Genesis of a Giant

Thirty years ago this month, Syncrude produced its first barrel of oil. This article appears in the July 2008 issue of The Oilsands Review.

By Peter McKenzie-Brown

Syncrude triumphed over an era which was eerily similar to the one we’re in today.

Many commentators have remarked upon the likenesses between then, the 1970s, and now. A financial crisis in the United States led it in 1971 to end the link between the dollar and gold and to adopt a wave of protectionist policies. America and its allies were mired in interminable and expensive Asian wars. Because of high liquidity in capital markets, price inflation became endemic. Stock markets flattened and employment in non-resource sectors slumped. Rapidly rising food costs contributed to great suffering in the Third World, as it was then known, and to the poor in the richer countries.

After a 20-year decline, in 1973 real oil prices rose rapidly because of new demand, declining supply from key producers, and geopolitical events focused in the Middle East. The oil industry boomed; drilling, development and construction costs skyrocketed. As the decade wore on, the belief that oil was about to “run out” became widespread. So did the view that humanity would soon choke on its own pollution. By the end of that spooky period, forecasts of oil prices tripling from their already high base were common.

Given the similarities between that era and this, it is ironic that the early 1970s were a threat to Syncrude’s existence. The giant seemed doomed until three governments agreed to serve as midwives. This largely forgotten tale is an important part of the plant’s heritage. Few people remember that today’s world beater was nearly the victim of a breached birth.

Origins: For oilsands development to make any sense at all, Alberta needed appropriate policy. This is not a new idea. A hundred years ago Canada’s Senate held hearings on how to develop them.

Having established itself in 1930 as the rightful owner of the resource (by appeal to Britain’s Privy Council), Alberta’s government intensified its efforts to create a long-term policy just after the Second World War. The effort was short-lived, however, because of important discoveries of light oil at Leduc and elsewhere, beginning in 1947. Why develop the sands when high-quality crude was there for the pumping?

The province has always understood that its long-term future lies with the sands, however. Despite gathering volumes of conventional oil production, in 1962 the government announced an oilsands policy for the long term. In response, two proposals came forward. Cities Service Athabasca Inc. proposed a 100,000 barrel per day plant at the site of its Mildred Lake pilot project – the site of the Syncrude project. Including a pipeline to Edmonton, the plant was to cost $56 million, with construction beginning in 1965 and completion in 1968.

In that round the winning bid was for the much smaller Great Canadian Oil Sands Limited (today’s Suncor plant), which initially received approval for a 30,000 barrel per day plant. By the original terms of its license, production from the plant could not exceed 5% of total volumes in markets already supplied by conventional oil from Alberta.

For its part, Cities Service got a rejection letter. Undeterred, in 1964 the company assembled the Syncrude consortium, which later applied for a much larger (140,000 barrel per day) plant. The proposal received approval in late 1969. But before the plant shipped its first barrel of oil nearly ten years later, the project experienced a financial crisis.

Crisis: The reason for the long gap between approval and completion was an alarming escalation of costs besetting major North American projects. High inflation multiplied budgets for practically every aspect of the Syncrude project.

Reviewing project costs in late 1973, the Syncrude consortium found that costs had more than doubled, from $1 billion to $2.3 billion. One of the partners, Atlantic Richfield, needed cash to develop its Prudhoe Bay interests and frankly saw its Alaskan bonanza as a far more attractive bet than investing in the oilsands. In December 1974, the company withdrew its 30 per cent participation in the project. A few days later, the three remaining partners – Gulf Oil, Imperial and Cities Service – informed the Alberta government that they were unwilling to risk more than $1 billion on the project. They would need another $1 billion of risk capital if the project were to go on.

The prospect of Syncrude collapsing was a political and economic nightmare. The world was reeling from the oil crisis of the day. Policy-makers in the rich Western countries considered it a matter of national urgency to develop stable, secure energy supplies. The rich world was experiencing the worst recession since the Second World War, and Canada desperately needed economic stimulus. Because the oilsands were so large and development was so clearly possible, getting Syncrude back on track looked like Canada's best bet for both coherent policy and economic stimulus. From coast to coast to coast, Canadians came to believe the project must not falter.

Alberta reviewed the cost estimates given by the Syncrude consortium. When it found those estimates weren’t out of line, the province helped convene, in February 1973 in Winnipeg, a historic meeting between consortium members and governments.
Three governments joined the consortium as commercial partners, thereby salvaging the project. The federal government took a 15% interest, Alberta 10% and Ontario 5%. Alberta also took full ownership in the no-risk pipeline and electrical utility. The private partners agreed to take a $1.4 billion interest in the project, but gave Alberta the option to convert a $200 million loan to Gulf and Cities Service into equity.

The Billionth Barrel: Syncrude went into operation in the summer of 1978 and produced 5 million barrels of oil within a year. World oil prices leaped skyward in 1979-80 and remained high for the first half of the 1980s. This helped Syncrude become successful financially as well as technically. The collapse of oil prices in 1986 – followed by 15 years of lower prices – intensified the organization’s incentive to reduce costs per barrel while increasing production. Production rose steadily in the ensuing years and, on April 16, 1998, the plant piped its billionth barrel down the line – five years ahead of schedule.

Ten years later, a counter on the Syncrude website zips along at a rate of four barrels a second, estimating the volume the plant has produced: as this magazine goes to press, about 1.9 billion barrels. A giant since inception, Syncrude is too big and complex to easily conceptualize. The largest producer of crude oil from oilsands, 350,000 barrels of oil pour from its processing vessels every day. Every twenty-four hours, the sands wear the metallic equivalent of two full-size pickup trucks off the plant’s mining equipment.

One of the most complex industrial operations anywhere, Syncrude operates the largest network of open-pit mines. It is Canada’s largest single source of oil, producing volumes equal to 15% of total national requirements. It extracts the raw oil known as bitumen from the sand and then turns it into the sweet light crude oil known as Syncrude Sweet Blend by processing it in vast upgrading vessels. The plant’s “synthetic crude” (hence the name) moves by pipeline to refineries in Canada and the United States.

Syncrude plans to increase production to about 500,000 barrels of crude oil per day within the next decade. As it does so – and as it has done for the last three decades – the consortium will continue to introduce new technologies and processes. These will improve the plant’s efficiency and reduce its per-barrel impact on the environment. During the next decade, the consortium estimates, its sulphur dioxide emissions will decline by 60% from today's levels. Reflecting efficiencies of scale and better technology, per barrel energy consumption will drop by 1% annually.

Today the technology is proved, and oilsands development is of global rather than national interest. Many policy-makers now view oilsands development as a critical source of relief for straining international supply. Sitting in the opposition benches are environmental and public health issues. Mainstream in a way they weren’t 30 years ago, they will threaten some of tomorrow’s giants.

Athabasca Chronology

By Peter McKenzie-Brown

• 1714. Hudson’s Bay Company (HBC) fur trader James Knight records in his journal at Fort York (in what is now Manitoba) that Indians told him of a “great river” far inland where “there is a certain gum or pitch that runs down the river in such abundance that they cannot land but at certain places.”

• 1719. Henry Kelsey of HBC’s York Factor (near the western shore of Hudson Bay) notes that Cree Indian Wa-Pa-Sun has brought him a sample “of that gum or pitch that flows out of the banks of the river.”

• 1778. Fur trader Peter Pond reports “springs of bitumen that flow along the ground.”

• 1788. Famed explorer Alexander Mackenzie writes, “at about 24 miles from the fork (of the Athabasca and Clearwater Rivers) are some bituminous fountains into which a pole of 20 feet long may be inserted without the least resistance….The bitumen is in a fluid state and when mixed with gum, the resinous substance collected from the spruce fir, it serves to gum the Indians’ canoes. In its heated state it emits a smell like that of sea coal.”

• 1894. Dominion Government sends rig to drill for oil along the Athabasca River, hoping to find light oil below the oilsands. In 1897 the second well strikes gas and blows wild. The Pelican Rapids well burns an estimated 20 million cubic feet per day until killed in 1918.

• 1907. Alfred von Hamerstein, who claimed to be an immigrant German count, tells a Senate committee “I have all my money put into it (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.”

• 1913. Federal Department of Mines assigns Dr. S.C. Ells, an engineer, to investigate the sands’ economic potential. He proposes using it for road-paving, which becomes a marginal cottage industry.

• 1923. Assigned by the Alberta Research Council to study the oil sands, Dr. Karl Clark and his associate, Sid Blair, build the first bench model of Clark’s hot-water separation plant at the University of Alberta.

• 1925. Alberta Research Council constructs a pilot project using the process near Fort McMurray.

• Bitumount:

• 1925. R.C. Fitzsimmons founds International Bitumen.
1930. The company uses a combination hot water and solvent method to produce bitumen at a location called Bitumount. Plant soon falters.
• 1943. Alberta government makes plans to build an oil sands plant at the Bitumount site.
• 1948. Constructed for $725,000, plant goes on production. Operations end after Leduc discovery.

• Abasand:

• 1930. Max Ball and B.O. Jones of Denver organize Abasand, buying the Alberta Research Council's Fort McMurray plant.
• 1935. Company begins construction of a new plant, scheduled to go into operation by 1936. Forest fires and equipment supply delays hold up plant construction.
• 1941. Mining begins, and the plant processes 18,475 tonnes of oil sand to produce 17,000 barrels of oil. Fire destroys the plant, which is rebuilt.
• 1943. Federal government takes over plant as part of war effort.
• 1945. Fire destroys operation.

• 1950. Alberta government issues report on oil sands potential by S.M. Blair, who proposes that development could be economic for 20,000 barrel-per-day projects. He envisions such a plant costing $43 million and generating a 5 to 6 per cent annual return on investment.

• 1951. Alberta sponsors a conference on oil sands geology, mining, recovery, transportation and refining. Nathan Tanner, Alberta's Minister of Mines and Minerals, outlines provincial policy on oil sands leasing and royalties. A dozen companies take out 20,000-hectare exploration permits.

• 1959. Cities Service Athabasca constructs a 3,000 barrel per day plant at Mildred Lake. Plant extracts bitumen at a field facility, then upgrades at a pilot refinery.

• 1962. Great Canadian Oil Sands Limited receives approval for 30,000 barrel per day, $122 million plant. Financial difficulties ensue.

• 1964. Sun Oil Company takes over GCOS project, receiving approval to construct 45,000 barrel per day plant for $190 million.

• 1967. GCOS goes into production; final cost: $250 million.

Taking Centre Stage

This article appears in the June 2008 Issue of Oilweek magazine.

By Peter McKenzie-Brown

At 10 o’clock in the morning of February 13, 1947, a group of dignitaries welcomed in the Canadian oil industry’s modern era. On that day Imperial Oil brought in its Leduc #1 discovery with fanfare, but the event was primarily of local interest. Internationally, only the American oil press paid heed.

The event that brought Alberta’s potential to the attention of the world came a year later. The occasion was the storied blowout at Atlantic Leduc #3. Here is the tale of that extraordinary event as seen through the eyes of Hugh Leiper – the last surviving crewman on the well. Twenty years old and at the beginning of a long and successful career, Leiper was derrickman on the rig as the adventure started.

His father worked in the small refinery at Turner Valley, which hosted Canada’s first major oilfield, so Leiper had lived with the industry from childhood. When the Second World War ended, the Turner Valley field was essentially dead from overproduction. “It had been ruined during the war,” says Leiper. “Jobs in drilling were not plentiful, to say the least. There were two rigs working in Wainright, one or two in Taber, Cantex had two working for California Standard and that was about the extent of the drilling industry at that time. Imperial had a rig of its own, the one they used at Leduc.”

After a year at Calgary’s Mount Royal College, Leiper couldn’t afford to continue studying petroleum technology. He signed on as a roughneck with Cantex in 1946 and moved to a new contractor, General Petroleums, a year later. “We were pretty lucky. We lived in camps. We were getting six bucks a day, but they deducted $1.50 for room and board. The steam rigs we used were cheap to operate; all you needed was water and fuel. But they were hard to tear down and move, and by 1949 they were gone. The new power rigs were faster and more portable.”

As drilling contractor, General Petroleums had already drilled two good wells on a quarter section of John Rebus’s 320-acre farm. Rebus owned freehold oil and gas rights, and fabled Calgary oilman Frank McMahon had snapped up that quarter section for Atlantic Oil Company, which he had founded.

The first two wells – wells that would take 4-5 days to drill today – had each taken a month of drilling. Rather than tear down the steam-powered rig to get ready for #3, Leiper says, “We bolted two huge steel beams across the bottom frame of the substructure, then used hydraulic jacks to put the end of each beam on an athey wagon. Athey wagons were steel contraptions, each with a pair of caterpillar tracks, but with no power. Then we hooked on a cat and lugged the whole rig, completely intact, over to the new location. I’d say that rig weighed 50 ton.”

“We had an old blowout preventer but they were usually clogged with mud and crud,” he says. “We really just put them on for show, and sometimes didn’t put them on at all. They were a joke, but I’m getting ahead of myself.”

Drilling began, but “we pretty soon lost circulation in the well. We pumped down straw, wire mesh, golf balls, chicken feathers – I can still smell those chicken feathers -- and anything else we could to try to regain circulation. Nothing worked.”

One evening Leiper was in the cookhouse listening to an argument among the engineers. Some of them “wanted to drill dry – just pump clear water down past the drill bit. The cuttings would theoretically seal off the lost circulation zone.” After fierce arguments, the dry drillers won the day, and disaster loomed.

It was 3 am, March 8^th, 1948. Leiper continues, “A fellow named Cliff Covey and I were in the cellar under the rig thawing out a line that was frozen solid. Then suddenly the mud started flowing up. There was a blurp of mud over the drilling nipple, and I said to Covey ‘Let’s get the hell out of here.’ We ran west under the rig and a huge master bushing (a rotary table) weighing several hundred pounds went up through the rig and into the air and landed just 20 feet ahead of us.

“There it was. What an awesome sight, the roar of this thing. You couldn’t talk to each other because of the noise. The rig was winterized as they called it in those days – boarded in with tin. The well was blowing huge chunks of shale and they were penetrating that tin just like you’d taken an AK-47 and opened up on it.

“The driller was a guy named Bill Murray, a very capable driller. He dispatched a couple of people to run down as fast as they could to the boiler house and tell them to shut the fire off. Then he and I ran up to the derrick floor and we raised the string of drill pipe as high as we could, chained down the brake on the draw works, and got off the rig.

“The crown of the rig was more than 150 feet off the ground, and when daylight came we could see what we were dealing with. Oil was blowing over the crown. It seems like lunacy today, but we put up some windsocks. We wanted to know when it was safe to fire up the boilers to pump weighted mud into the well. We were wading in oil up to our bellybuttons, carrying these sacks for the drilling mud.”

“This went on for three days,” he says. Then, suddenly, “the flow subsided. It must have got plugged up a bit, naturally.” The crew got the primitive blowout preventer functioning, and things appeared to be looking up. “I’m running one of the steam pumps, and the mud gauge is going down. It looked like we were winning. Then someone came up to me and said ‘I just come by some seismic shot holes on the road and I saw oil and gas coming out of them.’ That’s when it started. That’s when she started cratering, and it gradually got worse and worse.”

“There was two to three feet of snow in the field, and we needed to get water to the rig, we had to get a line strung up to the well to continue killing it. We started setting up a line using five-inch drill pipe in 45-foot lengths, and we were using bull chains to cinch up these thick-walled pipes.”

“I saw Cliff Covey go walking by, and I wondered what he was doing, going back to the rig. Then I saw him waving his arms for us to come. Well, he was just off the farm, and he had gone into an outdoor privy, lit a cigarette and thrown the match down the hole and caught the toilet on fire. We didn’t have anything to fight fire with. We got some gunny sacks and some little hand fire extinguishers from the pumpers. The flames had gone from the toilet to the sump. We’d swat out a bit of fire here and it would jump over there. None of us should have even been in there. It was lunacy. But we were young and didn’t realize the consequences, and eventually we got it out. We always called him Shithouse Covey after that.

“We decided to do a huge cement job on that well. We got 10,000 sacks of cement, put it into the hopper and pumped it down the well. Didn’t fizz a bit on that hole, not one damned bit. It was an awesome sight. The derrick, the equipment, everything but the boilers was collapsing into the crater.”

Eventually, command of the control operation went to Imperial Oil, although Leiper worked at the site until the end, for General Petroleums. “We didn’t get any danger pay,” he recalls. “The Imperial Oil guys got danger pay – they were a mile and a half away at the river. We didn’t get any, and we were right at ground zero.”

Imperial decided to drill two relief wells, but “one of those holes was plagued with fishing jobs and every other problem you can imagine. Then, in early September, the well caught fire. But we had finished a new water line from the North Saskatchewan River to the operations area, and we pumped huge amounts of river water down the relief wells. Finally, I think it was on September 8^th, the well came under control. It just went quiet.”

It took six months, two relief wells and the injection of some 700,000 barrels of river water to bring Atlantic #3 under control. As part of the crude oil recovery effort, trucks sucked more than two million barrels of oil from ditches and gathering pools in the area. Oilman Frank McMahon quipped that the well was “producing through a 40-acre choke.”

The size of the blowout and the cleanup operation created a legend. The whole world knew from newsreels and photo features about it. The words “oil” and “Alberta” had become inseparable.

From a technical perspective, much good came from this disaster. Most importantly, the blowout led to new regulation. “I didn’t see any Oil and Gas Conservation Board (ERCB) people in the area when we were fighting that well,” says Leiper. But after the event the board held a public hearing, and later instituted two important regulations.

The first had to do with surface pipe. The well had been cemented to a shallow shale formation which didn’t have a chance of containing the monster reservoir pressures it encountered. Under the new regulations, drillers had to install adequate surface pipe, and it had to be cemented into a “geologically competent formation” – one that would hold in the event of a blowout.

The second had to do with blowout preventers. After Atlantic #3, BOPs had to be adequate, and there had to be two of them, so you had a backup. This was costly to the industry. “The substructure had to be a lot higher after that, so you could fit all this equipment in the cellar,” Leiper observes. “But this changed the whole complexion of the industry. After #3 there was public regulation of the drilling sector. Prior to that, you were on your own.”

The Great Pipeline Debate

This series of articles first appeared in the June, 2008 issue of Oilweek magazine. Pictured above, C.D. Howe.

By Peter McKenzie-Brown

The Minister of Everything
“If we have overstepped our powers, I make no apology for having done so,” said C.D. Howe to Parliament in 1953.

Howe was known for his gathering arrogance. The second most powerful politician in Canada, he ran much of the government and was dubbed “Minister of Everything” by supporters and opponents alike. A man of extraordinary ability and energy, he served in Parliament from 1935 until 1957. His downfall was a Parliamentary wrangle known to history as the Great Pipeline Debate, which took him and the government he served down to a surprise defeat. Howe’s performance effectively ended a quarter-century of Liberal rule in Ottawa.

Half a century later, it is difficult to imagine the emotions aroused by a pipeline construction proposal. At one time, though, Trans-Canada Pipelines was the focus of a divisive national debate.

After twice rejecting applications, Alberta had granted gas export permits in 1953. Pipelines were now essential to get that gas to market, but efforts to develop the Trans-Canada line to Central Canadian markets encountered a Pandora’s Box of problems. These began with the fact that the project was primarily financed by American interests – merchant bankers Lehman Brothers and a covey of oilmen, including the legendary Texan, Clint Murchison.

Despite the strength of its board, TCPL had difficulties from the beginning. There were several competing proposals to move gas east from Alberta; because of the uncertainty, Alberta producers would not sign supply contracts, and distributors would not sign purchase contracts. TCPL’s original route, which would have taken the project through US territory, faced the fierce opposition of Canadian nationalism. When Ottawa rerouted the line through the rugged Precambrian Shield, which covers most of Canada north and east of Winnipeg, private-sector financiers balked at the additional costs.

Other trouble came from across the border. An association of coal producers called the proposal “a brazen attempt to force the American people to subsidize a costly and unnecessary pipeline across Canada.” Even the Federal Power Commission, whose approval TCPL needed to sell gas into the United States, got into the fray. The American regulator was skeptical of the project's financing and unimpressed with Alberta’s reserves.

Nonplussed, Howe used his considerable political skills to drive the project forward. “This is no ordinary project, but the largest capacity and longest pipeline ever undertaken,” he said. “The project is comparable in importance to our transcontinental railroads. In my opinion, if the project is allowed to collapse, the use of western gas in eastern Canada will be a dead issue for all time.”

Howe virtually compelled TCPL and its competitors to merge and 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. During the Great Pipeline debate in 1956, Howe tried to force the legislation through Parliament by using closure at every stage. This tactic annoyed the opposition parties, who objected strenuously, delayed its passage, and turned the pipeline into a major political issue. The use of closure created a furore which spilled out of Parliament into the press, and led to the government's defeat at the polls the following year.

After his electoral defeat, Howe said simply, “We were too old. I was too old. I didn’t have the patience any more that it takes to deal with Parliament. You know, over a year ago I went to the Prime Minister (St. Laurent) and suggested that he and I ought to retire. He wouldn’t hear of it – I guess he’d decided to live forever, and everything was to go on as it was going. So he said nonsense, we must stay. So we did – and look what happened.” Clarence Decatur Howe died on New Year’s Eve, 1960, aged 75.

The Wildcatter
Himself the son of a prospector, Francis Murray Patrick McMahon (known as Frank to everyone but the baptising priest) became a hard-rock driller in the 1920s. The following decade he shifted to wildcatting – unsuccessfully in BC’s Flathead Valley, then in Alberta.

Pacific Petroleums is the oil company he is most closely associated with. It originated in 1930 through the merger of two tiny Turner Valley-based companies, one of which McMahon had founded. In the early days, McMahon’s involvement with the company was tenuous – he wasn’t on the board, and an economy drive during the Second World War relieved him of his job as operations manager. After the war he rose to the top, however, and imbued the company with vision and energy. So successful did the company become that in 1979 Petro-Canada acquired it as a fully integrated oil company for the then-record purchase price of $1.5 billion.

McMahon was successful in Alberta but – always the maverick – turned his attention to exploration in his native British Columbia just after the war. He coaxed the government to open up lands in the Peace River area for development. First in the queue, in August 1947, he acquired permits #1-3 for a consortium he had assembled, thus obtaining exploration rights on 750,000 acres. His 1951 discovery of the Fort St. John gas field rewarded this gamble and contributed to the next stage in his remarkable career.

Not until the 1950s did natural gas development become a major continental enterprise, and early in those years there was a great deal of competition to build the lines that would eventually create North America’s fundamental pipeline grid. Frank McMahon was a fierce competitor in both of Canada’s major controversies.

With an eye to creating a gas pipeline to BC’s lower mainland and the Pacific Northwest, he incorporated Westcoast Transmission in 1949. His original plan was to export Alberta gas along this line. He encountered delays getting export licenses, however, so he simplified matters by first negotiating with the government of British Columbia for permits to transport and export natural gas from the growing reserves being discovered in the Peace.

Westcoast won final approvals from British Columbia, federal regulators and America’s Federal Power Commission in 1955. Within two years, the company had constructed a $170-million, 680-mile pipeline from BC’s Peace River area. The line delivered gas to some cities in the BC interior and to the Lower Mainland, and exported gas to the Pacific Northwest. In October, 1957, an American reporter provided a vivid description of the opening ceremonies. “At the turn of a valve,” he wrote, “gas roared through the 30-inch pipe heading south for Vancouver, and a gas flame leaped symbolically skyward. Said McMahon, ‘So far, (natural gas) has all been going out (of the United States). Now it will start coming in.’”

The huge American market tantalized McMahon, and around the time of the Great Pipeline Debate he also put together one of the bids competing with Trans-Canada. Audacious to a fault, in March 1956 he walked into the Ottawa office of C.D. Howe and presented his alternative. He would construct a pipeline from Alberta to Montreal, following an all-Canadian route. It would be 70% Canadian owned, and it would require no financial assistance from government. Furthermore, he would “personally post with the government $500,000 performance cash to complete the project by 1958, subject only to being able to obtain necessary materials.” The key to this financial alchemy was a bigger line and larger exports to the US market.

Although in some respects the proposal seems clearly superior to the TCPL proposal, Howe wanted nothing to do with it. He wouldn’t even discuss it. McMahon let news of this rejection out, however. As the clamour of the Great Pipeline Debate grew, news about this proposal contributed greatly to the din, and to the defeat of the federal government.

Born in 1902, Frank McMahon died in 1986.

The High Priest
Eldon Tanner was a politician (16 years in Alberta’s legislature) of great skill, and a man of impeccable integrity. The Minister of Lands and Mines in 1947, he turned the valve to officially start oil flowing from Leduc. In 1952 he retired from politics, moving to Calgary to head a small company called Merrill Petroleums. Reflecting on his years in politics, he believed his political legacies were fiscal responsibility, efficient administration in government and the conservation of Alberta’s natural resources.

In those days, the meaning of “resource conservation” was quite different from our meaning today. It meant limiting gas exports to those in excess of the province’s 30-year needs. This calculation consumed the Oil and Gas Conservation Board and helped delay the selection of a line to eastern Canada and points south. In 1954, premier Manning resolved the stalemate by informing C.D. Howe that Alberta would only give permits to one company to export gas eastward.

At that time only two serious contenders were left at the bargaining table: US-owned Trans-Canada Pipelines and Western Pipe Lines. Western was a Canadian company with an economical and realistic plan. However, to be profitable it needed more foreign exports than TCPL – an insurmountable political handicap. In the end a shotgun wedding married the two, with Howe’s finger firmly on the trigger.

The merged company needed a president, and in 1954 Tanner was asked to serve. Initially, he refused because the company wanted to host its head office in Toronto. TCPL was undeterred. According to Tanner, “The next day I received a call from Premier Manning. He said, ‘Tanner, these people want you to do this job and I think it is your opportunity to be of great service to your country’....Well, I got a call the very next day from Mr. C.D. Howe, who was the Senior Minister of the Canadian Government, telling me he wanted me to take the job. He was very complimentary and said that I was the only man who could hold these two companies together. Flattery, you know, will get you anything. I did feel that when the two asked me to do it, I should accept.”

The company agreed to have its head office in Calgary, and Tanner brought political savvy, business acumen and interpersonal skills to the job. According to the leading historian of TCPL, however, he “probably did not play as important a role in Trans-Canada’s survival and ultimate success as half a dozen of the original sponsors on the board. Nor did his ability or style ever qualify him to be a member of the power elite of Canadian business and public life. But his quiet diplomacy was to be important both to the morale of the employees and for relations with a great range of persons outside the company.”

With their ascendancy to power after the Great Pipeline Debate, the Diefenbaker Conservatives appointed a federal commission to study Canadian energy export policy. Its report suggested that Tanner might have acted improperly by exercising stock options in a company that received federal financing. Embarrassed, he relinquished TCPL’s presidency in 1957 and chairmanship of its board the following year.

Public libraries file Nathan Eldon Tanner’s official biography among religious books, and the last word on the man needs to go to his religion. A devout Mormon, after Trans-Canada he dedicated his life (he died in 1982, age 84) to the church. Indeed, for his last two decades he was President of the Quorum of the Twelve Apostles – the highest religious role a Mormon can aspire to.

The Battery and the Charger

This article originated here.

B.C. and Alberta need each other’s power

By Martin Merritt
About 14 years ago, Alberta began to restructure its electrical system, and it’s been quite a journey to the market-based system we have today. Most people don’t understand what an important role British Columbia’s government-owned system plays in our market. From my perspective as head of the agency charged with making sure Alberta’s electricity markets are fair, efficient and competitive, I see our relationship with B.C. as mutually rewarding.

Alberta’s electricity market includes a host of buyers and sellers. At one end of the spectrum are small consumers like you and me who depend on electricity in our homes; on the other are huge industrial consumers mining the oil sands, operating pipelines and milling forest products.

On the supply side, generators range from wind farms east of Crowsnest Pass to huge coal-fired plants near Edmonton. The diversity of Alberta’s electricity supply has increased substantially. We now have more technology, fuels, locations, ownership, and maintenance diversity than in the past. Our system’s reliability, its cost structure and Alberta’s collective exposure to various risks are well-served by this diversity.

Less known is that Alberta and British Columbia are buyers and sellers of each other’s power. We Albertans buy from B.C. during our peak hours. B.C. buys from Alberta during the night. This arrangement confers tremendous benefits on both provinces.

There’s a misconception among some Albertans that the relationship between Alberta and B.C. is parasitic: we’re the host and they’re the parasite. According to this argument, our western neighbour is pulling a fast one by preying on a weakness in our market design.

The facts do not support those ideas. The power-exchanging relationship between the two provinces is symbiotic, and the symbiosis is based on geography. Alberta has lots of coal and natural gas, while B.C. has big mountains, long valleys and lots of rain. It makes perfect sense that B.C. based its system on hydroelectric power while we constructed one that primarily burns hydrocarbons. Because of these basic realities, over the years the two provinces have evolved a mutually beneficial relationship – somewhat like a battery and a charger.

The power we get from next door perfectly complements our own – and vice-versa. Alberta’s electrical demand varies substantially throughout the day and across the seasons. When we are fixing supper and using our home appliances our demand for power goes up, as it does during heat waves and cold snaps. It tapers off during spring and fall. Like other mechanical devices, generators fail unexpectedly from time to time. If they are wind-powered, their output is quite variable and difficult to predict.

Whether for reasons of temporary high demand, short supply or both, we’re fortunate to be able to buy electricity from our neighbour. Last year B.C. sent us as much as 465 megawatts for brief periods. What we have in B.C. is a standby generator that can provide us with significant amounts of reliable power on short notice.

Could Alberta make do without B.C.’s hydropower? Sure, by over-building generation capacity in the province. It’s worth noting that we don’t just buy power from B.C. because we can’t supply it ourselves. We buy it anytime that they are willing to supply it for less than it costs in Alberta. Every hour of the year Alberta generators have to compete with B.C. for the right to serve Albertans. If we had built a generator of our own just to supply the power that B.C.’s government-owned generators sent us in 2007, it would have run only 742 hours over the course of the year, or just 8 per cent of the time. This would make as much sense as buying an additional family car to avoid the odd cab fare.

Like cars, generators have costs that are largely fixed. Investing over $500 million plus ongoing maintenance in a generator that would run infrequently would be a very poor use of capital in any market. At the end of the day such power would cost far more than the power we buy from B.C.

Mutual self-interest has evolved a smarter way. We sell electricity to British Columbia at night when we have surplus capacity, so they can recharge their hydroelectric reservoirs. We buy electricity from B.C. at suppertime or on cold days or when a larger-than-normal number of our own generators are down for maintenance.

Our neighbour buys electricity from us when we least need it, and provides it to us when we need it most. This enables both provinces to make optimal use of their generating and storage capacity and use assets more efficiently. This keeps power prices lower in both provinces than they would otherwise be.

This arrangement has evolved naturally because of the physical differences between our electrical systems. It depends very little on differences in our market models. Yes, the market models are different. Alberta has developed a system in which markets determine prices and the pace of investment, while B.C. has a regulated, government-owned power system. British Columbians are justifiably proud of their hydroelectric system, although today’s B.C. taxpayers do not appear as keen to invest in publicly funded generation as their parents were. As a result, B.C. has become a net electricity importer. Many Albertans might be surprised to learn that in 2007 we sold much more electricity to B.C. than we bought from them, though overall Alberta too was a slight net importer in 2007.

Despite the vast differences in our market designs and because of large differences in the mix of our generation assets, the electricity systems of Alberta and British Columbia enjoy a unique symbiotic relationship. The big battery next door provides a market for our night-time surplus and a peaking supply for our crunch periods. Combine this with an investment climate that has attracted a steady stream of investor-funded generation projects for the past ten years, and you have a system that has provided reliable, sustainable power to the most robust economy in the country.

Alberta’s Market Surveillance Administrator, Martin Merritt is head of an independent agency developed to ensure that the province’s electric markets operate in a fair, efficient and competitive fashion. The MSA also monitors the retail natural gas market.

Leading the Charge

This article originally appeared in Oilweek; photo from The Calgary Herald

In a career that has yet to span two decades, Tristone Capital founder George Gosbee is a shining activist for better business and better politics

By Peter McKenzie-Brown

George Gosbee is an unusual mix of builder, campaigner and populist, and from any of these perspectives he seems to be on the leading edge.

Tristone Capital Inc. is his foundation, and it is probably corporate Alberta’s greatest recent success story. Despite his high-profile participation on provincial boards, he has been a leader in the industry campaign against the Alberta’s recent royalty regime change. And as an observor of social change, he has recognized the growing strength of political populism and has set up a firm that he believes will become a leader in the field.

Builder: When Gosbee enters the room, he brings a lightning-sharp mind and a strong command of numbers and issues. He also brings an engaging personality and takes control of the interview – in an unassuming way, of course. It’s a pleasure to do business with him, and that is certainly one of the factors behind his remarkable success.

At 38, his credentials are a running commentary on what his kind of energy can create during quite a short career. He is the founder, chairman, president and CEO of Tristone Capital, the largest oil and gas property acquisition and divestiture business in the world. When he sold Tristone in 2003, the Globe and Mail called it the “deal of the year” because of the high sale price: $101 million in cash and stock. Eighteen months later, he bought back the enlarged company for an undisclosed sum.

A 1992 graduate of the University of Calgary, Gosbee began his career with merchant bank Peters and Co., where he was appointed managing director in his mid-twenties. He moved to Newcrest Capital for a couple of years, and then began to create Tristone.

“I founded Tristone in 2000 because I saw the opportunity for a better type of banking firm,” he recalls. “I recognized that there was a lack of confidence among oil companies dealing with bankers that were not global or technical. I formed Tristone with the mandate of being a technical global banking firm, which was rare.” The company has three components (the “tri” in its name): property acquisitions and divestitures, investment banking and capital markets. “We were the first firm to combine oil and gas property acquisitions and divestitures with investment banking.”

“It’s a client-driven strategy”, Gosbee says. “Our clients wanted bankers who knew what was going on under the ground and around the world.” And that’s what Tristone quickly came to provide. Now the world’s largest independent energy advisory firm, Tristone has more than 150 employees, of whom more than 40 are engineers, geologists and geophysicists. It has offices in London, Calgary, Houston, Denver and Buenes Aires. Tristone has seats on three major stock exchanges, does research on 72 petroleum-producing basins, and has 20 datarooms to facilitate property sales. “In any one week, we have $1-2 billion worth of properties for sale.”

Tristone’s spectacular successes reflect Gosbee’s exploitation of an important trend in the petroleum industry – one that became increasingly clear in the 1990s. Briefly, acquisitions have become a critical form of reserves replacement. The industry can’t replace reserves by the drill bit anymore, so the number of transactions in the sector has become easily the largest on the planet. “Pharmaceutical companies don’t have to acquire the assets of other companies to stay in business,” Gosbee says, “and neither do other kinds of companies. Oil companies are the exception. They have to.”

Campaigner: After the change of premiership in Alberta at the end of 2006, the new government under Ed Stelmach offered him two important appointments – both of which he accepted. He was asked to sit as a board member on Alberta’s Economic Development Authority. Created by former premier Ralph Klein, the authority describes itself as “a partnership that provides businesses with a direct working link to the Alberta Government. A network of business and industry sectors made up of private sector volunteers work with government to attract investment, promote the Alberta Advantage and help generate more wealth and employment for Alberta.”

More importantly, premier Stelmach also invited Gosbee to serve as vice chairman of the Alberta Investment Management Corporation. (Toronto-based TD Bank’s Charles Baillie is chairman.) A Crown corporation with more than $70 billion of Alberta’s assets under management, the newly formed entity is one of the largest public sector asset managers in Canada. “This is rather exciting,” Gosbee says with characteristic understatement. “Not a lot of people get to have the experience of helping create a Crown corporation.”

Notwithstanding the government’s evident confidence in him, when Alberta’s Royalty Review Panel released its report last September, Gosbee helped lead the charge against it. This was his latest campaign, and the one with the highest profile.

“I wrote a letter to the citizens of Alberta and put it in 17 newspapers around the province,” he says. “There is an opportunity for increased royalties, but the math is wrong. We can’t make this kind of decision on faulty math.”

He adds, “I dumped on the panel’s report and I dumped on the process and I dumped on the result. It seems as though the people of Alberta are now taking the oil and gas industry for granted. I think we’re in a dangerous situation.” Strong words, but he backed them up at a news conference (more than 25 reporters were present) at which he provided Tristone’s thinking about why the formulas are wrong.

“Yes,” he says, “I was upset with the outcome, but that doesn’t mean I’m not going to continue working with (the government) and the premier in trying to come up with solutions to the unintended consequences of what they have done. I think the government respects my comments because we can back them up with our team’s research.” In Gosbee’s view, the most important failing of the Royalty Review Panel was its impact on natural gas, which he calls the province’s economic driver. “If you mess with the economic driver of this province, then we’ve got a mess on our hands. The general public didn’t know about it. Even the premier didn’t understand it.”

Now he rolls out the statistics. “About 64 percent of Alberta’s royalties come from natural gas, and five percent of the gas wells – the deeper wells – account for 64 percent of the gas royalties paid. Now we have a problem on our hands. The (deeper) gas wells are marginally economic at today’s gas prices, and those recommendations (scheduled to come into effect at the beginning of 2009) are going to make them uneconomic.” In a research paper, Tristone points out that a tiny two percent of the province’s oil and gas wells account for 40 percent of provincial royalties.

When Gosbee began his campaign against the fiscal changes, many newspapers put it down to self-interest. The irony is that the opposite is true; the new regime offered a lot of near-term opportunity for Tristone. “M&A (merger and acquisition activity) is going to be great this year. If the government hadn’t done anything, it would have been status quo for us, but we will actually benefit from increased numbers of transactions. October 25th (the day the Alberta government acceded to the panel’s recommendations) was a record trading day for Canadian oil and gas equities, with Canadian equities falling off 30 percent compared to the American companies. There is a global bull market in energy, and institutional investors didn’t want to be out of it. They just wanted to be out of Canadian energy stocks. And that’s mostly because of government decisions.”

Populist: In university, Gosbee says, “(I realized) that I didn't want to sit back and wait for opportunities. I wanted to create them.” It shows.

An avid skier, runner, rock climber and golfer, Gosbee owns (with Precision Drilling’s Hank Swartout) a heli-skiing company in the Rockies. With his wife, Karen, he founded an athletic wear company called Cura.

He also co-founded a company with a subtle but more vital purpose. Mass LBP (“led by people”) is a new public policy company, based in Toronto. “Governments aren’t like they used to be 20 or more years ago,” he says. “Governments now rely more on popular opinion. We have a different type of politician now, people who rely on popular opinion, and it’s the process of how to consult that is the problem. So I got together with some leading academics in Toronto to discuss how governments are going to make decisions and come up with a better way to make these decisions, taking into account public perception and what’s best for the public.”

The result was Mass LBP which, according to its online prospectus, “is reinventing public consultation.” Advertising the importance of “a seat at the table, a hand at the wheel and a turn at the mic(rophone),” the company claims to help governments, corporations and not-for-profits make decisions and set priorities that enjoy public understanding and popular support.

“I’m pretty passionate about that, too,” says Gosbee, adding that populism is on the rise across the continent. “We had a situation in Alberta where the politicians and the population and the industry all wanted to change the oil sands (regime). How did we screw it up so badly? Why did we go after (the driver of) our provincial economy, which is natural gas? There needs to be change. As Canadians we need to find new and better decision-making.”

Asked about his philanthropic interests, Gosbee says only that he and spouse Karen donate mostly to the organizations they are involved with. However, he stresses the importance of giving back to the community. Chairman of the board for the Alberta College of Art and Design, he also sits on the boards of the Libin Cardiovascular Institute of Alberta and Calgary’s private Edge School, which now has a $49 million school under construction.

The Edge School, which trains student-athletes in both sports and academics, seems particularly close to his heart – perhaps because of his love of sports. “I’m a big believer that life is a partnership. Team sports like those at Edge school give you (a sense of partnership). So if you can grow up in that environment you’re better prepared for the future.” The oldest of his children, John (age 13), is already studying at the Edge. The others – Carter (10) and Isla (6) – will attend when they reach sixth grade.

Gosbee’s on a roll now. “You’re a partner with your spouse, with your kids. You’re a partner with your community, with your business.” He stresses that 80 percent of Tristone’s employees are shareholders in the company, which is held privately; only employees can own company stock. There are perhaps 25 “senior partners” at Tristone, he says, “but we consider all our shareholders to be partners.” Yes, he’s a populist in business, too.

History of the Petroleum Industry in Canada

This history is about the early development of Canada's conventional petroleum resources and pipelines. I prepared it as part of a series for Wikipedia, and will post part two tomorrow.

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 tsported 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 & 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, Norma