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.

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.

Damage Control

Gasoline and other fuel prices are subsidized in the three representative oil-producing countries graphed on the top right - to the point that gasoline costs $0.12 per gallon in Caracas.

Compare the growth in oil consumption in those countries to growth for the world as a whole. Did you notice a pattern?

By Peter McKenzie-Brown

The world has two kinds of energy-consuming jurisdictions: Those which respond to high oil prices, and those which don’t. In this post, I want to help define which is which. I also want to offer a few explanations why dramatic increases in energy prices have not yet damaged the world economy. These are intimately related issues.

I recently had an interview with Marcel Coutu, the chair of Syncrude – the world’s largest oil sands plant. Syncrude has been in operation for 30 years, and it has gone through a great deal of debottlenecking and expansion. It now produces 350,000 barrels of light, synthetic oil per day.

I asked Marcel for his thoughts on peak oil, and he gave me a few comments that summarize things precisely.

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.

He didn’t seem to think this was a major global problem, and I wish I had asked why not.

Three Theories: Historically, rapid increases in oil prices have led to global recession. This certainly applies to the stagflation that influenced the decade after the energy crisis of 1973. The terrible recession of 1982 was without doubt related to the energy crisis of 1979-80. And the long, gradual boom that began in ’83 was closely tied to declining oil prices, and accelerated by their collapse in 1986.

What I think we need to ask ourselves is why high oil prices don’t seem to be doing a lot of damage to the global economy. According to The Economist, there are three possible explanations.

An important and interesting idea is that high oil prices are not hurting the economy simply because they themselves are the result of rapid economic growth around the world. “Rather than oil harming the global economy, it is global expansion that is driving up the price of oil” says the world's great champion of liberalism.

Another explanation is that developed economies are more efficient in their use of energy, thanks partly to the increased importance of service industries and the diminished role of manufacturing. For example, the EIA has calculated that the energy intensity of America's GDP fell by 42% between 1980 and 2007.

A third notion is that the oil price rise has been steady, not sudden. This has given the economy time to adjust. The Economist writes, “Giovanni Serio of Goldman Sachs points out that in 1973 there was a severe supply shock because of the oil embargo, when the world had to cope with 10-15% less crude almost overnight. Not this time.” It’s worth adding that during 1979-80, the percentage increases in oil prices were not as great as they were in the early 1970s, but in absolute terms those increases were greater by far.

The Role of Emerging Economies: As Marcel Coutu explained at the beginning of this article, the most important factor for higher prices has been the shift toward greater consumption by developing economies.

The US, for example, has responded to high prices by cutting consumption slightly. According to one source, the decline will be 1.1% this year, such that American consumption next year will be no higher than it was in 2004. Given such a niggardly response, growing demand from China and other emerging markets will be more than enough to offset this shortfall. With supply growth slight to neutral, the steady increase in demand is hauling prices remorselessly higher. It would take a recession in emerging markets to drive commodity prices substantially lower, and to date recession in those economies is not in the cards.

A couple of points deserve comment here. One is that the achievements of Western nations in reducing energy intensity are nothing compared to the achievements of China. According to an excellent paper on China’s energy consumption and demand , since 1980 China’s energy intensity has dropped by about 75% – nearly twice the drop in the US. The reason is that in every way the world's next superpower has become far more efficient.

Of course, I am raising this point because it suggests a very deep irony: Exporting the world’s manufacturing sector to developing countries has not only enabled the West to become a more efficient energy consumer. It has also helped those countries to become more efficient. Don’t blame the Chinese, in other words: They are doing a far better job at using the world’s resources efficiently than the West can even imagine.

Final Thoughts: These ideas, too, hark back to Marcel Coutu’s earlier comments. By subsidizing energy consumption within oil exporting countries, the world is contributing to inefficient energy consumption. Some of the cheapest gasoline prices in the world are in Saudi Arabia, Kuwait and Venezuela – the last being the all-out winner, with gasoline selling for $0.12 per gallon. The economies of these countries are not known for their gathering efficiency, yet the charts illustrate how much more dramatically oil consumption accelerates when prices are subsidized than when they are not.

The plain truth is that energy importers are subsidizing the inefficient consumption of oil in these countries because of the geographical reality that they have oil to export. Yet the countries we are most anxious about - China and India, for example - are the ones that are increasing their energy consumption not because of large subsidies, but because they are able to provide goods and services with greater energy efficiency than the rest of us.

Colin Campbell and the Cracks of Doom

By Peter McKenzie-Brown
For many peak oil believers, this is the scariest chart you can imagine. The blue lines show historical oil discoveries. The gold lines project discoveries into the future. The line that looks like a rising serpent shows annual production up to about 2005. The chart was created by peak oil guru Colin Campbell in 2004 for a deliciously ironic article titled "The Heart of the Matter". The chart looks like a road map to the Cracks of Doom, and it has been quite influential.

In this column I have frequently provided arguments in favour of peak oil theory, and I am an unabashed admirer of Campbell and his work. However, I believe this chart, though directionally accurate, is simplistic and alarmist. It needs to be nuanced. We can do that in three ways.

• First, note that the blue lines essentially track the world’s new-field discoveries of light and medium oil. The chart suggests that these volumes are the world’s oil reserves. It doesn’t nearly reflect the reserves additions that come through infill drilling, enhanced oil recovery and other standard oilfield practices. By applying simple math to the chart (subtracting production from discoveries), you will come up with world oil reserves far short of the roughly 1.2 trillion barrels that the Energy Information Agency and other authorities have booked.

As they are developed, most discoveries prove to be much bigger than the estimates at time of discovery. This is partly because reserves are a function of economics. When you find a new field you calculate its reserves based on present conditions and price forecasts – say, in 1970, $2.50 per barrel into the foreseeable future. As prices rise relative to costs, you will get more oil out of that field – of that you can be sure.

The thinking by which M. King Hubbert forecast the year of peak oil production in the United States was incredibly successful. What is rarely discussed, though, is that Hubbert underestimated by about 50 per cent the amount of oil that would be available in the US after it reached the peak. To a large extent this was because new reserves became available through changing technologies and more favourable petroleum economics.

• Second, give heavy oil, bitumen and oil shale the credit they deserve. Because of the nature of the beast, these unconventional resources are not booked as reserves until they become economically and technically producible.

Alberta’s huge oil sands are a classic example. In 2005 America’s Energy Information Agency booked Canadian oil reserves as second in the world (after Saudi Arabia) because of the impact of higher prices and improved technologies on the oil sands. If that amount of oil – 174 billion barrels (174 gigabarrels) – were added to the gold-coloured reserves lines on Campbell’s chart, it would require a line that would tower over the rest of the chart by a factor of three. Campbell’s methodology does not account for this kind of event. And in all likelihood, much more of the oilsands will eventually be booked as reserves.

That point takes me to this chart (click to enlarge), which is also from Campbell’s article. The black wedge – characterized as “Heavy, etc.” in the legend – is his estimate of the contribution of heavy oil to the global energy liquids picture. Eyeballing suggests that he expected these unconventional resources to be about 4.5 million barrels per day by now, world-wide.

Heavy oil, synthetic oil and non-upgraded bitumen represent about two million barrels of production per day in Canada alone, and Venezuela and Mexico are also big producers. What’s more, Canada’s oil industry is working hard to develop export markets for heavy oil, because there is a great deal more production yet to develop. Indeed, Canadian producers are selling their heavy oil at a discount because they cannot get it to world markets.

According to one excellent and credible report, seven years from now Alberta alone will be producing about three million barrels per day of “Heavy, etc.” That estimate risks production for economic and environmental obstacles, so it is probably low.

• Third – and this is my main point – let’s acknowledge that the serpent-like production line in Campbell’s chart, while it is not a happy sign, is not the spectre of doom it appears. The world’s unconventional resources will greatly blunt the blow – relative to the steep declines described in Campbell’s chart, in any event.

One amazing feature of the oil sands is their incredible energy density. Imperial Oil’s Cold Lake bitumen plant, for example, is a tiny dot on the map of Alberta, yet it produces 6 per cent of Canada’s oil. The resource density of these unconventional resources is immense, and that density is what makes it such an important resource. The world is heading toward capital-intensive, technology-intensive, pollution-intensive and energy-intensive energy - bitumen from Cold Lake, for example.

The greater the capital intensity, though, the lower the geopolitical risk must be. Keep that in mind when you consider development prospects for Venezuela’s Orinoco heavy oil belt, which is so huge it rivals the resources of Canada. The geopolitical risks in that country are enormous, so the likelihood is small that new Venezuelan supplies will soon hit world markets.

Strongman Hugo Chavez is increasingly unpopular in his own country, however, and the economy is in disarray. Oil production is in decline even though the the country has the largest conventional reserves in this hemisphere. Given that situation, it is possible to imagine a post-Chavez Venezuela which will develop those resources and become a resurgent supplier to the world. If that happened, it would lead to another super spike in booked reserves.

I share the view that a global Hubbert’s peak is nigh. The world is facing serious energy supply problems, and they are related to peak oil. To too great a degree, however, the discussion has failed to recognize the immensity and importance of the world’s unconventional sources of oil. Those vital resources will radically change the shape of the chart as they are plotted into it.

Bedfellows: The Prices of Gold and Oil

By Peter McKenzie-Brown

I’ve been a gold bug since the beginning of 2001, and you will probably notice on this chart that my timing was pretty good – especially so since the market in gold shares turned before the price of bullion did. In my opinion, the volatile price of gold shown here is directly tied to the recent dramatic increases in oil prices.

I think this chart is the best available picture of gold prices over the last quarter century. It's a point-and-figure chart, consisting of columns of Xs (upticks) and Os (downticks) to represent price movements over time.

As Stockcharts.com explains, there are several advantages to using P&F charts instead of the more traditional bar or candlestick charts. Briefly, point-and-figure charts automatically eliminate the insignificant price movements that often make bar charts appear ‘noisy;’ remove the often misleading effects of time from the analysis process; make recognizing support/resistance levels much easier; make trend line recognition a no-brainer; and help you stay focused on long-term price developments. In that context, you will notice that there has been more price volatility in the last six years (when the present uptrend began) than in the previous 20 combined.

Within that context, please note that The Privateer's technical analyst recently identified an extremely bullish on this chart – the dashed green line on the far right. If this trend stays intact, we won’t see $900 gold again for a long, long while. Point-and-figure charts can’t tell you when gold will run through $1000 per ounce, but this one gives a very strong opinion that it will. Perhaps you should buy some gold producers - or, if you can handle even greater volatility, a leveraged bull fund like HGU.

Why? In my opinion the price we are paying for gold is directly related to the price we are paying for oil. And gold's fast-moving price reflects a rapidly deteriorating situation in the petroleum industry.

A few weeks ago I answered the big question of the day – will oil prices climb or collapse? – with arguments that prices are still on an upward trajectory. I recently had a discussion with an oilman - he has created a $5 billion enterprise in Canada, and is still in the saddle - who tended to agree. He was just back from the Cambridge Energy Research Associates conference in Houston, where one participant was Matt Simmons.

Author of Twilight in the Desert, Simmons is a fierce sceptic of Saudi Arabia’s ability to increase or even maintain oil production capacity beyond the next few years. In a recent pronouncement, he proposed that the world reached maximum production two years ago. The apparent increase in supply since that time has been essentially a drawdown in global inventory.

Gold prices reflect political instability. And if Simmons is correct, the near-term geopolitical outlook is quite dangerous. Imagine battles for supply, complicated by Jihadism, disrupting the world order. Imagine regional conflict between large landmasses, as in the US vs. the Middle East and Islamic terrorism (already reality); Putin keeping his hand on the valve to dictate terms to parts of Europe (already reality); regional struggles between India and China for Southeast Asian resources, especially petroleum; America using the terms of the US/Canada free trade agreement to demand ever more of Canada’s oil and gas production.

Peak Oil: And that, of course, takes us to the topic of peak oil - the notion that the world has produced about half its producible reserves, and that implied demand will soon outpace available supply.
You usually see a peak in oil prices in the spring, and the low point for oil demand is usually in December, but that is not what peak oil is about. What it is about can be seen more clearly in this simple fact: we have $90 oil, and most companies are still missing their production targets. Maybe the oil just isn’t there.

Let's look at that in a broader context. It took about 250 million years to create all this oil, and we have used about half of it in the last three generations. That’s amazing.

Worse, western oil companies are now decapitalizing – buying back stock and otherwise returning cash to shareholders, rather than exploring for large new fields which aren't there. Decapitalization is one way to acknowledge the problem of peak oil.

Whether you do or don’t believe in peak oil, there hasn’t been sufficient reinvestment in the business. There’s been a classic cycle of underinvestment. What are the major companies doing with their cash flow? Spending some on new development and buying back stock to increase shareholder value. Some major companies (e.g., ConocoPhillips) are replacing as little as 15% of their reserves.

This underinvestment has several causes. For one, 80% of the world’s reserves are national oil – owned by countries where aliens can’t invest directly. These countries are mostly not known for their efficient use of capital: Venezuela, Sudan, Saudi Arabia. Other known reserves and resources are located in places that are difficult and undesirable to explore, like the Arctic.

The problem has been articulated for a full century. The oilman I was talking to put it in these no-nonsense terms: “Petroleum is a capital-intensive business. You’ve got to keep offsetting depletion and there’s a massive amount of capital required just to maintain production. And suppose there’s not enough investment to both offset the decline and grow production in the near term. What’s going to happen if India and China continue to boom and expand their requirements for energy?” That is a good question.

After listing a number of large producing basins and giant fields in decline, he pointed out that “the only country that has the potential to grow production over the next 5-10 years is Canada, because of the oil sands.” He returned to his central theme: “Whether you believe in peak oil or not, there is not enough money going back into the oil industry to offset production. It’s a huge issue.”

There are a couple of ironies in this. For one, a logical conclusion from peak oil theory is that, by accelerating production to meet demand, you are accelerating oil depletion. We consumed the first half of the planet’s oil reserves in three generations. How long will it take to consume the rest?

Using a geologist’s understanding of the underworld, peak oil prophet M. King Hubbert suggested that the world’s crude oil production will take as long to decline as it took to peak – roughly speaking, three generations. But isn’t it possible that, because of improved production technologies and much greater markets in the post-peak world, it will actually take much less time? The question matters.

The other irony is that oil companies, whether they understand the peak oil issue or not, are responding to developments through a program of decapitalization – as I have already suggested, returning cash flow to investors, with an eye to eventually leaving the oil part of the business. Giant and other large fields not being available through exploration, much of the private sector is now involved in the orderly and efficient liquidation of existing assets through mergers and acquisitions. This matter also matters.

Where is Alberta? Why Should You Care?

A barrel of crude oil supplies more than energy. It is also a building block for petrochemicals and other goods.

By Peter McKenzie-Brown

Can it really be true that - oil at $90 per barrel notwithstanding - the Canadian petroleum industry is facing an economic downturn?

It is true, and you should care. Traditionally ignorant about Canada, Americans in particular should understand the implications of the critical economic issues now roiling the sector here.

Canada is by far the largest source of imported oil for America, and one of the few large oil producers with the potential to increase production well into the future. The US Energy Information Administration has identified Canadian reserves as being second only to those of Saudi Arabia. So if you worry about peak oil and the world’s energy future, you would be foolish to ignore the geopolitics and energy economics that are racking Canada today.

Canada's petroleum industry is facing a perfect storm. Five main factors are at play. First, the Canadian dollar is at its highest level against the US dollar in 30 years. Second, the natural gas industry is in the tank. Third, environmental issues are getting critical. Fourth, industrial inflation is rocketing out of sight. And finally, governments have become greedy - very greedy.

Together, these developments augur ill for oil supply. Let’s look at them, one at a time.

1. Exchange Rates: In 2001, the Canadian dollar's value was just over 60 cents per US dollar, and Fortune magazine famously dubbed our loonie the "northern peso". Today it is worth $1.04 US. During that period, oil (priced in US dollars) has tripled in value.

These parallel movements have had some curious effects. Oil prices for Americans have more than tripled, based on nominal (US dollar) prices. In Canadian dollar terms, however, they have "only" doubled. That's a big increase, of course, but it's more modest than in the rest of the world.

Consumers have been hit much harder in the United States than in Canada - that's on the one hand. On the other, American oil companies have benefitted far more from oil price increases than those in Canada. And since Canadian oil companies have profited much less, they have less capital for exploration and development than you might expect.

Put another way, foreign exchange movements have made crude oil less profitable to develop and produce. The industry thus has less incentive to develop it.

2. The Natural Gas Sector: Forecasters now commonly suggest that western Canada's conventional gas production has peaked and will continue to decline.

The reasons are complex, but part of the reality is that Canadian producers can’t sell their gas at the prices American producers command. The $7 futures contract for gas on the NYMEX is not reality in Canada. In Western Canada, our producers get $5 per thousand cubic feet for their gas, while the cost of finding and developing the stuff is in the $7-$9 range. Once again, this means less capital for investment in domestic reserves.

And yet, as this article discusses below, that sector has just been hit with higher royalties. That's just what you need when new production is marginally profitable at best.

3. The Environment: Global concern about climate change is leading to higher taxes on crude oil, most of it imposed at the retail level. In Canada, this includes transit taxes in the cities of Vancouver and Montreal, and – effective this month – a carbon tax in Québec.

Retail taxes are not a concern for the oil producers, except to the extent they are inflationary. However, tough environmental rules in the upstream are creating a lot of problems. They increase costs and they delay project development.

No one disagrees with the importance of good environmental regulation, but good regulation does not come cheap. It costs both time and money. Environmental regulation is adding to inflation and delaying the onset of oil production that is increasingly critical.

4. The Boom: The general boom in Alberta is also contributing to oil patch inflation. The province hosts most of Canada’s petroleum production, and is the North American jurisdiction with the lowest unemployment rate.

In this province the petroleum sector faces rapidly escalating costs in almost every area. Office space in Calgary, the industry’s geographic centre, has quintupled in five years. Labour for oil sands development is astronomical. Productivity is declining.

How can there be an economic boom when the basic economics of conventional oil and gas production are in decline? The main reason is that conventional reserves, which were drilled in an era of lower costs, are now getting produced and sold as quickly and profitably as possible. High prices for oil are accelerating the resource’s depletion.

Costs for drilling and mineral rights have declined in the last year, but that is hardly cause for celebration. It has happened because the industry is less inclined to drill. From an all-time high of almost 25,000 wells in 2005, drilling has dropped precipitously. Estimated drilling this year will total only 17,650 wells this year and a mere 14,500 wells next. Most of the drop is in the area of natural gas drilling, but it is still something to worry about. If you don’t drill, you don’t find oil or gas.

5. Government Greed: The final piece of this puzzle is the matter of royalties and taxes. In Canada, oil and gas resources are mostly owned by government, and governments get revenue from producers in a variety of ways – primarily economic rent (royalties), sales of mineral rights, and a variety of taxes. In response to voters who are convinced high oil prices mean high profits for oil producers, Canadian governments are finding ways to increase their take from the sector. This is their right and privilege, of course. However, the more the industry has to pay, the less oil it is going to produce.

Today, things took a decidedly ugly turn for the petroleum industry in Alberta, the province that produces more than 90 per cent of Canada's oil. The province has no debt, has no sales tax and yet runs a huge fiscal surplus. This year alone the province projected the surplus to be $2.2 billion, based on lower oil price assumptions.

Its great wealth notwithstanding, this afternoon the provincial government announced a much-dreaded new royalty framework that will boost royalties by $1.4 billion per year (20 per cent) in 2010. The new rates, which will increase maximum royalties from current highs of 35 per cent to 50 per cent for conventional oil and natural gas, won't take effect until 2009.

In the critical area of a regime for oil sands development, the system also changed. The current royalty is 1 per cent per year on gross revenue until a project recovers its multi-billion dollar investment. The royalty then rises to 25 per cent of revenue minus operating and other costs. Under the new regime there will be a sliding tax which starts increasing at $55 a barrel. Assuming current prices, oil sands royalties will be about 5 per cent before payout and 33 per cent thereafter. The maximum rate will be 40 per cent.

Outcome: The chart projects Canadian oil production based on the first of these two royalty regimes - the one that has so successfully encouraged development in the past. Rest assured that, under the new arrangement, future oil production from both conventional and oil sands resources will be less than the volumes projected.

In a world anticipating peak oil, making oil production less profitable is a serious matter - and, by definition, the new fiscal regime will make oil and gas production less profitable in Alberta. Love ‘em or hate ‘em, oil companies are governed by the rules of capitalism. They put their money where it will generate the best return.

Canada, which has a strategically vital place in the world petroleum industry, is the world's seventh largest oil exporter, but also the seventh largest importer. In most of eastern Canada, the refining side of our industry is happily importing oil from overseas. Because they pay for it with our strong currency, it costs less. This is great for Canadian consumers.

When you have a strong currency, you have more options. Canadian producers will increasingly invest in production from riskier but lower-cost and therefore more profitable exploration provinces overseas. (One great under-explored region, for example, is Southeast Asia.) But they will do so at the expense of secure investment in Canada, including development of the vast oil sands deposits.

We should worry about this, and worry a lot.

History of the Petroleum Industry in Canada, Part Two

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

Canada's petroleum frontiers are of two types.

The technological frontiers include the oil sands of Alberta, and the huge heavy oil belt that stretches from central Alberta into Saskatchewan, and straddles the borders between the two provinces. Here the resources are known, but technologies to produce oil from them in cost-effective ways are still being developed.

The geographical frontiers are the vast petroleum basins in the north, in the Arctic Islands and offshore, and off the coast of Atlantic Canada. These areas are difficult and expensive to explore and develop, but successful projects can be profitable using known production technology.

This article covers the early development of both.

Oil sands and heavy oil

Chemistry of Petroleum: An early history of Canada’s petroleum industry would not be complete without a chronicle of pioneering efforts to produce the tar sands (now commonly called “oil sands”) of northern Alberta. To appreciate these resources, it is important to understand the "gravity" of oil and gas.

Gravity refers to the weight spectrum of hydrocarbons, which increases with the ratio of hydrogen to carbon in a chemical compound's molecule. Methane (CH4) - the simplest form of natural gas - has four hydrogen atoms for every carbon atom. It has light gravity, and takes the form of a gas at atmospheric pressure. The next heavier hydrocarbon, ethane, has the chemical formula C2H6 and is a slightly heavier gas. Gases, of course, have no gravity at atmospheric temperatures and pressures.

Organic compounds combining carbon and oxygen are many in number. Those with more carbon atoms per hydrogen atom are heavier, and less likely to be gaseous. Most hydrocarbons are liquid under standard conditions, with greater viscosity associated with greater gravity. The American Petroleum Institute has developed a formula to measure the API gravity of petroleum liquids.

Heavy oil and bitumen, which have more carbon than hydrogen, are heavy, black, sticky and either slow-pouring or so close to being solid that they will not pour at all unless heated. Although the dividing line is fuzzy, the term heavy oil refers to slow-pouring heavy hydrocarbon mixtures. Bitumen refers to mixtures with the consistency of cold molasses that pour at room temperatures with agonizing slowness.

It is difficult to grasp the immensity of Canada's oil sands and heavy oil resource. Sand deposits in northern Alberta include four major deposits which underlie almost 70,000 square kilometres of land. The volume of bitumen in those sands dwarfs the light oil reserves of the entire Middle East. One deposit, the Athabasca oil sands, is the world's largest known crude oil resource.

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

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

Drilled at a site called Pelican Portage, the well blew out at 235 metres after encountering a high-pressure gas zone. According to drilling contractor A.W. Fraser,
“ The roar of the gas could be heard for three miles or more. Soon it had completely dried the hole, and was blowing a cloud of dust fifty feet into the air. Small nodules of iron pyrites, about the size of a walnut, were blown out of the hole with incredible velocity. We could not see them going, but could hear them crack against the top of the derrick . . . . There was danger that the men would be killed if struck by these missiles. ”

Fraser's crew unsuccessfully tried to kill the well by casing it, then abandoned the well for that year. They returned in 1898 to finish the job, but again they failed. In the end, they simply left the well blowing wild. Natural gas flowed from the well at a rate of some 250,000 cubic metres per day until 1918. In that year a crew led by geologist S.E. Slipper and C.W. Dingman finally shut in the well.

These wells helped establish that the bitumen resource in the area was huge. There was now clear recognition of the commercial potential of the oil sands, and a long period of exploration and experimentation followed. The point of this research was to find a method of getting oil out of the tar sands at a reasonable price.

Alfred Von Hamerstein, who claimed to be a German count, was one of the colourful early players in the oil sands. He had been en route to the Klondike, but stayed and turned his interest from gold to the oil sands. In 1906 he drilled at the mouth of the Horse River, but struck salt instead of oil. He continued working in the area, however.

In 1907 Von Hamerstein made a celebrated presentation to a Senate committee investigating the potential of the oil sands.
“ I have all my money put into (the Athabasca oil sands), and there is other peoples' money in it, and I have to be loyal. As to whether you can get petroleum in merchantable quantities . . . I have been taking in machinery for about three years. Last year I placed about $50,000 worth of machinery in there. I have not brought it in for ornamental purposes, although it does look nice and home-like. ”

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

In 1913, Dr. S.C. Ells, an engineer with the federal department of mines, began investigating the economic possibilities of the oils sands. It was then that the idea of using the sands as road paving material was born. In 1915, Dr. Ells laid three road surfaces on sections of 82nd Street in Edmonton. Materials used included bitulithic, bituminous concrete and sheet asphalt mixtures. A report, ten years later, by a city engineer stated that the surface remained in excellent condition. McMurray asphalt also saw use on the grounds of the Alberta Legislature, on the highway in Jasper Park and elsewhere in Alberta.

Although private contractors also mined oil sand as a paving material, the proposition was not economic. Fort McMurray (the village closest to the near-surface deposits) was small and far from market, and transportation costs were high.

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

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

Under the agreement with the government, the plant was to be in operation by September 1, 1936. But forest fires and failure of equipment suppliers to meet delivery dates delayed completion.

The agreement called for mining 45,000 tonnes of sands in 1937 and 90,000 tonnes each year after 1938. The 1,555-hectare lease carried a rental of $2.47 per hectare per year. There was to be a royalty of $0.063 per cubic metre on production for the first five years, and $0.31 per cubic metre thereafter.

Mining at the Abasand plant began May 19, 1941. By the end of September, 18,475 tonnes of oil sand had produced 2,690 cubic metres of oil, but in November fire destroyed the plant. Rebuilt on a larger scale, it was fully operational in June 1942. Between 1930 and 1955, the International Bitumen Company Limited under R.C. Fitzsimmons operated a smaller scale pilot plant at Bitumount.

In 1943, the federal government decided to aid oil sands development, and took over the Abasand plant. The federal researchers concluded that the hot water process was uneconomic because of the extensive heat loss and proposed a “cold” water process. But work at the plant came to an end with a disastrous fire in 1945.

Meanwhile, in July 1943, International Bitumen Company reorganized as Oil Sands Limited. When the Alberta government became disenchanted with federal efforts in the oil sands and decided to build its own experimental plant at Bitumount, the province engaged Oil Sands Limited to construct the plant.

The company agreed to buy the plant within a period of ten years for the original investment of $250,000. The cost of the plant was $750,000, however. A legal claim against Oil Sands Limited resulted in the province taking possession of the plant and property at Bitumount. The plant consisted of a separation unit, a dehydrating unit and a refinery. The plant conducted successful tests using the Clark hot water process in 1948/49 then closed, partly because the recent Leduc discoveries had lessened interest in the oil sands.

Oil Sands Limited eventually reorganized as Great Canadian Oil Sands Limited (now Suncor}, which built and started operation of the first commercial-sized integrated oil sands project in 1967. It had found solutions to the problems of extracting a commercial grade of oil from the sands - problems that had been the concern of financiers, chemists, petroleum engineers, metallurgists, mining engineers, geologists, physicists and many other scientists and pseudo-scientists for may decades. A much later development - although its roots go back to the 1940s, the massive Syncrude plant did not go into operation until 1978 - now supplies some 14 per cent of Canada's crude oil production, in the form of synthetic oil.

Heavy Oil Story:Heavy oil is a sister resource to bitumen. It is lighter than bitumen and its reservoirs are much smaller than the great oil sands deposits. Even so, its dimensions are impressive. But like the oil sands, only a small percentage is producible.

Often called conventional heavy oil, this low-density oil can be recovered by conventional drilling techniques or by waterflood, a technique of injecting water into the reservoir to increase pressure, thus forcing the oil toward the well bore. When these techniques work, heavy oil is like the more commercially attractive lighter grades of oil. But heavy oil can also be quite viscous. It can need some form of heat or solvent and pressure before it can flow into a well bore to be produced. When heavy oil requires these techniques to go into production, it is known as non-conventional heavy oil.

The first heavy oil discoveries came with the pursuit of conventional light and medium crude oil. Because much of western Canada's heavy oil is in pools close to the surface, early explorers using older rigs discovered many of those pools before they came upon the deeper light oil reservoirs.

One of the first finds was in the Ribstone area near Wainwright, Alberta in 1914. The province's first significant production of heavy oil came from the Wainwright field in 1926. Producers drew almost 6 000 barrels of heavy oil from the field in that year. A small-scale local refinery distilled the heavy goo into usable products.

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

The most important exception was at Lloydminster. While the first discovery occurred in 1938, serious development did not begin until Husky Oil moved into the area after the second world war.

Husky Oil was born during the Depression through the efforts of Glenn Nielson, an Alberta farmer driven to bankruptcy when the bank called a loan on his farm. Nielson had moved to Cody, Wyoming, by the time he founded Husky as a refining operation. He turned his attention back to Canada after the second world war, and decided to set up a refinery at Lloydminster. Steel was scarce, so Husky dismantled a small Wyoming refinery constructed during the war to provide bunker fuel to the American Navy. It loaded the pieces onto 40 gondola cars and shipped them north by railway.

The company began reassembling the 400 cubic metre per day facility in 1946, and the refinery went on production the following year. Strategically located between the Canadian Pacific and Canadian National railroad tracks in Lloydminster, the refinery soon began to get contracts for locomotive bunker fuel. The company also found a strong market for asphalt for road building.

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

Husky began producing heavy oil from local fields in 1946, and by the 1960s was easily the biggest regional producer. In 1963 the company undertook another in a series of expansions to the refinery. To take advantage of expanding markets for Canadian oil, it also began a program to deliver heavy oil to national and export markets.

The key to the $35 million project was the construction of a reversible pipeline which could move the viscous heavy oil into the marketplace. The 116-kilometre "yo-yo" pipeline - the first in the world - brought condensate from the Interprovincial Pipe Line station at Hardisty, Alberta. The company began mixing this very light hydrocarbon with heavy oil, enabling it to flow more easily. The company then pumped the blend through its pipeline (hence the nickname "yo-yo") back to Hardisty. From there the Interprovincial took it eastward to market.

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

True North

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

Led by a geologist, a crew comprised of six drillers and an ox (Old Nig by name) began a six-week, 1,900-kilometre journey northward by railway, river boat and foot to the site now known as Norman Wells. They found oil - largely by luck, it turned out later - after Ted Link, the geologist, waved his arm grandly and said, “Drill anywhere around here.” The crew began digging into the permafrost with pick and shovel, unable to put their cable tool rig into operation until they had cleared away the mixture of frozen mud and ice. At about the 30-metre level they encountered their first oil show. By this time, the river ice had frozen to 1.5 metres and the mercury had plunged to -40 degrees. The crew decided to give up and wait out the winter. They survived, but their ox did not. Old Nig provided many a meal during the long, cold winter.

Drilling resumed in the spring and a relief crew arrived in July. Some of the original crew stayed around to help the newcomers continue drilling. On August 23, 1920, they struck oil at 240 metres. The world’s most northerly oil well had come in. In succeeding months, Imperial drilled three more holes - two successful, one dry. The company also installed enough equipment to refine the crude oil into a type of fuel oil for use by church missions and fishing boats along the Mackenzie. But the refinery and oil field closed in 1921 because northern markets were too small to justify the costly operations. Norman Wells marked another important milestone when in 1921 Imperial flew two all-metal 185-horsepower Junkers airplanes to the site. These aircraft were among the first of the legendary bush planes which helped to develop the north, and forerunners of today’s commercial northern air transport.

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

When Japan captured a pair of Aleutian Islands, Americans became concerned about the safety of their oil-tanker routes to Alaska and began looking for an inland oil supply safe from attack. They negotiated with Canada to build a refinery at Whitehorse in the Yukon, with crude oil to come by pipeline from Norman Wells. If tank trucks had tried to haul the oil to Alaska, they would have eaten up most of their own load over the vast distance.

This spectacular project, dubbed Canol - a contraction of “Canadian” and “oil” - took 20 months, 25,000 men, 10 million tonnes of equipment, 1,600 kilometres of road, 1,600 kilometres of telegraph line and 2,575 kilometres of pipeline. The pipeline network consisted of the 950-kilometre crude oil line from Norman Wells to the Whitehorse refinery. From there, three lines carried products to Skagway and Fairbanks in Alaska, and to Watson Lake, Yukon. Meanwhile Imperial was drilling more wells. The test for the Norman Wells oilfield came when the pipeline was ready on February 16, 1944. The field surpassed expectations. During the one year remaining of the Pacific war, the pipeline pumped about 160,000 cubic metres of oil to the Whitehorse refinery.

The total cost of the project (all paid by US taxpayers) was $134 million, in 1943 US dollars. Total crude production was 315,000 cubic metres (7,313 cubic metres of which spilled.) The cost of the crude oil was $426 per cubic metre ($67.77 per barrel). Refined petroleum product output was just 138,000 cubic metres. Cost per barrel of refined product was thus $975 per cubic metre, or 97.5 cents per litre. Adjusted to current dollars using the US Consumer Price Index, in 2000 dollars the oil would have cost $4,214 per cubic metre ($670 a barrel), while the refined product woul