China: Panda or Dragon?

This article appears in the August 2008 issue of Oilweek.

By Peter McKenzie-Brown

A symbol of unrivalled wisdom and power, China’s dragon is a long, scaly, snake-like creature with the paws of a tiger and the claws of an eagle. This chimera is an emblem of ancient imperial power. Indeed, the dynastic emperors were known as dragons.

The revolutions of the twentieth century made a break with the past, and the present regime does not think the dragon is a proper symbol of China. Instead, the country’s rulers prefer to use the giant panda – that loveable, bamboo-eating member of the bear family – as the national emblem. By tradition a rare and noble creature, the panda has been part of diplomacy since 685 CE, when an emperor of the Tang dynasty sent a pair to his counterpart in Japan.

As the world sets its eyes on Beijing, where the Olympics will showcase progress since the death of Mao Zedong two decades ago, this commentary asks a simple question. Is the panda in charge of Chinese energy strategy, or is it the dragon? From the security of its bamboo forest, the gentle panda would stress comparative advantage. The dragon would rely on cunning, speed and power.

The charts below show growth in China’s oil consumption (top) and the country's oil production - both since the death of Chairman Mao

Until 15 years ago, China exported oil to neighbouring countries. Today, it has an almost insatiable appetite for the stuff. Since the Great Helmsman’s death in 1976, the People’s Republic has become the world’s second largest oil consumer (behind the U.S.) During those years Chinese consumption has quadrupled to about 7.7 million barrels per day while production – about 3.7 million barrels per day – has barely doubled.

The International Energy Agency thinks China will burn 16.5 million barrels per day by 2030, after buying 13.1million barrels abroad. Think about it: Saudi Arabia’s total output is now less than 11 million barrels per day.

Thrift: This article suggests that such parabolic growth requires the skills of the dragon to survive. In that spirit, China is now applying its extraordinary energy in four ways to meet its petroleum and other resource needs. The first is domestic resource development. Diplomatic manoeuvres on behalf of its petroleum industry are the second. The third involves partnerships with Western companies. Last is what the mandarins call “thrift.”

Based on efficiency, conservation and innovation, thrift is sometimes called the fifth form of energy.

China’s rise is making the world a more energy-efficient place. The country’s energy intensity – the amount of energy it uses per unit of GDP – has dropped by about 75% in the last 20 years, largely because of more efficient industry. Its energy intensity higher than America’s but lower than Canada’s, in 2006 China adopted the slogan “Save energy, cut emissions” as part of a drive to cut energy intensity even further. The country is thus improving its energy efficiency while increasing its energy-intensive role as workshop of the world. So don’t blame the Chinese for the world’s energy woes. They are doing an effective job of managing energy.

A latecomer to the world’s petroleum stage, China is now simultaneously the world’s second-largest oil consumer, the third-largest net importer, and the fifth-largest producer. In the last 15 years the dragon has been sending its agents into the world to secure the new energy supplies it desperately needs. Compared to the West’s international producers, China’s national oil companies arrived late to the petroleum Olympics, and they are not large contenders. The prizes left in play are expensive, and often in countries where Western companies refuse to operate because of human rights issues and geopolitical risk.

Through petroleum-related state-owned enterprises (SOEs) – China National Petroleum Corporation (CNPC), China National Offshore Oil Corporation (CNOOC) and China Petroleum and Chemical Corporation (Sinopec) – China started investing outside the country in 1993, just as the country became a net oil importer. China’s first petroleum acquisition was in Thailand, but CNPC acquired exploration acreage in Canada and Peru the same year. The amount of equity oil generated by those projects was relatively insignificant, and this remained the case for several years.

In terms of Canada’s ties with China, 1997 was an important year. As the British were preparing to return Hong Kong to China, Sir Li Ka-shing, the colony’s richest man and chairman of the Hutchison Whampoa conglomerate, became the owner of Husky Energy. Husky’s headquarters continued to be in Calgary, and the acquisition did not affect the company in the short term. However, Husky has since expanded its assets offshore China, and is now the largest foreign owner of exploration blocks there. All its holdings there are in the South China Sea.

Since 2001 Husky has signed eleven production sharing contracts in collaboration with the China National Offshore Oil Company (CNOOC) – now publically listed, but 70% owned by the government of China. Husky can participate in these projects up to 51%, and the company describes its entry into China as part of a strategy to develop conventional oil and gas outside North America. Certainly the company is also part of Chinese strategy, also. It is one source of capital for mandarins focused on securing energy supplies by developing the Middle Kingdom’s domestic resources.

The Venezuela Card: China cannot secure Canadian oil supplies as long as the only export pipelines from Alberta lead into the United States. Especially after the two countries announced in 2005 an agreement on energy cooperation, it was therefore astonishing when CNPC announced last year that it had pulled out of an agreement to take a 50% stake in the proposed Enbridge-operated Gateway Pipeline. When completed, the pipeline will transport 400,000 barrels of oil per day to Kitimat BC for overseas export. According to the terms of the original deal, CNPC would take 200,000 barrels per day of throughput, with the balance being exported to refiners in California. If the line had been expanded to 800,000 barrels per day capacity, CNPC could have acquired a larger stake.

For a country with rapidly rising oil demand, what’s not to like about this deal? When PetroChina vice president Song Yi-wu announced the dragon’s decision, he put it in the political context of a nation re-evaluating its commitment to Canada’s oilsands.

Projects take too long to get off the ground here, he said, and the political environment “frustrates” Chinese investors. Song said China would slow down its involvement in the Canadian oilsands business, give up its involvement in the Gateway pipeline project and wait for better investment policies and politically friendly opportunities in the future. Translation: Chinese policy-makers were frustrated over the unwillingness of Canadian producers to partner with CNPC in a production/refining venture that would see Canadian bitumen and heavy oil sent to Asia for processing.

Forecasting that CNPC couldn’t begin to produce bitumen from the oilsands for at least another decade, he made it clear that China’s near-term heavy oil strategies were pointed directly at Venezuela, where a “warm-hearted” President Hugo Chavez has taken steps to nationalize oil operations. Song said China is building energy security for its people in “politically friendly” countries, which include Venezuela, Saudi Arabia, Russia and a host of Asian and African nations – Burma, for example, and Sudan. Call it the Venezuela card.

The Venezuela card suggests a competitive advantage for China that Western countries often will not play. The dragon sees oil security as an urgent need, and is willing to exert whatever cunning, speed and power it must to meet its future needs. Not surprisingly, given its political structure and domestic situation, China will not let issues like liberal democracy and human rights stand in the way of its quest for energy.

Do Western oil companies let political and human rights niceties stand in the way of business? It’s a matter of degree, of course, but it is not difficult to find examples of North American and European companies pulling out because of political risk and public pressure based on human rights abuses. In Canada the most famous case is that of Talisman.

Ten years ago the company acquired a 25 percent interest in a developing oil project in Sudan. The production facilities, pipeline and offshore loading terminal were being built and the wells were being drilled. By the summer of 1999, oil was flowing and being exported. By 2002, the project was producing 240,000 barrels of oil a day, with the equity oil being distributed to the project’s participants, three of which were subsidiaries of state-owned oil companies from China, Malaysia, and Sudan. The only privately owned company in this consortium, Talisman bowed to public pressure based on Sudan’s human rights record and sold its 25% interest to an oil company owned by the government of India.

The pattern is clear. The Asian players were unconcerned about human rights. There is a subtext here about Asian strategies toward energy. Especially in the face of a high-profile divestment campaign like that launched against Talisman, Western companies will buckle in the face of pressure related to human rights, environmental integrity and so on. Chinese and other Asian companies will not. For example, all three of China’s oil and gas SOEs are active in Burma. Latecomers to the petroleum Olympics, they measure petroleum victory in terms of land, reserves and production.

Comparative Advantages: Chinese industry’s willingness to overlook “soft” issues like human rights gives it a distinct comparative advantage. China’s willingness to bring diplomacy to bear on behalf of its SOEs gives it another. These advantages are rebalancing the planet toward East Asia. The dragon is rising.

Chinese energy policy is directed by government, and some 70% of the world’s petroleum resources are now controlled by national oil companies like Saudi Aramco and Petróleos de Venezuela. State-to-state negotiations are especially important when one of the participants is an emerging superpower.

Much of China's efforts are directed to the energy-rich nations of Central Asia, which can deliver energy overland instead of by tanker. For example, a trans-Kazakhstan pipeline is already delivering oil from the Caspian Sea.

Two other factors in China’s favour deserve mention. One is that Southeast Asia is home to many in the Chinese Diaspora – the descendants of the many waves of migration from China over the last millennium. Particularly as colonialism collapsed after the Second World War, they came to control great assets and even some national economies. By some estimates the third largest economic entity in the world, the Overseas Chinese began repatriating capital to China in the 1990s, thereby igniting the Chinese miracle. Today they occupy key positions in Southeast Asian business and government, and strengthen local ties with China.

Another factor working for China began during Cultural Revolution – that decade of social, political, and economic madness from 1966 until the arrest of the Gang of Four. Despite mutual fascination and incomprehension, during those years black African governments and African revolutionary movements were the recipients of Chinese aid (both military and economic) and other diplomatic efforts. African governments – many of them successors to those revolutionary movements – remember China’s efforts during that time. That diplomacy is now paying off with preferential access to petroleum leases and production sharing contracts.

A classic example is Angola, in West Africa. Mainly because of the expansion of its oil industry that country has the fastest-growing economy in the world, and its growth is mainly driven by Chinese explorers and producers. China’s SOEs got access to Angola’s offshore as a ‘Thank you’ to the People’s Republic of China. Despite desperate poverty at home during the Cultural Revolution, the dragon still found the wherewithal to support Angola’s independence movements during those critical years.

China’s Peaceful Rise: A final point deserves comment. In the late 1990s, China’s central government developed what it called “the new security concept.” The idea is that the Cold War mentality of antagonistic blocks no longer makes sense. In a globalizing world, nations can increase their security through diplomatic and economic interaction. This notion has become part of a foreign policy doctrine known among diplomats as “China’s peaceful rise” – a policy that, for example, encourages Chinese businesses to form partnerships with Western firms. For Canada, which is one of the few countries likely to increase production in the coming decade, it has important implications.

Consider, for example, that Enbridge is undeterred by CNPC’s decision to pull out of the Gateway Pipeline. “The appeal (of this pipeline) to Canadian producers is that you would get another bid on the crude oil from somewhere other than the United States,” said Enbridge’s executive vice president, Steve Wuori. Also, of course, pipeline costs would be less.

“When (Enbridge) first started we were aiming (to complete the project in) 2011,” Wuori says. “But now we are targeting 2012-2014.” Will Canada be able to supply new markets with heavy? Wuori thinks so. “Production forecasts up to 2020 for the oil sands support that kind of growth potential, even if you risk it for economics and environmental concerns.”

Although China has placed less than 1% of the $50 billion investment in the oilsands since the early 1990s, it is still part of the equation. China’s most significant direct investment has been the SinoCanadian Petroleum joint venture, through which Sinopec owns a 40% stake in Synenco’s Northern Lights project. CNOOC made its presence known with the acquisition of a small interest in MEG Energy, which is focusing on a project at Christina Lake.

Obsessed with diversifying its oil sources and avoiding dependence on a single supplier, Beijing sees Canada as a country in the U.S. sphere of influence, a country where oil could be held hostage to political concerns. It has little enthusiasm for multibillion-dollar oil deals in a country whose relations with China have been soured by human-rights disputes. Think Tibet.

“China doesn’t want to make a multibillion-dollar commitment to a country where the political contacts are constrained,” says Jiang Wen-ran of the University of Alberta’s China Institute. Professor Jiang adds that the Middle Kingdom worries about Canada’s business practices. Canadians can’t explain how they will triple production from the oilsands given environmental constraints. The costs of environmental protection seem out of control. Labour costs are reaching the moon.

The Panda Speaks: This article has focused on the areas of Chinese petroleum development where Westerners are more likely to see a dragon than a panda. Of course, in modern China it is the giant panda that speaks for the neo-imperial court. To conclude, let’s listen to what this species has to say.

According to China’s State Council, a policy-making arm of the People’s Republic, “The basic themes of China’s energy strategy are giving priority to thrift, relying on domestic resources, encouraging diverse patterns of development, relying on science and technology, protecting the environments, and increasing international cooperation for mutual benefit.”

The panda adds that its energy development is based on “the principle of relying on domestic resources and the basic state policy of opening to the outside world.” In its efforts to ensure a stable supply of energy, the country wants “a steady increase in domestic energy production.” It also wants to “promote the common development of energy around the world.” China’s energy development “will bring more opportunities for other countries.” It will “expand the global market, and make positive contributions to the world’s energy security and stability.”

All this will help perfect the national system of “socialism with Chinese characteristics.”

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.

Q&A with Marcel Coutu

Syncrude's Chairman of the Board delves into operations, the environment and the demise of oil around the world. This article appears in the July 2008 issue of Oilsands Review.

By Peter McKenzie-Brown
Canadian Oil Sands Trust owns the biggest single share of Syncrude (37%), and the firm’s CEO is also Syncrude’s chairman. Oilsands Review asked Marcel Coutu about operating and environmental issues at the oil sands giant. His edited comments follow.

OSR: Developing new technology has been part of the business from the beginning. To what extent is that still the case?

MC: The first few years of this business were about survival, because oil prices were low and costs were high. When oil prices were low and margins were thin the driver for this business was always lowering costs. That really hasn’t changed much.

Both Syncrude and especially Suncor have been major developers of new technology. Suncor, for example, developed hydro transport – technology that enabled us to move oil sands ore by pipeline rather than truck. So all of a sudden we were operating satellite facilities, without having to truck ore to the processing site. That was a major innovation.

The tailings ponds are a major challenge area. It’s an important functioning part of our operations, and enables us to recycle our water. It’s a major challenge. We need to find ways to separate clay from the water more rapidly. This will help us reclaim land better.

OSR: Oilsands inflation has been high in recent years. How has that affected you?

MC: The one inflation component that has dwarfed all the others is the price of natural gas, which has moved up in parallel with the price of oil. We buy eight-tenths of an MCF of natural gas for every barrel of light sweet product we produce. The rest of our costs are increasing by low double-digit to high single-digit numbers, and over the years those costs add up. Fortunately, oil prices have more than offset operating-cost inflation.

OSR: How much energy do you consume for every barrel of oil you produce?

MC: About 1.5 gigajoules (1.5 MCF of natural gas equivalent) per barrel. That’s higher than 0.8 MCF, the number I mentioned earlier; that refers to purchased energy. The total energy we consume in our operations includes energy we generate as a by-product to our upgrading processes. It is largely electrical energy, in which we are more than self-sufficient.

We produce a lot of waste gas from our processes, and use that to fire gas turbines. We also have a lot of waste heat from our operations, and we raise steam with that heat and put that steam into steam turbines. This makes our operations more efficient.

Beyond that we arbitrage against the price of electrical power around the clock, sometimes selling electricity into the Alberta grid, sometimes buying it, depending on how those conditions align. We arbitrage those markets in both directions. We do the same with natural gas. It’s one of the businesses we do to make ourselves as energy efficient as possible.

OSR: How are you managing carbon dioxide emissions?

MC: We’ve been reducing them from the time we opened the plant gate. Carbon dioxide emissions are all about energy consumption – they are exactly the same thing; reciprocals, if you will. You only create CO2 emissions by burning fuels. We have always been incentivized to keep our energy consumption as low as we can, and lowering consumption means lowering CO2 emissions. We have always been focused on reducing CO2 emissions because they represent a direct cost to us.

OSR: You are a member of ICON, the Integrated CO2 Network. Any thoughts on carbon sequestration?

MC: The plants at Fort McMurray are the largest collectible source of CO2, but it is an expensive proposition. You have three levels of major expenditure there. You could sequester a lot of CO2, but I’ve seen numbers that you are actually generating more CO2 than you are sequestering by going through this process. First you have to construct equipment to extract the CO2, then build a pipeline, then pump the carbon dioxide into the saline aquifers, salt domes, old reservoirs or whatever you use to host the stuff.

OSR: The notion that crude oil supply is about to peak or has peaked is gaining a lot of currency. What do you think?

MC: Natural gas is in vast supply around the world but oil is not. Crude oil production in most of the producing countries in the world is in decline.

All OPEC can now do is raise prices by cutting production. They cannot lower prices by increasing production because they don’t have the capacity. We are in a very pure free market situation, with prices being set by supply and demand. When I look at that dynamic, I have stopped worrying about the demand side. No matter how much the US goes into recession, for any period that is important to any of us, any decline in consumption there will be offset by increased demand elsewhere – in China and India, but also in developing countries that produce their own crude oil. Those countries generally subsidize oil products, and subsidies accelerate demand growth.

At these prices you are seeing some conservation somewhere, but it is being more than offset by increased demand somewhere else. Whether people are still going to be buying at $200 a barrel I don't know, but by the time we get to $200 it will be the supply side that will keep things tight and moving upward.

OSR: How serious a problem is maintaining global production?

MC: Very. World oil production is generally in decline. You can assume that out of global production of 87 million a day, productivity will come off by 5-10 percent every year, so you have to replace that production each year before you can even begin to satisfy global demand growth. So what we are seeing is the demise of the commodity, since we are never really going to be able to meet the demand. Prices will be volatile, but the trend in my view is that prices will continue to climb. The demand will be fully there regardless of anything that happens to the US economy. The decline is real and cannot be arrested, at least not in the short term. One hundred and fifty dollar oil is within striking distance.

OSR: What is the role of the oil sands in this environment?

MC: Oil sands production is close to a million barrels a day, a little more than 1 per cent of global production. It’s going to take a huge amount of effort, capital and time, maybe ten years, to double Canadian oil sands production. It’s true that the Canadian resource is huge, but accessibility is long and slow. Our impact will be very slow.

One thing we need to bear in mind is that the size of our resource goes up with the price of oil; the higher world oil prices grow the greater our resources become. We have re-evaluated Syncrude’s leases, and that re-evaluation has taken us way up from 9 billion barrels, which was our traditional resource base. That’s good for Canada and Alberta and the rest of it.

OSR: How are you dealing with the labour shortages around Fort Mac Murray?

MC: To answer that, you have to think of labour as being in two buckets. The people in the operational bucket are there for the duration. They have great careers, pension plans and so on. Everyone puts their shoulder to the wheel, and we get the job done. We lose some people, but the situation is manageable.

Then there is the contract bucket – construction workers, pipefitters and so on, who are mostly there to work on expansions. They are there on a temporary basis and they are hard to hold onto. They are the challenging part of the work force. The labour problems we face are focused in that area.

OSR: Having waterfowl fly into the tailings pond brought international attention to Syncrude. Do you want to comment on it?

MC: We’ve extended apologies to everybody. It was really a heartbreaking incident for us. Why did it happen? Because we didn’t have our equipment deployed before the ice thawed. It’s something we have been managing for decades with success, but we got caught by the weather. We didn’t have our deterrents in place.

OSR: What are some of the other environmental issues you face?

MC: In general, our environmental story has been glowing. Where we have done a poor job has been in telling the world about it.

I’d like to comment in three areas – water, air and land. Let’s start with water. At Syncrude we consume two tenths of 1 percent of the water from the Athabasca River for our operations. We recycle as much as we can. If you extrapolate from that, the whole oil sands industry consumes less than 1% of the Athabasca’s flow.

Air is a more serious issue. We reduce our CO2 emissions because it makes economic sense, as I said earlier. But there are nastier things that we have been managing for years and they cost us a lot of money, and the nastiest of them all is sulphur dioxide. Our SO2 emissions peaked at 250 tonnes per day when we were producing around 250,000 barrels a day. In our last expansion we moved from 250,000 barrel per day to 350,000 barrels per day, and we invested about $1 billion in SO2 scrubbing equipment. We not only stopped the growth of SO2 emissions but reduced them slightly from our peak levels. Now we are spending another billion dollars to reduce those emissions to about 150 tonnes per day.

On the land side, in March we were the first company in the whole industry to get certification for land reclamation. We have returned that property to the province. It’s really impressive. You would never know there had been a mine there.

Losing The Arctic Edge

This article appears in the July 2008 issue of Oilweek.

Canada needs to move quickly to join international rivals exploiting the potential of the Arctic

By Peter McKenzie-Brown

Canada began to explore the far north for oil almost a century ago. In 1911 Jim Cornwall, a northern businessman, saw oil on the Mackenzie River and hired an Aboriginal named Karkesee to look for seepages. Karkesee found several. Later analysis showed the oil to be medium in gravity and low in sulphur.

Cornwall formed a syndicate with two Calgary businessmen and the group engaged T.O. Bosworth, a prominent petroleum geologist, to study the area. During his 1914 expedition, Bosworth staked three claims on behalf of his backers and reported enthusiastically on the area’s prospects. Ironically, given later events, Bosworth stressed that his supporters should take every effort to control pipeline transportation from the North to southern markets.

World War I put a halt to the group’s exploration plans, and by Armistice Day Imperial Oil owned Bosworth’s claims. The company began exploratory drilling along the Mackenzie in 1919, first drilling two salt water wells near Great Slave Lake. Farther down the Mackenzie, near Fort Norman, the third showed oil.

Led by Ted Link, who later became Imperial's chief geologist, the crew drilled the successful well with a cable tool rig. Legend has it that Link chose the site by waving his arm and saying, “Drill anywhere around here.” In August 1920, at a depth of about 1,240 metres, the world's most northerly oil well came in; Imperial put it on production the very same year.

Although just south of the Arctic Circle, the Norman Wells field established Canada as the world’s undisputed leader in northern exploration and production, and she retained that title for more than 60 years. Led by Dome Petroleum and a series of attractive federal grants, the industry’s golden age of Arctic exploration in the 1960s and 70s delivered huge natural gas discoveries and a number of small oil finds.

Let’s fast forward to the present. In petroleum terms Canada has become a second-tier Arctic nation. The US, Norway and Russia are all Arctic producers. In recent years, Denmark has done some drilling off the eastern shore of Greenland. Canada is clearly the laggard. Despite skyrocketing oil and gas prices and the many successes of Canada’s golden age, exploration in our Arctic is almost at a standstill.

As if to rub our collective nose in it, Enbridge Inc. and Gaz Metro recently announced that their proposed Rabaska liquid natural gas terminal in Québec had found a secure source of LNG. The source will be Russian energy giant Gazprom, which will deliver cargoes from an Arctic facility in the Barents Sea due to begin deliveries in 2014. By the terms of the agreement, Gazprom and Gaz de France will become equity partners with the two Canadian companies in the $840-million regasification plant.

The Great Abandon: In a sobering presentation to the Canadian Society of Petroleum Geologists, Dave Russum (VP of geosciences for AJM Petroleum Consultants) made a compelling case that Canada has fallen behind its rivals in the development of Arctic oil and gas, and that she needs to catch up. Only five countries have claims to mineral rights in the Arctic – the others are the United States, Russia, Norway and Denmark.

The United States became a major oil producer at Prudhoe Bay in 1977, and continues to produce from that supergiant field. Last year Norway began producing LNG from its Snøhvit field. Russia, which already has Arctic production in Siberia, will begin producing from Shtokman in the Barents Sea in 2014.

And Canada? This country’s most northerly oil production still comes from the 88-year-old Norman Wells field. A tiny amount of gas production serves a few small towns and villages in the Mackenzie Delta, but this service has as much to do with local development as petroleum economics. When energy prices crashed and Dome Petroleum collapsed in the mid-1980s, the industry decamped from Canada’s Arctic with great abandon.

Why? Several concerns have discouraged Arctic exploration for a generation. The main issue is geology. “In the Arctic most of the expected resources are gas,” says Russum, “and they are devilishly expensive to develop. Except for Prudhoe Bay, (the Arctic basins) have pretty much been gas plays, and we expect about 75% of the resource there to be gas. Oil has been the prize. If you couldn’t find oil, you didn’t want to develop there.” During the last two decades the expense and difficulty of Arctic development was worsened by surplus natural gas supplies in North America.

The situation has greatly changed in recent years, says the executive director of the Arctic Institute of North America. Benoît Beauchamp agrees that the Arctic is gas-prone, but says this is no longer an obstacle to development. In recent years natural gas has become recognized as a premium source of energy, although it generally serves continental rather than global markets.

This continental character raises the spectre of Canada’s tradition of bitter disputes over northern pipelines. It now appears that the joint federal and provincial panel evaluating the social and environmental impacts of the present Mackenzie Valley Pipeline proposal – this one put forward by Imperial Oil in 2004 – will delay the environmental decision on the $16.2-billion project by at least another year. This adds to a string of such problems that date back to the mid-1970s.

Like previous proposals, Imperial’s pipeline project has been dogged by setbacks. The company has yet to resolve Aboriginal land access issues or come to an agreement with Ottawa on how to finance the project. According to Beauchamp, construction of this pipeline is critical for renewed exploration in the North. “The announcement of the Mackenzie Valley Pipeline will be the gunshot that starts the race up there. Then there will be a bonanza.”

Beauchamp is more sanguine about Canada’s place in the North than Russum. “It’s true that there hasn’t been much drilling in the Arctic Islands since the 70s, but there is a great deal of interest now in the Mackenzie Delta – no drilling, but seismic and other preliminary work. A few years ago an ExxonMobil/Imperial partnership acquired a large land parcel in the shallow Beaufort, on an extension of the Delta. That’s likely an oil prospect, and three parcels adjacent to that property will be up for grabs in June. It will be extremely interesting to see how strong the interest is.” As it happened, BP acquired one of those properties for $1.2 billion. The other two went for a mere $10 million combined.

Beauchamp expects an Arctic boom. “Interest in the Arctic is mounting. There are very few places left in the world with the potential of the Arctic, and companies need to develop reserves in order to grow. Canada is likely to be a focus because we are a stable country. Corruption is not a problem here, unlike Russia. We aren’t likely to abrogate signed agreements, as the Russians did at Sakhalin Island, for example. The problems in Canada are mostly related to the approval process.

Canada Rules! Russum sees the issue as being somewhat more urgent. “For security, sovereignty and economic reasons, Canada should take an active role in Arctic development.”

That’s an opinion shared by Federal Natural Resources Minister, Gary Lunn, who met in May with leaders from the United States, Russia, Norway and Denmark to sort out how best to deal with conflicting sovereignty claims in the Arctic, including Canada’s.

“It is critically important that it’s under our sovereign control so that we set the parameters for the environment and that we make the decisions whether or not even to allow exploration,” Lund said on the eve of the meetings, which were held in Ilulissat, Greenland. “We are going up to reaffirm our commitment on defending and protecting our sovereignty in the Arctic.”

On an immediate front, Russum notes that depletion rates have been accelerating in all of Canada’s gas-producing regions. “In every area, particularly those in Alberta, we have seen declines. This is not particularly surprising, given the drop-off in drilling,” but it is an important reason to move back into the Arctic. “Estimates suggest that there might be 10 billion barrels of oil and 181 trillion cubic feet of gas in the Canadian Arctic. With high production rates depleting gas reserves across Canada, we need to be considering all opportunities.”

“Conventional and unconventional gas in southern Canada will not satisfy future North American needs,” he adds. “We have to recognize the need to develop a wide range of energy sources.” Energy is the vital commodity, he says; it equals power. In a rather unCanadian way, he argues that “countries with abundant energy (like Canada?) will control the world. Net consumer countries (like the United States?) will be at the mercy of world economics and politics.”

In the case of natural gas, the Arctic will soon become a particularly important source of supply. According to Russum, a quarter of the world’s undiscovered gas is likely to be there. Looking at the entire transpolar region, 26 geological basins make up the Arctic. Of those, 21 have had some exploration activity, and explorers have found oil or gas in ten. There is commercial production in four basins (two in Russia, one in Norway and Alaska’s North Slope). Two - Canada’s Cameron Island and the Mackenzie Delta – have been the source of minor production volumes. Given the small number of wells drilled and the Arctic’s challenges to development, these results are impressive.

Imagination Beckons: Given the prospects for huge Arctic gas discoveries and the controversy over gas pipelines to the large North American markets – in addition to the Mackenzie Valley line, there have been disputes for 30 years over a line from Prudhoe Bay through the Yukon into the Alberta network – Russum argues that Canada should consider LNG production from the Arctic. “Although there are big problems with sea ice in the winter, these are problems the Norwegians have solved” he says, “and which the Russians obviously believe are solvable. Certainly one ‘benefit’ of global warming is ice shrinkage, which means more open water in the Arctic and a more easily passable Northwest Passage.”

Another advantage of LNG is that producers have more market options – especially since “world demand is now driving gas movement.” This point harks back to the geographical maps that Dome Petroleum made famous in the early 1980s. As those maps pointed out, the Beaufort Sea is roughly in the geographic centre of the developed world. If sea ice were no problem, LNG tankers loading up in the Arctic would find themselves about equidistant from London, New York, San Francisco and Seoul. Destination decisions for cargoes from that region could be based purely on best price; the calculation of transportation costs would be largely redundant.

By contrast, traditional pipelines have a number of drawbacks quite apart from political wrangling. One of those is greater terrorist risk. Others include long timelines, the enormous capital required and the fixed destination. Pipelines from stranded resources don’t have much market flexibility.

Whether developed through traditional pipelines or LNG or both, Russum believes it needs to be done. “In the Canadian Arctic, the long-term costs of frontier gas production are going to be similar to the costs of producing unconventional gas – shale gas, coal bed methane – in large volumes. Imagination will be required for development, and we will need to apply out-of-the-box thinking to all aspects of E&P. If we do this, there is no reason our Arctic production can’t be economically viable in the global market place.”

The resources are there and the technology is available. The world’s hydrocarbon markets have never been stronger. According to Russum, “We used to be the leader in exploring the Arctic, along with the Americans. Now we have a real opportunity. We have to move beyond discussing development. We have to pursue it in an economic, environmentally sensitive and socially responsible manner.”

He pauses for effect. “We only have four competitors. Three of them have already proved that Arctic development is viable in this environment.”

Pushing South

Notes on geopolitics as Canadian crude pushes toward the Gulf Coast This article appears in the June 2008 issue of Oilsands Review.

By Peter McKenzie-Brown
“There certainly appear to be a lot of forces increasing the demand for Canadian heavy, particularly in the US,” says Steve Wuori. Enbridge’s executive vice president observes that right now only Venezuela and Mexico are seriously competing for the heavy oil market in the Gulf Coast, and “there are declines in Mexican supplies for geologic reasons, and Venezuelan declines for both economic and political reasons. So structurally it’s a very good time for Canadian heavy oil to secure that market."

Wuori’s comments reflect a sea change in Canada’s approach to selling the stuff. Early bitumen development in Alberta was slow and easy – regional producers supplying heavy oil to refineries in America’s northern tier states, with virtually no competition from overseas. Today, with surging supplies projected well into the future, Canadian producers, pipelines and marketers have had to become aggressive. Global forces are having a greater impact on the industry than ever before.

This is a good news/bad news story. The good news is that there are chinks in the armour of our offshore competitors – lots of them. The bad news is that the chinks in Canada’s armour are costing the country dear. Consider the following.

• Already the world leaders in bitumen production and an important producer of conventional heavy, Canadians have roughly doubled their non-upgraded bitumen production in less than four years.
  
• American decision-makers would be delighted to replace politically volatile Venezuelan supply with low-risk Canadian product, and Venezuela’s present leadership would be equally happy to develop markets elsewhere.
• Mexico’s supergiant Cantarell heavy oil field is in steep decline, but Canada has the productive potential to offset the shortfalls.
• The isolation of the Canadian prairies from the world’s sea lanes and from America’s major refining centres means bitumen producers can’t freely compete in world markets. Consequently, they get lower prices.
• As price-takers in North American markets, Canada’s producers have to settle for lower profits, and the province has to settle for diminished royalty revenue.

All these matters have geopolitical overtones. One way or another, each calls for the economic fix of more fully integrated global markets. This article focuses on the importance to Canadian producers of integration into world markets, and some of the ideas in play to achieve it. Let’s begin with Alberta’s relative isolation.

The Economic Burden of Under-Priced Oil:Western Canada’s heavy oil sells for less than the price it would fetch on the open seas. “Alberta is not an island,” observes FirstEnergy’s Steven Pachet, with a somewhat understated taste for the obvious. “If it were, world market prices for heavy oil would be easier to obtain. Alberta is landlocked, and pipeline capacity to other markets is sometimes restricted. Mountains to the west make pipeline transportation to the Pacific difficult, while the bulk of North America stands between Alberta and the Atlantic and Gulf Coasts.”

While heavy oil and bitumen sell at a discount to light crude both in Alberta and around the world, sometimes the Alberta discount increases when heavy crude from Alberta cannot reach markets. Known as the heavy oil differential, it represents the difference between the prices of Alberta’s Lloyd blend heavy oil and Mexico’s Maya crude, adjusted for transportation costs.

Lack of transportation is the main reason for the differential. The refineries that are accessible to Alberta heavy crude and bitumen can only handle so much supply. Alberta producers have limited access to US markets because of pipeline constraints, and the refining and upgrading systems in Western Canada are not nearly large enough to handle all the new production. As available supplies rise, refiners lower the price they will pay for Alberta’s heavy and oil sands-based crude until it is below world prices: the greater the competition to sell that oil, the lower the market price and the greater the differential.

This market behaviour costs Alberta, big-time. To help put it in perspective, during the final quarter of last year the differential averaged US$17.94 per barrel – the largest discount ever for Canadian heavy.

Such discounts are an economic burden on both producers and government. By Paget’s calculations, in 2008 bitumen producers will forego $1.88 billion because of the differential. This estimate uses very specific assumptions about how oil prices will behave this year.

When he presents an estimate for the cost of the discount to the provincial government, however, Paget uses a range of assumptions for its impact on royalties. In his view, the discount could cost Alberta some $200-$500 million in foregone royalty income. Also, of course, foregone revenues mean foregone taxes at every level of government.

The size of the prize can be measured in billions, but the penalty for inaction could be greater still: growing surpluses leading to greater discounts and diminishing development. The simple logic of this situation is clear. The large sums in play mean a lot of incentive for change, and a lot of change is on the way.

According to Paget, “Oil sands producers have a choice. Upgrade the bitumen into synthetic crude for higher unit revenue, or sell the bitumen and let others invest the capital to refine it into lighter crude and petroleum products.” This fundamental choice can be resolved with three kinds of development: New and expanded upgrading systems; expanded pipelines for existing markets; the creation of new markets. All are under consideration, and all are needed to meet the growing heavy flow from Alberta.

Getting to the Gulf: Here is the problem in a nutshell. Access to the world gives you the best available prices for your heavy oil. Access to a crowded regional market gives you Western Canada’s heavy oil discount. That is why the marketing Shangri-la for the heavy oil sector is the Gulf of Mexico, and why it’s important at this point to discuss the labyrinthine world of pipelines.

Cushing, Oklahoma, is now the southernmost delivery point for Canadian oil, and the closest delivery point to the vast coastal refinery complexes in Texas (4 million barrels throughput per day) and Louisiana (3.3 million barrels per day). Cushing itself has more than half a million barrels per day of refining capacity, so you can see the importance of delivering oil to these key markets. However, Enbridge’s pipeline to land-locked Cushing now supplies only 120,000 barrels of oil per day – soon to be increased by more than half. Shipping capacity from Canada to Cushing will increase by another 155,000 barrels per day with the completion two years from now of TransCanada’s Keystone Oil Pipeline extension.

Steve Paget explains the inexorable implications of these expansions. “By late 2010, total Canadian shipping capacity to Cushing will increase to 345,000 barrels per day. This is 65 per cent of Oklahoma’s total refining capacity. Canadian producers will need access to new markets to avoid swamping Oklahoma refineries.” After all, swamped refineries mean lower oil prices because of greater competition.

At the moment, Canada has no direct access to the Gulf, although small amounts – in the order of 15,000 barrels per day – are transhipped there from Cushing. Both Enbridge and TransCanada are proposing further pipeline extensions to the Gulf Coast to avoid Canadian crude being stuck in Oklahoma. The American Gulf Coast has refining capacity for bitumen, and it also needs new sources of heavy crude.

Of course, heavy oil developments in Canada are creating the need for much greater pipeline access to the coast than the volumes Enbridge and TCPL will be providing to (and south from) Cushing. At this writing there are four other proposals to increase pipeline capacity to the Gulf.

• Enbridge’s Access Pipeline would expand existing pipe and extend the system from central Illinois to the Gulf. This would provide 445,000 barrels per day of capacity. ExxonMobil is a 50 per cent joint venture owner of the proposed pipeline and owns useful rights-of-way.
• TransCanada is also considering several possibilities – notably (with Conoco Phillips) the Keystone project, which will convert a segment of TCPL’s natural gas mainline for oil transportation.
• Another possible entrant is the Chinook system – a 300,000 barrel-per-day proposal by two American firms, which would use existing rights-of-way to ship.
• The Altex Pipeline – proposed by a private company – would use new technologies to ship 425,000 barrels of bitumen per day south.

Ironically, increased oil sands production in Alberta has greatly increased the province’s need to import condensate – the mix of light hydrocarbons used to dilute bitumen to enable it to flow through pipelines. That need, in turn, is leading to the construction of yet another pipeline. According to Steve Paget, “diluent (condensate) is being shipped into the province by railcar these days. There’s plenty of diluent in North America, but how much do we want to move in by train? It’s like the old Rockefeller days. The problem is getting it here at a reasonable price, and that problem is being resolved by construction of the Southern Light pipeline, which will move diluent from Chicago to Edmonton.”

As Canada develops greater access to Gulf Coast markets, Canada’s heavy oil differential should disappear. The reason is simple. Unfettered free-market oil prices reflect just two factors: transportation costs and crude oil quality. Canada’s competitors into the Gulf Coast region – notably Mexico and Venezuela – have the option to cheaply take their production by tanker, anywhere in the world, to the highest bidder. This means their prices are driven by competition for the world’s highest prices. By contrast, Western Canadian producers are competing in a small and crowded marketplace.

The Competition: Markets always face complicating factors, and the situation along the Gulf Coast is no different. As Steve Wuori points out, “The issues are increasing Canadian supply and possible political issues between Venezuela and the United States. Venezuela has gravitated toward China and possibly other customers. This has made it more feasible for Canadian oil to replace Venezuelan production in Chicago and south.” Because of political turmoil, employees at Petróleos de Venezuela struck some years ago, cutting deeply into production a few years ago. Also, of course, the country’s disputes with ExxonMobil and other multinational companies have made international headlines.

Closer to home, the vast Cantarell heavy oil field, which provides about half of Mexico’s oil production, is in rapid decline. According to the director-general of national oil company PEMEX, production from the offshore field declined by more than 13 per cent in 2006 alone. Cantarell’s production peaked at 2.1 million barrels per day barely four years ago, but is forecast to average only a million barrels per day by the end of this year.

According to FirstEnergy’s Steven Paget, “There’s a possibility of Mexico becoming a net oil importer if the decline at Pemex is not turned around, so it is for several reasons not wise to depend on those two countries for oil.” Enter Canada – a secure and reliable supplier with vast and growing supplies of heavy oil and eager to displace imports from Latin America to the Gulf Coast.

The geopolitical considerations do not end there, however. Venezuela’s Hugo Chavez is increasingly unpopular at home, the country’s economy is in disarray, its heavy oil resources rival Canada’s, its labour costs are low and its transportation costs to the US Gulf Coast are a fraction of Western Canada’s. It is possible to imagine a post-Chavez Venezuela developing those resources and becoming a resurgent competitor.

Don’t put all your eggs in one basket: such is the weakness in the Canadian strategy of focusing on markets in Texas and Louisiana. From the Gulf, Canada’s heavy oil producers would have tanker access to the whole world, but not before paying huge pipeline costs from Alberta. To help forestall such an eventuality, Enbridge has proposed a project named Gateway.

A Nearby, Open-water Port: "Usually to create a market you need producer push and refiner pull,” says Steven Paget. “We are definitely seeing (both) for Gulf coast markets,” but right now the producer push to reach Asian markets is pretty slim. However, Enbridge is planning just such a line.

Gateway is “a heavy oil pipeline from Edmonton to Kitimat (British Columbia) to carry oil to a different market than the southern US,” Steve Wuori explains. “It would carry oil to California and to Southeast Asia, by ship. The appeal to Canadian producers is that you would get another bid on the crude oil from somewhere other than the United States.” Also, of course, pipeline costs would be less.

“When (Enbridge) first started we were aiming for 2011,” Wuori says. “But now we are targeting 2012-2014” to get this line into production. Will Canada be able to supply all these markets with heavy? Wuori thinks so. “The production forecasts up to 2020 for the oil sands support that kind of growth potential, even if you risk it for economics and environmental concerns.” Indeed, Enbridge is even looking for ways to take Canadian heavy to refineries in Ohio and Kentucky “and even beyond that to the east coast of the US – to ensure that there is market for Canadian production.”

Canada’s bitumen production is the ultimate example of the blackening of the barrel in the petroleum world. For more than two decades there has been a shift in global production from light, sweet, high-quality oils to heavy, sour, poor-quality crude. This “blackening of the barrel” has been problematic for many refiners, since black barrels bring with them environmental drawbacks, require capital-intensive equipment, and refine into lower-value barrels of fuel and other products.

Most refiners prefer higher-quality oils, and producers prefer to sell those oils because they fetch a better price. So does the government of Alberta, because it wants to realize as much of the economic benefit from the oil sands as possible. What’s a province to do? FirstEnergy’s Paget has an idea that deserves sharing.

Upgrader Option: As resource owner, the government of Alberta receives its royalty share from bitumen and heavy oil production in kind – that is, it receives oil, which it then needs to turn around and sell. Most producers that upgrade their oil sands in Alberta into lighter crude or petroleum products pay royalties based on the bitumen price.

Therefore, any discount for Alberta oil sands bitumen results in decreased royalties and decreased Government of Alberta revenue, whether the crude is upgraded in Alberta or elsewhere. “Assume that bitumen royalties are 10 per cent” this year, says Paget, and that the oil sands produce 1.3 million barrels per day.” This would mean the province receives 130,000 barrels of bitumen each day in royalties – a volume forecast to grow into the foreseeable future.

“Why wouldn’t Alberta guarantee that amount as feedstock for a private-sector upgrader?” Paget asks. “If the government believes in upgrading in Alberta, then taking the oil which it in fact owns and dedicating it to Alberta upgrading is a good way to do it. It’s a good way to make policy without investing much money directly. A hundred and thirty thousand royalty barrels per day is easily enough to support one or two stand-alone upgraders.”

Paget weighs the possibilities. “The government of Alberta is faced with a dilemma. Investment is lost (whenever raw) bitumen is exported. How much investment might be lost if bitumen exports from the province increase by 500,000 barrels per day? With current pipeline constraints and artificially high differentials, royalty revenue is already being lost.”

The new pipelines under construction don’t present an obstacle to this proposal, since most of the oil pipelines from the province can ship both bitumen and other crudes, including synthetic oil. Indeed, this idea seems to be one that will benefit the province in many ways. Provincial royalties would increase, and so would producer profits.

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.

Gas Goes Global