petroleum resources are mostly in early stages of exploration and development. Canada became a natural gas-producing giant in the late 1950s and is second, after Russia, in exports; the country also is home to the world's largest natural gas liquids extraction facilities. The industry started constructing vast networks of pipelines in the 1950s, thus beginning to develop domestic and international markets in a big way.

 Despite billions of dollars of investment, her bitumen - especially within the Athabasca oil sands - is still only a partially exploited resource. By 2025 this and other non-conventional oil resources - the northern and offshore frontiers and heavy crude oil resources in the West - could place Canada in the top ranks among the world's oil producing and exporting nations. In a 2004 reassessment of global resources, America's EIA put Canadian oil reserves second; only Saudi Arabia has greater potential. However, many oil experts argue that Saudi potential is highly limited, so Canada could well be number one.

 Many of the stories surrounding the petroleum industry's early development are colourful. The developing oilpatch involved rugged adventurers, the occasional fraud, important innovations and, in the end, world-class success. Canadian petroleum production is now a vital part of the national economy and an essential element of world supply.

 Early origins The early uses of petroleum go back thousands of years. But while people have known about and used petroleum for centuries, Charles Nelson Tripp was the first Canadian to recover the substance for commercial use. The year was 1851; the place, Eniskillen Township on the north shore of Lake Erie. It was there that Tripp started dabbling in the mysterious gum beds near Black Creek. This led to incorporation of the first oil company in Canada. Parliament chartered the International Mining and Manufacturing Company, with C.N. Tripp as president, on December 18, 1854.

The charter empowered the company to explore for asphalt beds and oil and salt springs, and to manufacture oils, naphtha paints, burning fluids, varnishes and other such products. International Mining and Manufacturing was not a financial success, but Tripp’s asphalt received an honourable mention for excellence at the Paris Universal Exhibition in 1855. Several factors contributed to the downfall of the operation. Lack of roads in the area made the movement of machinery and equipment to the site extremely difficult. And after every heavy rain the area turned into a swamp and the gum beds made drainage extremely slow. This added to the difficulty of distributing finished products.

When James Miller Williams became interested and visited the site in 1856, Tripp unloaded his hopes, his dreams and the properties of his company, saving for himself a spot on the payroll as landman. The former carriage builder formed J.M. Williams & Company in 1857 to develop the Tripp properties. Besides asphalt, he began producing kerosene.

A North American first Stagnant, algae-ridden surface water lay almost everywhere. To secure better drinking water, Williams dug a well a few yards down an incline from his plant. At a depth of 20 metres the well struck free oil. It became the first oil well in North America, remembered as the Williams No. 1 well at Oil Springs, Ontario.

Some historians challenge Canada’s claim to North America’s first oil field, arguing that Pennsylvania’s famous Drake well was the continent’s first. But there is enough evidence to support Williams, not least of which is that the Drake well did not come into production until August 28, 1859. The controversial point might be that Williams found oil above bedrock while “Colonel” Edwin Drake’s well located oil within a bedrock reservoir.

We do not know exactly when Williams abandoned his Oil Springs refinery and transferred his operations to Hamilton. He was certainly operating there by 1860 however. Spectator advertisements offered coal oil for sale at 16 cents per gallon for quantities from 4,000 to 100,000 gallons.

Williams reincorporated there as The Canadian Oil Company (perhaps provisionally as the Canada Rock Oil Company). His company produced oil, refined it and marketed refined products. That mix of operations qualify Canadian Oil as the world’s first integrated oil company. Exploration in the Lambton county backwoods quickened with the first flowing well in 1860: Previous wells had relied on hand pumps. The first gusher blew in on February 19, 1862 when Hugh Nixon Shaw struck oil at 48 metres. For a week the oil gushed unchecked, eventually coating the distant waters of Lake St. Clair with a black film.

Dr. A. Winchell, in his Sketches of Creation, refers to this oil gusher (though not very accurately) in the following passage.

Though Western Pennsylvania has produced many flowing wells of wonderful capacity, there is no quarter of the world where production has attained such prodigious dimensions as in 1862 upon Oil Creek (Black Creek?) in the Township of Eniskillen, Ontario. The first flowing well was struck there January 11, 1862, and before October not less than 35 wells had commenced to drain a storehouse which provident nature had occupied untold thousands of years in filling for the uses of man. The price had fallen to ten cents a barrel, three years later that oil would have brought ten dollars a barrel in gold. From detailed determinations I have ascertained that during the spring and summer of 1862, no less than five million barrels of oil floated off upon the waters of Black Creek.

Following William’s example, practically every producer in the infancy of the oil business became his own refiner. Seven refineries were operating in Petrolia, Ontario in 1864 and 20 in Oil Springs. Together, they processed about 80 cubic metres of oil per day. In 1865 oil was selling for $70 per cubic metre ($11.13 per barrel). But the fields of Ontario delivered too much too quickly, and by 1867 the price had dropped to $3.15 per cubic metre ($0.50 per barrel). By 1870, Oil Springs and Bothwell were both dead fields, but other booms followed as drillers tapped deeper formations and new fields. Although the industry had a promising start in the east, Ontario’s status as an important oil producer did not last long. Canada became a net importer of oil during the 1880s. Dependence on neighbouring Ohio as a crude oil supplier increased after the automobile rolled into Canada in 1898.


Canadian drillers Canadians developed petroleum expertise in those early days. The Canadian “oil man” or driller became valued the world over. Petrolia drillers developed the Canadian pole-tool method of drilling which was especially useful in new fields where rock formations were a matter for conjecture. The Canadian technique was different from the American cable-tool method. Now obsolete, cable-tool drilling uses drilling tools suspended from a cable which the driller paid out as the well deepened.

Canada’s pole-tool rig used rods or poles linked together, with a drilling bit fixed to the end of this primitive drilling “string.” Black-ash rods were the norm in early Petrolia. Iron rods came later. Like the cable tool system, pole-tool drilling used the weight of the drill string pounding into the ground from a wooden derrick to make hole. The record is not complete enough to show all the locations Canadians helped to drill. However, Petrolia drillers unquestionably helped drill for oil in Java, Peru, Turkey, Egypt, Russia, Venezuela, Persia, Rumania, Austria and Germany.

One of the best known Canadian drilling pioneers was William McGarvey. McGarvey acquired oil properties in Galicia (now part of Poland) and amassed a large fortune - then saw his properties destroyed when Russian and Austrian armies swept across the land during the First World War. Today, Canadian drillers still move to far away places to practice their widely respected skills.

  Early eastern natural gas The natural gas industry was also born in eastern Canada. Reports from around 1820 tell of youngsters at Lake Ainslie, Nova Scotia, amusing themselves by driving sticks into the ground, pulling them out, then lighting the escaping natural gas.

 In 1859 an oil explorer found a natural gas seep near Moncton, New Brunswick. Dr. H.C. Tweedle found both oil and gas in what became the Dover field, but water seepage prevented production of these wells. An offshoot of the oil drilling boom was the discovery of gas containing poisonous hydrogen sulphide (“sour” gas) near Port Colborne, Ontario. That 1866 discovery marked the first of many gas fields found later in the southwestern part of the province. Eugene Coste, a young Paris-educated geologist who became the father of Canada’s natural gas industry, brought in the first producing gas well in Essex County, Ontario, in 1889.

Canada first exported natural gas in 1891 from the Bertie-Humberstone field in Welland County to Buffalo, New York. Gas was later exported to Detroit from the Essex field through a 20-centimetre pipeline under the Detroit river. In 1897, the pipeline stretched the Essex gas supply to its limit with the extension of exports to Toledo, Ohio. This prompted the Ontario government to revoke the licence for the pipeline. And in 1907 the province passed a law prohibiting the export of natural gas and electricity.

 In 1909, New Brunswick’s first successful gas well came in at Stoney Creek near Moncton. This field still supplies customers in Moncton, although the city now has a propane air plant to augment the limited natural gas supply. The year 1911 saw a milestone for the natural gas industry when three companies using Ontario’s Tilbury gas field joined to form Union Gas Company of Canada, Limited. In 1924, Union Gas was the first company to use the new Seabord or Koppers process to remove poisonous hydrogen sulphide from Tilbury gas. Union became one of the largest corporations in Canada before its acquisition by Duke Energy, a US firm.

The move west These were the early days in Canada’s petroleum industry. The cradle was in eastern Canada, but the industry only began to come of age with discoveries in western Canada, notably Alberta. There, the Western Canadian Sedimentary Basin is at its most prolific.

Alberta’s first recorded natural gas find came in 1883 from a well at CPR Siding No. 8 at Langevin, near Medicine Hat. This well was one of a series drilled at scattered points along the railway to get water for the Canadian Pacific Railroad’s steam-driven locomotives. The unexpected gas flow caught fire and destroyed the drilling rig. This find prompted Dr. George M. Dawson of the Geological Survey of Canada to make a notable prediction. Noting that the rock formations penetrated in this well were common in western Canada, he prophesied correctly that the territory would some day produce large volumes of natural gas.

A well drilled near Medicine Hat in 1890 - this time in search of coal - also flowed natural gas. The find prompted town officials to approach the CPR with a view to drilling deeper wells for gas. The resulting enterprise led to the discovery in 1904 of the Medicine Hat gas sand. Later, that field went on production to serve the city, the first in Alberta to have gas service. When Rudyard Kipling travelled across Canada in 1907, he remarked that Medicine Hat had “all Hell for a basement.”

 In northern Alberta, the Dominion Government began a drilling program to help define the region’s resources. Using a rig brought from Toronto, in 1893 contractor A.W. Fraser began drilling for liquid oil at Athabasca. He abandoned the well in 1894. In 1897 Fraser moved the rig to Pelican Rapids, also in northern Alberta. There it struck gas at 250 metres. But the well blew wild, flowing uncontrolled for 21 years. It was not until 1918 that a crew led by A.W. Dingman succeeded in killing the well. Dingman, who played an important role in the industry’s early years, began providing natural gas service in Calgary through the Calgary Natural Gas Company. After receiving the franchise in 1908, he drilled a successful well in east Calgary on the Walker estate (a well which continued producing until 1948). He then laid pipe from the well to the Calgary Brewing and Malting Company, which began using the gas on April 10, 1910. Later mains provided the city with domestic fuel and street lighting.


Oil in the Alberta foothills The earliest efforts to develop western Canadian oil were those of John George (Kootenai) Brown. This colourful character - a frontiersman with an Eton and Oxford education - was probably Alberta’s first homesteader. In 1874, Brown filed the following affidavit with Donald Thompson, the resident solicitor at Pincher Creek:

I was engaged as a guide and packer by the eminent geologist Dr. George M. Dawson, and he asked me if I had seen oil seepages in that area, and if I did see them, would I be able to recognize them. He then went into a learned discussion on the subject of petroleum. Subsequently some Stoney Indians came to my camp and I mixed up some molasses and coal oil and gave it to them to drink, and told them if they found anything that tasted or smelled like that to let me know. Sometime afterwards they came back and told me about the seepages at Cameron Brook.

In 1901, John Lineham of Okotoks organized the Rocky Mountain Drilling Company. In 1902 he drilled the first oil exploration well in Alberta on the site of these seepages (now in Waterton Lakes National Park). Despite a small recovery of 34? API sweet oil, neither this well nor seven later exploration attempts resulted in production.

In 1909, exploration activity shifted to Bow Island in south central Alberta, where a natural gas discovery launched Canada’s western gas industry. The same Eugene Coste who had found gas in Ohio and again in southern Ontario drilled the discovery well, Bow Island No. 1 (better known as “Old Glory”). Pipelines soon transported Bow Island gas to Medicine Hat, Lethbridge and Calgary, which used the fuel for heat and light. Eugene Coste became the founder of the Canadian Western Natural Gas Company when he merged the Calgary Natural Gas Company, Calgary Gas Company and his Prairie Fuel Company in August 1911.

In early 1914, oil fever swept Calgary and other parts of southern Alberta. Investors lined up outside makeshift brokerage houses to get in on exploration activity triggered by the 1914 discovery of wet gas and oil at Turner Valley, southwest of Calgary. So great was the excitement that, in one 24-hour period, investors and promoters formed more than 500 “oil companies.” Incorporated a year earlier, the Calgary Stock Exchange was unable to control some of the unscrupulous practices that relieved many Albertans of their savings. The discovery well that set off this speculative flurry belonged to the Calgary Petroleum Products Company, an enterprise formed by W.S. Herron, William Elder and A.W. Dingman. Named Dingman No. 1 after the partner in charge of drilling, the well produced natural gas dripping with gas liquids, sometimes referred to as naphtha. Stripped from the gas, these liquids were pure enough to burn in automobiles without refining. The mix became fondly known as “skunk” gasoline because of its distinctive odour.

Pioneered in Turner Valley, natural gas liquids extraction eventually became an important Canadian industry in its own right, as the story of its development illustrates. The Dingman well and its successors were really “wet” natural gas wells rather than true oil wells. The high expectations raised by the initial discovery gave way to disappointment within a few years. Relatively small volumes of liquids flowed from the successful wells. By 1917, the Calgary City Directory listed only 21 “oil mining companies” compared with 226 in 1914. Drilling continued in Turner Valley, however, and in 1924 came another significant discovery.

The Calgary Petroleum Products Company, reorganized as Royalite Oil Company, drilled into Paleozoic limestone. The well blew out at 1,180 metres. The blowout at Royalite No. 4 was probably the most spectacular in Alberta’s history. Initially flowing at 200,000 cubic metres per day, the flow rate increased to some 620,000 cubic metres per day when the well was shut in. The shut in pressure continued to rise and, when the gauge read 7,930 kilopascals, the drillers ran for their lives. In 20 minutes, 939 metres of 21-centimetre and 1,052 metres of 16-centimetre pipe - together weighing 85 tonnes - rose to the top of the derrick. The well blew wild, caught fire, and destroyed the entire rig. The fire blazed for 21 days. Finally, wild well control experts from Oklahoma used a dynamite explosion to blow away the flames. They then applied the combined steam flow of seven boilers to keep the torch from lighting again.

Unknown to the explorers of the day, these wells extracted naphtha from the natural gas cap over Turner Valley’s oilfield. After two years of off-and-on drilling, in 1936 the Royalites No. 1 well finally drilled into the principal oil reservoir at more than 2,500 metres. This well, which established Turner Valley as Canada’s first major oil field and the largest in the British Commonwealth, used innovative financing.

Promoters ordinarily sold shares in a company to finance new drilling programs, but in the Depression money for shares was hard to come by. Instead, R.A. Brown, George M. Bell and J.W. Moyer put together an enterprise called Turner Valley Royalties. That company offered a percentage share of production (a “royalty”) to those willing to put money into the long-shot venture. Recoverable oil reserves from the Turner Valley field were probably about 19 million cubic metres. Although locals boasted at the time that it was "the biggest oil field in the British Empire," Turner Valley was not a large field by later standards. (By way of comparison, the Pembina field in central Alberta - Canada’s largest - had recoverable reserves of about 100 million cubic metres.) But besides being an important source of oil supply for the then-small market in western Canada, the field had an important long-term impact. It helped develop petroleum expertise in Canada's west, and it established Calgary as Canada’s oil and gas capital.

  Waste and conservation Enormous waste of natural gas was a dubious distinction that Turner Valley claimed for many years. Royalite had a monopoly on sales to Canadian Western Natural Gas Company, so other producers could not sell their gas. But all the producers wanted to cash in on the natural gas liquids for which markets were growing. So the common practice became to pass the gas through separators, then flare it off. This greatly reduced the pressure on the oil reservoir, reducing the amount of recoverable oil. But the size of the problem was not clear until the oil column was later discovered. The flares were visible in the sky for miles around. Many of these were in a small ravine known to locals as Hell’s Half Acre. Because of the presence of the flares, the grass stayed green year-round and migrating birds wintered in their warmth. A newspaper man from Manchester, England, described the place with these florid words:

... Seeing it you can imagine what Dante’s inferno is like ... a rushing torrent of flame, shooting 40 feet high ... a ruddy glow to be seen for 50 miles ... most awe-inspiring spectacle ... men have seen the hosts of hell rising ... the titanic monster glowering from the depths of Hades ...

While the flaring continued, the business community seriously discussed ways to market the gas. For example, in early 1929 W.S. Herron, a Turner Valley pioneer, publicly promoted the idea of a pipeline to Winnipeg. At about the same time, an American company made application for a franchise to distribute natural gas to Regina. The Bank of North Dakota offered to buy 1.4 million cubic metres per day.

By early 1930, there was talk of a pipeline from Turner Valley to Toronto. Estimates showed that gas delivery to Toronto would cost $2.48 per thousand cubic metres. A parliamentary committee looked into ways to force waste gas down old wells, set up carbon black plants or export the gas to the United States. Another proposal called for the production of liquefied methane. Unfortunately, the Depression had already gripped Canada, which might have been more severely affected by this economic catastrophe than any other country in the world. Capital investment became less and less attractive and drilling at Turner Valley ground to a halt as the economic situation worsened.

 The federal government owned the mineral rights not held by the Canadian Pacific Railway, the Calgary and Edmonton Corporation and by individual homesteads. The government tried to curb the flaring of gas, but legal difficulties made its efforts of little avail. One federal conservation measure succeeded, however. On August 4, 1930 began operations to store surplus Turner Valley gas in the depleted Bow Island field. An earlier effort to control waste resulted in an Order-in-Council passed April 26, 1922 prohibiting offset drilling closer than 70 metres from any lease boundary.

Keeping wells spaced away from each other, as this regulation did, prevents too rapid depletion of a field. After a bitter appeal to Britain’s Privy Council, the federal government transferred ownership of natural resources to the provinces effective October 1, 1930. Soon after, the Alberta government enacted legislation to regulate oil and gas wells. In October 1931, the Legislature passed legislation (based on a report by a provincial advisory committee) to control the Turner Valley situation. While most operators supported this act, one independent operator successfully launched legal proceedings to have the Alberta act declared ultra vires. The provincial government asked the federal government to pass legislation confirming the Alberta law. Ottawa, however, shrugged off the request saying that natural resources were under provincial jurisdiction 

During 1932, the newly created Turner Valley Gas Conservation Board proposed cutting production in half and unitizing the field to reduce waste. But the producers could not reach agreement on this issue, and the idea fell by the wayside. And so legal wrangling tied up any real conservation measures until 1938. In that year, the federal government confirmed the province’s right to enact laws to conserve natural resources. With this backing, in July 1938 the province set up the Alberta Petroleum and Natural Gas Conservation Board (today known as the Alberta Energy and Utility Board). New unitization rules limited well spacing to about 16 hectares per well.

The board also reduced oil production from the field. This reduced the flaring of natural gas, but it came only after the waste of an estimated 28 billion cubic metres. The lessons of Turner Valley made an impression around the world as the need for conservation and its impact on ultimate recovery became better understood. Countries framing their first petroleum laws have often used the Alberta legislation as a model. Besides contributing to conservation, solving Turner Valley’s technical challenges with innovative technology also helped earn the field a place in early oil and gas history. Uncorrected, drilling holes wandered 22 degrees or more off course.

As the field’s high-pressure gas expanded, it cooled rapidly freezing production equipment. This complicated the production process. Other problems involved external corrosion, casing failures, sulphide stress corrosion cracking, corrosion inside oil storage tanks, and the cold winters. Early drilling was done by wooden cable tool drilling rigs which pounded a hole into the ground. These monsters ruled the drilling scene until the mid-1920s. Rotary drilling (which has since replaced cable tool drilling) and diamond coring made their appearance in Turner Valley in 1925. Nitro-shooting came in 1927 to enhance production at McLeod No. 2. Acidizing made its Canadian debut in 1936 at Model No. 3. Scrubbing gas to extract hydrogen sulphide started in 1925. Field repressurization began in 1944 and waterflooding started in 1948.

Only months after Union Gas completed a scrubbing facility for its Tilbury gas in Ontario, in 1924 Royalite began sweetening gas from the sour Royalite #4 well through a similar plant. This process removed H2S from the gas, but did not extract the sulphur as a chemical element. This development waited until 1952, when a sulphur recovery plant at Turner Valley began producing raw sulphur. Turner Valley oil production peaked in 1942, partly because the Oil and Gas Conservation Board increased allowable production as part of the war effort. During that period exploration results elsewhere in western Canada were disappointing. The only discoveries were small heavy oil fields.

Leduc There were no major new strikes until 1947, when Imperial Oil Ltd. discovered light oil just south of Edmonton. During the 1930s and early 1940s, oil companies tried unsuccessfully to find replacement for declining Turner Valley reserves. Imperial Oil had drilled 133 dry wells in Alberta and Saskatchewan. In 1946, the company decided on one last drilling program from east to west in Alberta. The wells would be “wildcats” - exploratory wells drilled in search of new fields.

The first drill site was Leduc No. 1 in a field on the farm of Mike Turta, 15 kilometres west of Leduc and about 50 kilometres south of Edmonton. Located on a weak seismic anomaly, the well was a rank wildcat. No drilling of any kind had taken place within an 80-kilometre radius. Drilled started on November 20, 1946. It continued through a winter that was “bloody cold,” according to members of the rig crew. At first the crew thought the well was a gas discovery, but there were signs of something more. At 1,530 metres, drilling speeded up and the first bit samples showed free oil in dolomite, a good reservoir rock. After coring, oil flowed to the surface during a drill stem test at 1,544 metres. 

Imperial Oil decided to bring the well in with some fanfare at 10 o’clock in the morning of February 13, 1947. The company invited the mayor of Edmonton and other dignitaries. The night before the ceremony, however, swabbing equipment broke down. The crew laboured to repair it all night. But 10:00 a.m. passed and no oil flowed. Many of the invited guests left. Finally by 4:00 pm the crew were able to get the well to flow.

The chilled onlookers, now numbering only about 100, saw a spectacular column of smoke and fire beside the derrick as the crew flared the first gas and oil. Alberta mines minister N.E. Tanner turned the valve to start the oil flowing (at an initial rate of about 155 cubic metres per day), and the Canadian oil industry moved into the modern era. Imperial lost no time.

On February 12 it started drilling Leduc No. 2, about 3 kilometres southwest of No. 1, trying to extend the producing formation. But nothing showed up at that level and company officials argued over how to proceed. One group proposed abandoning the well, instead drilling a direct offset to No. 1; another group wanted to continue drilling No. 2 into a deep stratigraphic test. But drilling continued. On May 10 at 1,657 metres, No. 2 struck the much bigger Devonian reef, which later turned out to be the most prolific geological formation in Alberta. Leduc No. 1 stopped producing in 1974 after the production of some 50,300 cubic metres of oil and 9 million cubic metres of natural gas.

On November 1, 1989, Esso Resources (the exploration and production arm of Imperial) began producing the field as a gas reservoir. Thus did Canada’s seminal oil discovery become a gas well on its way to extinction. Geological diversity The Leduc discoveries put Alberta on the world petroleum map. News of the finds spread quickly, due in large part to a spectacular blowout in the early days of the development of this field. In March 1948, drillers on the Atlantic Leduc #3 well lost mud circulation in the top of the reef, and the well blew out. In one journalist's words,

The well had barely punched into the main producing reservoir a mile below the surface when a mighty surge of pressure shot the drilling mud up through the pipe and 150 feet into the air. As the ground shook and a high-pitched roar issued from the well, the mud was followed by a great, dirty plume of oil and gas that splattered the snow-covered ground. Drillers pumped several tons of drilling mud down the hole, and after thirty-eight hours the wild flow was sealed off, but not for long. Some 2,800 feet below the surface, the drill pipe had broken off, and through this break the pressure of the reservoir forced oil and gas into shallower formations. As the pressure built up, the oil and gas were forced to the surface through crevices and cracks. Geysers of mud, oil, and gas spouted out of the ground in hundreds of craters over a ten-acre area around the well.

Atlantic #3 eventually caught fire, and the crew worked frantically for 59 hours to snuff out the blaze. It took six months, two relief wells and the injection of 160,000 cubic metres of river water to bring the well under control, an achievement which the crews celebrated on September 9, 1948. Cleanup efforts recovered almost 180,000 cubic metres of oil in a series of ditches and gathering pools. The size of the blowout and the cleanup operation added to the legend. By the time Atlantic #3 was back under control, the whole world knew from newsreels and photo features of the blowout that the words "oil" and "Alberta" were inseparable. Exploration boomed.

By 1950, Alberta was one of the world's exploration hot spots, and seismic activity grew until 1953. After the Leduc strike, it became clear that Devonian reefs could be prolific oil reservoirs, and exploration concentrated on the search for similar structures. A series of major discoveries followed, and the industry began to appreciate the diversity of geological structures in the province that could contain oil. Early reef discoveries included Redwater in 1948, Golden Spike in 1949, Wizard Lake, Fenn Big Valley and Bonnie Glen in 1951 and Westerose in 1952. In 1953, drillers found Pembina, the largest field in western Canada, in a sandstone formation.

By 1956, more than 1,500 development wells dotted the Pembina field, with hardly a dry hole among them. The Swan Hills field, discovered in 1957, exploited a carbonate rock formation. Before Leduc, the petroleum industry had long been familiar with the oil sand deposits. A number of companies were already producing heavy oil in Alberta and Saskatchewan. The Turner Valley petroleum reservoirs near Calgary had been in production for almost 35 years, and the Devonian reef at Norman Wells in the Northwest Territories had been discovered a quarter of a century earlier. In the decade after Leduc, the industry identified half a dozen more reservoir types, mentioned above. And in the years since, the sector has found many more petroleum traps in the Western Canada Basin, especially within Alberta's borders. The region has great geological diversity.

Pipeline networks In 1853, a small gas transmission line in Quebec established Canada as a leader in pipeline construction. A 25-kilometre length of cast-iron pipe moved natural gas to Trois-Rivieres, to light the streets. It was probably the longest pipeline in the world at the time. Canada also boasted the world's first oil pipeline when, in 1862, a line connected the Petrolia oilfield to Sarnia, Ontario. In 1895, natural gas began flowing to the United States from Ontario's Essex field through a 20-centimetre pipeline laid under the Detroit River. In Western Canada, Eugene Coste built the first important pipeline in 1912. The 274-kilometre natural gas line connected the Bow Island gas field to consumers in Calgary.

Canada's debut in northern pipeline building came during World War II when the short-lived Canol line delivered oil from Norman Wells to Whitehorse (964 kilometres), with additional supply lines to Fairbanks and Skagway, Alaska, and to Watson Lake, Yukon. Wartime priorities assured the expensive pipeline's completion in 1944 and its abandonment in 1946. By 1947, only three Canadian oil pipelines moved product to market. One transported oil from Turner Valley to Calgary. A second moved imported crude from coastal Maine to Montreal while the third brought American mid-continent oil into Ontario.

But the Leduc strike and subsequent discoveries in Alberta created an opportunity for pipeline building on a grander scale. As reserves increased, producers clamored for markets. With its population density and an extensive refining system that relied on the United States and the Caribbean for crude oil, Ontario was an excellect prospect. The west coast offered another logical choice - closer still, although separated from the oilfields by the daunting Rocky Mountains. The industry pursued these opportunities vigorously.

 Crude Oil Arteries Construction of the Interprovincial Pipeline system from Alberta to Central Canada began in 1949 with surveys and procurement. Field construction of the Edmonton/Regina/Superior (Wisconsin) leg began early in 1950 and concluded just 150 days later. The line began moving oil from Edmonton to the Great Lakes, a distance of 1 800 kilometres, before the end of the year. In 1953, the company extended the system to Sarnia, Ontario, and in 1957 to Toronto. Until the completion of the Trans Canada gas pipeline, Interprovincial (IPL) was the longest pipeline in the world.

The IPL line fundamentally changed the pricing of Alberta oil to make it sensitive to international rather than regional factors. The wellhead price reflected the price of oil at Sarnia, less pipeline tolls for shipping it there. IPL is by far the longest crude oil pipeline in the western hemisphere. Looping, or constructing additional lines beside the original, expanded the Interprovincial system and allowed its extension into the American midwest and to upstate New York. In 1976, it was 3,680 kilometres through an extension to Montreal.

Although it helped assure security of supply in the 1970s, the extension became a threat to Canadian oil producers after deregulation in 1985. With Montreal refineries using cheaper imported oil, there was concern within the industry that a proposal to use the line to bring foreign oil into Sarnia might undermine traditional markets for Western Canadian petroleum. The oil supply situation on the North American continent grew critical during the Korean War and helped promote construction of the Trans-Mountain pipeline from Edmonton to Vancouver and, later, to the Seattle area. Oil first moved through the 1,200-kilometre, $93 million system in 1953. The rugged terrain made the Trans-Mountain line an extraordinary engineering accomplishment. It crossed the Rockies, the mountains of central British Columbia, and 98 streams and rivers. Where it crosses under the Fraser River into Vancouver at Port Mann, 700 metres of pipe lie buried nearly five metres below the river bed. At its highest point, the pipeline is 1,200 metres above sea level.

To support these major pipelines, the industry gradually developed a complex network of feeder lines in the three most westerly provinces. A historic addition to this system was the 866-kilometre Norman Wells pipeline. This pipeline accompanied the expansion and water flooding of the oilfield, and began bringing 600 cubic metres of oil per day to Zama, in northwestern Alberta, in early 1985. From Zama, Norman Wells oil travels through other crude oil arteries to Alberta and other Canadian refineries.

Gas pipelines and politics Those who applied for permits to export Alberta natural gas made the painful discovery that it was politically more complex to export gas than oil. Canadians tend to view oil as a commodity. However, through much of Canadian history, they have viewed natural gas as a patrimony, an essential resource to husband with great care for tomorrow.

Although the reasons behind this attitude are complex, they are rooted in an incident at the turn of the century, when Ontario revoked export licenses for natural gas to the United States. By the late 1940s Alberta, through its Conservation Board, eliminated most of the wasteful production practices associated with the Turner Valley oil and gas field. As new natural gas discoveries greeted drillers in the Leduc-fuelled search for oil, the industry agitated for licenses to export natural gas. In response, the provincial government appointed the Dinning Natural Gas Commission to inquire into Alberta's likely reserves and future demand.

In its March 1949 report, the Dinning Commission supported the principle that Albertans should have first call on provincial natural gas supplies, and that Canadians should have priority over foreign users if an exportable surplus developed. Alberta accepted the recommendations of the Dinning Commission, and later declared it would only authorize exports of gas in excess of a 30-year supply. Shortly thereafter, Alberta's Legislature passed the Gas Resources Conservation Act, which gave Alberta greater control over natural gas at the wellhead, and empowered the Oil and Gas Conservation Board to issue export permits.

The federal government's policy objectives at the time reflected concern for national integration and equity among Canadians. In 1949, Ottawa created a framework for regulating interprovincial and international pipelines with its Pipe Lines Act. Alberta once again agreed to authorize exports. The federal government, like Alberta, treated natural gas as a Canadian resource to protect for the foreseeable future before permitting international sales. Although Americans were interested in Canadian exports, they understandably wanted cheap gas. After all, their natural gas industry was a major player in the American economy, and American policy-makers were not eager to allow foreign competition unless there was clear economic benefit. Consequently, major gas transportation projects were politically and economically uncertain.

Construction begins Among the first group of applicants hoping to remove natural gas from Alberta was Westcoast Transmission Limited, backed by British Columbia-born entrepreneur Frank McMahon. The Westcoast plan, eventually achieved in a slightly modified form, took gas from northwestern Alberta and northeastern B.C. and piped it to Vancouver and to the American Pacific northwest, supplying B.C.'s interior along the way. Except for a small export of gas to Montana which began in 1951, Westcoast was the first applicant to receive permission to remove gas from Alberta. Although turned down in 1951, Westcoast received permission in 1952 to take 50 billion cubic feet of gas out of the Peace River area of Alberta annually for five years. The company subsequently made gas discoveries across the border in B.C. which further supported the scheme. However, the United States Federal Power Commission (later the Federal Energy Regulatory Commission) rejected the Westcoast proposal in 1954 after three years of hearings and 28 000 pages of testimony.

Within eighteen months, Westcoast returned with a revised proposal, found a new participant in the venture, and received FPC approval. Construction began on Canada's first major gas export pipeline. The Canadian section of the line cost $198 million to build and at the time was the largest private financial undertaking in the country's history. Built in the summer seasons of 1956 and 1957, the line moved gas from the Fort St. John and Peace River areas 1,250 kilometres to Vancouver and the American border.

TransCanada PipeLines Limited also applied early for permission to remove natural gas from Alberta. Two applicants originally expressed interest in moving gas east: Canadian Delhi Oil Company (now called TCPL) proposed moving gas to the major cities of eastern Canada by an all-Canadian route, while Western Pipelines wanted to stop at Winnipeg with a branch line south to sell into the midwestern United States.

In 1954 C.D. Howe forced the two companies into a shotgun marriage, with the all-Canadian route preferred over its more economical but American-routed competitor. This imposed solution reflected problems encountered with the construction of the Interprovincial oil pipeline. Despite the speed of its construction, the earlier line caused angry debate in Parliament, with the Opposition arguing that Canadian centres deserved consideration before American customers and that "the main pipeline carrying Canadian oil should be laid in Canadian soil". By constructing its natural gas mainline along an entirely Canadian route, TCPL accommodated nationalist sentiments, solving a political problem for the federal government. The regulatory process for TCPL proved long and arduous.

After rejecting proposals twice, Alberta finally granted its permission to export gas from the province in 1953. At first, the province waited for explorers to prove gas reserves sufficient for its thirty-year needs, intending to only allow exports in excess of those needs. After clearing this hurdle, the federal government virtually compelled TCPL into a merger with Western pipelines. When this reorganized TCPL went before the Federal Power Commission for permission to sell gas into the United States, the Americans greeted it coolly. The FPC proved sceptical of the project's financing and unimpressed with Alberta's reserves. Engineering problems made the 1,090-kilometre section crossing the Canadian Shield the most difficult leg of the TransCanada pipeline. Believing construction costs could make the line uneconomic, private sector sponsors refused to finance this portion of the line.

Since the federal government wanted the line laid for nationalistic reasons, the reigning Liberals put a bill before Parliament to create a crown corporation to build and own the Canadian Shield portion of the line, leasing it back to TCPL. The government restricted debate on the bill in order to get construction underway by June, knowing that delays beyond that month would postpone the entire project a year. The use of closure created a furore which spilled out of Parliament and into the press. Known as the Great Pipeline Debate, this parliamentary episode contributed to the John Diefenbaker government's defeat at the polls in 1957. But the bill passed and construction of the TransCanada pipeline began.

The completion of this project was a spectacular technological achievement. In the first three years of construction (1956-58), workers installed 3,500 kilometres of pipe, stretching from the Alberta-Saskatchewan border to Toronto and Montreal. Gas service to Regina and Winnipeg commenced in 1957 and the line reached the Lakehead before the end of that year. In late 1957, during a high pressure line test on the section of the line from Winnipeg to Port Arthur (today called Thunder Bay), about five and a half kilometres of pipeline blew up near Dryden, Ontario. After quick repairs, the line delivered Alberta gas to Port Arthur before the end of the year, making the entire trip on its own wellhead pressure. Building the Canadian Shield leg required continual blasting. For one 320-metre stretch, the construction crew drilled 2.4 metre holes into the rock, three abreast, at 56-centimetre intervals. Dynamite broke up other stretches, 305 metres at a time.

On October 10, 1958, a final weld completed the line and on October 27, the first Alberta gas entered Toronto. For more than two decades, the Trans-Canada pipeline was the longest in the world. Only in the early 1980s was its length finally exceeded by a Soviet pipeline from Siberia to Western Europe.