Calgary Rising

The world's greatest concentration of energy knowledge resides here. 

A cow town no more, Canada’s oil and gas capital sets its sights on Houston as petroleum capital of the world

This article appears in the December issue of Oilweek

By Peter McKenzie-Brown
Could Calgary become the centre of the petroleum world, finally shedding the century-old moniker of “Cow Town”? Many people think it’s not only possible, but inevitable.

Consider the views of Heather Douglas. “When I was president of the (Calgary Chamber of Commerce), I used to challenge visitors to name another city that had the intellectual knowledge about energy that Calgary has,” she says. Now a VP at Athabasca Oil Sands Corp. she adds, “That knowledge can be applied to any form of energy – nuclear, solar – not just oil and gas. We are already one of the world’s premier energy centres, and in the 21st century energy issues will endlessly challenge global economic and environmental systems.” Already in the big leagues, the city needs to get ready for growth.

Gary Leach puts the possibilities into a broader context. The executive director of the Small Explorers and Producers Association of Canada (SEPAC), Leach argues that “Houston was the late 20th century’s global energy capital. It’s now in decline, and Calgary is in the ascendant. A few things could affect (Calgary’s growing dominance.). What if the Mackenzie Valley and Alaska Pipelines are constructed, making Alberta the distribution centre for Arctic gas across the continent? Even if that doesn’t happen, within the next 20 years hundreds of billions of dollars will be invested in this province to develop the oilsands, and Canada will become a net exporter of millions of barrels per day – maybe 5 million barrels per day, most of it from the oilsands. The numbers are eye-popping.” According to a recent CAPP forecast, this country’s oil production will rise from 2.8 million barrels per day last year to 4.7 million in 2025.

“Looking back 20 years from now,” Leach adds, “we will see Calgary as a city of global importance” in more than energy. “Part of that is because of Canada’s energy and other resource surpluses. The other is the fact that Canada is one of the few countries in the world with food surpluses,” and Calgary will continue to be an agribusiness centre.

Constant Mixing
For decades Calgary has been home to the largest number of major head offices in Canada outside of the Toronto area, which has five times the population. Calgary is a corporate city, which arranges finance and makes business decisions. It is a technical centre, with an amazing array of scientific and technical skills. It is a management city, with seasoned executives continually making high-stakes decisions.

A unique mix of characteristics have set Calgary up for growth and increasing strategic importance in the energy world. Within the city’s ten blocks – the business part of downtown – is an extraordinary concentration of expertise. This includes the largest concentration of geological talent in the world, for example. Alberta’s petroleum industry has traditionally produced from conventional oil and gas formations that on a world scale are relatively modest. The industry developed strong drilling, engineering and technical skills at least partly in response.

Other areas of expertise include management, legal and accounting skills; finance and economics; technological development and environmental innovation. These skills developed in an entrepreneurial climate which takes a competitive delight in financing, exploring, developing and overseeing production from the geologically complex Western Canada Basin.

Underpinning the entrepreneurial environment is a fair and transparent regulatory system. Alberta’s system of land auctions and western Canada’s efficient regulatory systems make hydrocarbon development an attractive proposition. There is an enormous wealth of oil and gas data that must be made available by law. In Alberta, that information is mostly available through the Calgary-based Energy Resources Conservation Board.

With its concentration of companies, executives and expertise, Calgary is now the Canadian city you have to be in if you want to be in energy. You can’t be in Regina or Winnipeg or Toronto and be in the oil business. “In the last 20 years we have had the National Energy Board move here from Ottawa,” says Leach. “We had Shell and Imperial and TransCanada move here from Toronto and Enbridge moved its headquarters here from Edmonton.” Gulf Canada came indirectly, when Petro-Canada bought it out; so did BP when it acquired Amoco. “Calgary now has the densest focus of oil industry talent in the world between the Bow River and the Canadian Pacific rail tracks,” he says. “Everybody here is within a five or 10 minute walk of everyone else. That dense connectivity has created a unique and creative mix. There’s a constant mixing of competitors and collaborators.”

An unusual characteristic of Canadian business is that companies tend to go public at a very early stage – a tradition that in Calgary seems to be on steroids. There are hundreds of start-ups and other small energy companies, many of which have gone public. Forty per cent of the world’s 995 publically traded energy companies are headquartered in Calgary. Those companies represent about 30% of Canadian stocks by market value.

One of the reasons they are here is the resource potential. According to Heather Douglas, “Alberta is well-positioned to be a leading energy producer for decades. Challenging unconventional resources – oil sands, shale, tight and sour gas – are all a vital part of our future.”

The World’s Energy Cities
There is an organization known as the World Energy Cities Partnership, with 16 members. Besides Houston and Calgary, these cities include, for example, Aberdeen, Scotland; Atyrau, Kazakhstan; Dammam, Saudi Arabia; Daqing, China; Stavanger, Norway; and Tomsk, Russia. Canada is the only country to have three “energy cities” – the other two being Halifax and St. John’s.

How do the world’s other energy cities compare to Calgary? “Many of these centres have the disadvantage that they are dominated by a few very large producers, many of them state-owned,” according to Leach. “For example, Rio de Janeiro is the centre for Brazil’s offshore oil production, but it’s dominated by Petrobras.”

Other cities have other problems. “To be a serious contender as an oil and gas centre, you have to have the rule of law, democracy, and a stable environment,” Leach says. “You have to have transparent laws and regulation. You have to be a place where people will invest for the long term.” In many energy cities, few or none of these factors exist: Think China, Iran, Kazakhstan, Russia, and Saudi Arabia. Sudan, anyone?

What about Europe’s energy cities? “Aberdeen is only a service centre for oil and gas. It’s not financial. It doesn’t rival Calgary in any way,” according to the flag-waving Leach. “The same is true of Stavanger: It’s an important regional support and service centre, but that’s all. And of course North Sea oil production is declining rapidly, and that’s going to affect the relative rankings of those two centres…. Only Calgary, Houston, Dallas and London can say ‘We have big companies, we have oil and gas assets, we have a lot of financial strength, and here is where decisions are made.’”

London is a special case. It’s a financial superpower, of course, and it is headquarters for BP, Shell and some producers based in the North Sea. However, because energy is a relatively small part of its economy, it really isn’t an energy city.

The Rise and Decline of Houston
Houston’s status as the world’s dominant energy centre is fairly new. Until 1986 there were five significant oil centres in the US: Houston, but also Dallas, Denver, Oklahoma City and Tulsa.

When the oil industry went into a 20-year slump with the 1986 oil price collapse, much of the industry moved from Tulsa, Oklahoma City and Denver to Houston, which also benefitted from explosive growth in Gulf of Mexico drilling. Dallas is still an important centre, but primarily because ExxonMobil calls it home.

With its port and pipeline connections, Houston has become the world’s largest refining hub. It is an extremely important centre for petroleum technology, especially for offshore drilling and production. Still the world’s premier energy city, Leach argues that “its best days are behind it. As Calgary’s potential waxes, Houston’s is going to wane. We have the potential to rival them, not only in the oilsands but because of the prospect of Pacific Rim exports, for example. Calgary can become a Pacific Rim energy capital. This isn’t fantasy: Chinese, Japanese, Korean and Malaysian (companies are already) here.”

Already snapping at Houston’s heels, Calgary one day may take over. According to Chris Lee, managing partner of a resource consultancy provided by accounting giant Deloitte Touche, this country “has the opportunity to be an energy superpower. To do that we have to ensure that issues around transportation infrastructure are resolved. We need a national energy strategy. We have to deal with potential labour shortages and cost overruns, and we need a more positive public image for the oilsands. The future of the oilsands is incredible. Just imagine what would happen if (bitumen) carbonates became economic! What would this city be like?!”

Heather Douglas thinks Alberta should seize the moment to establish a Canadian benchmark for international trade. Right now world oil prices are quoted in reference to foreign crudes – mostly West Texas Intermediate (WTI), Brent and Dubai. “We usually sell at a discount to WTI,” she says. “Brent production is rapidly declining, while Alberta production is growing. We need to create a Canadian benchmark that is internationally recognized – maybe a price based on upgraded bitumen.”

Awesome
The Economist recently ranked Calgary as number five on its list of the world’s 100 most liveable business cities, and a Houston-based publication named Rigzone named the city number 2 in its list of the top ten energy centres to be transferred to – citing the Rockies, the fishing and the Stampede. (Dubai was number one, because of its tall new buildings and its shopping.)

And some months ago, 17-year-old Megan Butlin, on her way to Sweden as an exchange student, delivered a presentation to my Rotary club. It was a trial run for a presentation she would give to her Stockholm sponsors. According to one of her slides, “Statistically speaking, Calgary is 100% more awesome than Edmonton.”

Is any of this stuff really true?

Because of its proximity to major oil deposits – in the early days, Leduc and Pembina; recently, the Athabasca and Cold Lake oilsands deposits – Edmonton has become one of the world’s premier operations and service centres for the petroleum industry. It has fabrication and manufacturing capacity that would be the envy of virtually any other oilfield service centre. The University of Alberta is a jewel in the city’s crown, and it has been a centre of oilsands research since the 1920s.

The area is Alberta’s refining and petrochemical centre – notably the “Industrial Heartland” northeast of Edmonton. That industrial region has grown organically since the late 1940s, when Imperial Oil brought a tin-pot World War II refinery down from Whitehorse to process crude from nearby Leduc and other new fields. Now the beneficiary of more than $25 billion in investment, this 582-square-kilometre region hosts 40 large companies and many small ones. Together they operate numerous refineries and petrochemical plants, an upgrader, pipelines, service companies and numerous other interdependent businesses.

As the oilsands enable Canada to become an energy superpower, Edmonton will continue to serve as the staging area for the world’s biggest petroleum projects – most of them encircling another dynamic Alberta city, Fort McMurray. That, too, is awesome.

Tell Your Banker to Buzz Off!

As lines of bank credit grow increasingly restrictive, royalty financing offers new options for operators. This article appears in the February issue of Oilweek

By Peter McKenzie-Brown and Richard Graham

Especially if you’re a natural gas producer, it can be tough to get credit these days. What are you going to do?

One possibility is to do what Compton Petroleum did last spring. Primarily a gas producer, the company sold a 5% royalty interest in 19,000 barrels of oil equivalent (BOEs) production per day, plus a 5% interest in 600,000 undeveloped acres to Caledonian Royalty Corporation, a company founded and managed by oil and gas financier Jim Kinnear.

In a way, royalty financing is filling a gap created by the elimination of energy trusts – at least, that’s what conventional wisdom would like you to think. However, as we researched this story, it became increasingly clear that royalty financing not only meets the needs of investors (especially heavy hitters), but it is also an excellent tool to meet the industry’s needs – natural gas companies like Compton Petroleum, for example, but other companies as well. While the industry traditionally associates the idea of royalties with government take, the new players in this area are promoting it as an effective alternative financing tool. While the jury is still out on whether it will be a preferred form of funding during the next boom, right now it has a lot of merit.

The Olden Days
Royalty funding is not new in Canada’s oil and gas sector, but the industry has to a large extent lost its collective memory of royalty financing. The founder of royalty financing in Canada was R.A. (Bob) Brown who, with his son – also named Bob Brown – later turned Home Oil into a major independent oil company.

During the Great Depression royalty financing played a critical role in the development of Turner Valley – at the time “the biggest oilfield in the British Empire.” On June 16, 1936, Brown senior’s Turner Valley Royalties #1 well began flowing 850 barrels of crude oil per day. Funded by royalty financing which guaranteed investors a percentage production from successful wells, Royalties #1 found Turner Valley’s oil formation two decades after earlier producers began stripping naphtha from wet gas discoveries there. This meant the first generation of producers had wasted much of the pressure needed to produce light oil from the reservoir.

Royalties financed 69 other wells in Turner Valley in the two years following Brown’s discovery. Since only two of those wells were dry, the primary constraint on new investment was the rapid saturation of local crude oil markets.

Royalties financing didn’t last, however. In 1938 the federal government decreed that income from oil production was taxable as profits in the hands of the producing company. In the investor’s hands it was taxed again as income, rather than return of capital. Although a producing company appealed this decision successfully, the incident shook confidence in the system. Indeed, in 1942 Ottawa amended the Income Tax Act to tax oil income from royalty trusts at wartime rates. Although the federal government repealed this provision in 1950, it was 70 years before petroleum royalties again became a significant alternative to traditional debt and equity.

Teams at Play
In recent years, at least four teams have suited up for the royalty game. Each team has its own style of play and a strategy that sounds like a winner. Brickburn Asset Management has the most passive style of play. Range Royalty Management is the brainchild of Clayton Woitas, founder of Renaissance Energy, and effectively combines royalty financing with E&P. Caledonian, founded and controlled by Jim Kinnear, is new while the fourth, Freehold Royalties Ltd. has roots going back to the creation of Canada.

Until it converted to a dividend-paying corporation at the beginning of 2011, Freehold was a publicly listed trust that issued distributions based on a large number of diverse royalty-generating properties (mineral rights and gross overriding royalties) and working interest properties. Its income comes from oil, gas, liquids and potash. Many of its properties are legacy assets – royalty rights which Ottawa granted to railroads and the Hudson’s Bay Company as part of the national effort to secure Western Canada. Freehold has interests in more than two million gross acres of land and 23,000 wells.

In a statement, the company’s president and chief executive officer, Bill Ingram, said that most “of our oil and gas production comes from mineral title lands and gross overriding royalties, which have no associated capital or operating costs; thus we have relatively low capital expenditure requirements. The strength of our royalties has allowed us to preserve a high payout ratio historically and should allow us to maintain a high dividend payout.”

The newest team is that of financier Jim Kinnear, who sees royalty financing as an extension of a common practice in Canada’s mining sector. When he started out in the securities business, says Kinnear, “we invested in small mining syndicates that had acquired claims – money returned plus a carried interest. I learned about returning capital to investors. People liked to see a return of cash or cash flow, and they still do.”

Last year, after retiring from Pengrowth Energy Trust – a business he founded and managed for over 20 years – Kinnear began applying this lesson in finance to oil and gas in an innovative way. So far he and his investors have placed $100 million in Caledonian Royalty Corporation. Their royalty investments – which represent registered interests in land and rank ahead of banks and other creditors – allow qualified investors to participate in cash flow based on production. Caledonian’s royalty interests include current production and potential future production from a large undeveloped land base in Alberta. At present, those assets are heavily weighted towards natural gas.

Range Royalty Management operates rather more like a traditional oil company, but also does financing through the issuance of royalties. The company was not willing to be interviewed for this story, but a source who asked to remain anonymous describes the firm as having “a great technical team. While they always want an overriding royalty, they get at it in a different way. They begin at the grassroots level” – by going to land sales, drilling and frequently operating oil and gas properties. Issuing royalties effectively gives the company financing that bears no interest, doesn’t need to be repaid and is free of commodity price risk.

The Problem with PUDs
Another newcomer to royalty financing is Bill Bonner, president of Brickburn Asset Management. Brickburn manages four partnership funds that invest in royalty interests under the WCSB brand name.

Although he has had a long career in oil and gas financing, Bonner only added royalty financing to his company’s portfolio in 2008. His system is both conservative and traditional. “We raise capital through prospectus,” he explains, “then make that capital available to experienced operators for the completion of development wells. In return, we earn a gross overriding royalty. One way to think about this is that we rent the operator’s wellbores. We are not concerned with any of the traditional costs, including the well’s ultimate abandonment.” He adds, “The sanctity of the royalty position is a very special place to get to.”

Bonner is adamant that royalty financing in its own right is an effective and robust form of finance rather than a replacement for the energy trust. When the oil industry goes into boom mode again, “we think there will still be opportunities for this kind of instrument, although candidly we don’t know for sure.”

He adds that “the main link between us and income trusts is that we pay out capital as we receive it. We provide a stream of income which the investor really likes. We are very much a distribution model as opposed to a model where you retain capital and grow. One of the advantages we have is that our investors get a tax write-off – a 30% Canadian Development Expense, which enables them to write off all of the money they have invested. It just takes time.”

He adds, “We have completed five partnerships totalling $82 million. We only take the money for three years. At that point our prospectuses say we will offer a ‘liquidity event’ to return the capital investment back to the investor. Our game plan is to somehow monetize the property after our investments have gone through a period of flush production – either by selling it outright or by somehow putting it into a going-concern business.”

Brickburn’s first royalty partnership came about in 2008. After the 2006 Halloween Massacre imposed a new tax on energy trusts, he says “it became increasingly difficult for smaller energy businesses to finance growth because for them the liquidation opportunity (selling their assets to energy trusts) had disappeared. So we moved in with this royalty instrument.” Complicating the tax problem was the financial crisis. Traditional sources of equity and debt financing for junior oil and gas companies seemed to have disappeared. Part of the solution was royalty financing.

Brickburn royalty partnerships have participated in more than 70 wells, 95% of which used horizontal multi-frac technology. “One of the reasons operators like us,” according to Bonner, “is that we extend their budgets. If we provide one and a half million dollars for a horizontal well, it frees up that much money for them to go do something else.” Royalties can add to the companies’ bottom lines in other ways, too. One of the main reasons is that operators tend to carry inventories of “proven undeveloped reserves,” or PUDs.

“The problem with PUDs,” says Bonner, “is that you get credit on your balance sheet for them as a proven resource, but now you have to throw a lot of money at them to turn them into developed resource. What we did was to come along and offer operators the opportunity to develop those PUDs in a way that was not dilutive to equity” since royalty interest investments equate to non-repayable loans. “Even though interest rates for the last couple of years have been close to zero, royalty financing is attractive because you don’t have to pay back the principle. When operators began to see this, they quickly realized that taking our capital was very accretive to the capital they had to spend themselves.”

Through its family of funds, Brickburn has acquired royalty interests through 11 operating companies, but is bound by agreement not to mention names. However, Delphi Energy and Bellatrix Exploration have both publically acknowledged that they use royalty financing from Brickburn.

Vocal Records

Photo of the Bitumount oilsands plant, 1936. Bitumount was one of the first commercial oilsands plants.

Oilsands oral history project gets underway with the support of five key players. This article appears in the February issue of Oilsands Review 

By Peter McKenzie-Brown

Four oilsands companies – Syncrude Canada, Imperial Oil, Athabasca Oil Sands and MEG Energy – have become founding sponsors of an oral history project conducted by the Petroleum History Society (PHS). Why?

To appreciate the significance of this development, consider the story of Karl Clark. By far the most influential oilsands researcher, Clark did his important work before anyone now working in the business was born. Yet historians have easy access to useful information about him. That’s mostly because Clark lived during an era of low technology. He wrote letters and diaries and prepared scrapbooks and, with the methodical skills that made him a first-rate scientist, filed them carefully away. Since most of his work was done at the University of Alberta and the provincial government’s Alberta Research Council, his studies became public documents, now accessible through the university’s archives.

The accessibility of this work enabled Clark’s daughter to compile an authoritative and insightful book – Oil Sands Scientist: The Letters of Karl A. Clark, 1920-1949 – with relative ease. Direct, clear and intelligent, his letters contain important technical and chronological information about Clark's work. They also reveal much about his personality and character.

How many letters have you written recently? Probably very few. Because it’s faster and more secure we’re far more likely to send e-mail or use the phone than write memos and letters. In some ways technological advances are making it harder – not easier – to follow the impact of influential people. The profusion of information about us obscures areas of our intellectual and personal footprints. For those of us who believe an understanding of industrial development is possible, and necessary, this is a big loss. What's the best way to proceed?

The answer is oral history. To create balanced pictures of the growth of big industrial sectors, historians need personal recollections. The memories of those involved breathe life into the dry corporate and government documents that provide so much of the raw material of history. In this case, those being interviewed were mostly engaged with the oilsands for long periods. Their understanding of the sector has more depth than versions provided in the popular press.

The Horse’s Mouth
Oral history is a discipline that has developed over the last 60 years in lock-step with the spread of technology. As the personal and business letters that once formed core material for historians disappeared, technologies like cassette decks and video recorders proliferated and plummeted in price. This has enabled many historians to move beyond documentary research – instead, preparing contemporary history by simply asking people to tell their stories.

According to the Glenbow’s library and archives director Doug Cass, “to anyone researching and writing about history in the 20th and 21st centuries, any oral history that can be found is very important to our understanding of the past. Memory is, of course, very complex and fallible, but it just seems so obvious to use someone who was involved in an event to provide first-hand knowledge.

“Oral history is a source like any other, and the information provided needs to be cross-referenced with other materials,” he says. However, “the rich data about feelings and relationships is compelling and valuable.”

Clint Tippett – president of the Calgary-based Petroleum History Society – concurs. “If we want to understand history, there’s no better way than from the horse’s mouth. Every aspect of history is complicated – causes, effects, decision-making and repercussions. So there is no replacement for getting the true goods from a person who was actually involved.”

Mixed metaphors notwithstanding, Tippett’s comments celebrate initial funding for an ambitious oilsands history project. When Syncrude, Esso, Athabasca Oil Sands and MEG Energy agreed to fund the first phase of this oilsands oral history, they were continuing an industry tradition that began 35 years ago. PHS intends to conduct and record extensive interviews with 100 of the sector’s pioneers, then transcribe that material. The organization will donate this valuable source material to the petroleum collections of Calgary’s Glenbow Archive (part of the Glenbow Museum), which will make them accessible to media, the public and historians.

Two key supporters of this project, Eric Newell (formerly chair of Syncrude) and Bob Taylor (formerly Alberta’s assistant deputy minister for oil) described the project as providing “historians, researchers and educators with a repository of primary information from knowledgeable sources…(it) is part of a 30-year oral history effort by the Petroleum History Society (which has) already collected and archived more than 300 interviews with key figures in the evolution of the Canadian oil and gas industry” – pioneers like Jack Gallagher and Carl Nickle. Taylor said in an interview that “this effort will create a wealth of material that should be part of the industry’s educational efforts.”

According to the Glenbow’s Doug Cass, “the oral history recordings produced by the society’s previous petroleum industry oral history efforts are among the most used collections in our archives.” Especially since so many of these interviewees have passed away, these files are an irreplaceable part of the Glenbow’s extensive petroleum industry collection. “With the loss of these individuals, we lose important voices that can help historians recount the story of how this industry was created.”

A Textbook on Steam Technology
The history society’s Tippett is a strong believer in the efficacy of these personal statements. “We may think that we understand what happened in the past and why,” he says, “but we work with incomplete information and through the filters of our own experience. We may not see the bigger picture or context within which events unfolded. Records are commonly incomplete and small but critical aspects, in particular with regards to people, often fall between the cracks” when a historian is trying to re-create a piece of the past.

“Indeed,” says Tippett “seeing the powerful role that people play and the degree to which they are driven by their personalities, values and aspirations” makes those personal perspectives a critical part of understanding how events occurred. “The way people interacted with the technology of the day and how they innovated also becomes more tangible when it is heard from an actual participant. I’d much rather listen to a train engineer describe how he handled a steam engine than read a textbook on steam technology.”

The formal PHS proposal describes the project as “a core educational project for the oilsands industry. It will honour those who helped create and shape the industry. By uncovering stories of challenge and innovation, it will contribute to a deeper understanding of how the industry developed and how it functions. It will serve as an important resource for historians, researchers and educators.”

Tippett adds that “the opportunity to contribute to oral history can often be seen as recognition of an individual’s accomplishments. Unfortunately,” he says, “the other major place where a person’s life is spelt out is in an obituary – and by then one isn’t in a position to either appreciate or correct it!”

Selling Canada?

Image via Wikipedia

As Asian efforts to secure Canadian energy supplies intensify, can nationalist forces be silent much longer? This article appears in the November issue of Oilweek.

 By Peter McKenzie-Brown
In Canada, economic nationalism fell into a slumber twenty years ago. Is it likely to begin stirring again? According to Dr. Robert Mansell of the University of Calgary, “I could imagine a new period of nationalism. After all, public attitudes tend to go through regular cycles.”

An economist, Mansell is academic director of the university’s School of Public Policy and the founding director of the Institute for Sustainable Energy, Environment and Economy. Although he recognizes the possibility, Mansell puts a lot of caveats on the prospect of a nationalistic surge. “We’re still in a period with a high level of globalization, so I would be surprised if we said ‘No more foreign ownership.’ The markets are too big now (for Canada) to finance a lot of (the petroleum industry’s) activities, so you have to go into international markets for large amounts of money. We don’t have a lot of fiscal surpluses to finance many of these projects. This limits our options.”

However, he notes that political conflict with China, say, could lead to public concern about Chinese investments in Canada’s oil industry. In the United States, an outright political row wasn’t even required five years ago. That’s when a public outcry put an end to an $18.5 billion hostile bid by state-controlled China National Offshore Oil Corporation for UNOCAL, an American major. Chevron-Texaco acquired Unocal later that year.

Asian Investments
This has become an issue of interest because the sources of overseas funding for North America’s energy industry are undergoing a fundamental shift. “The axis of investment capital is rotating from a north-south flow over the 49th parallel to an east-west current across the longitude of the Pacific Ocean,” says author and analyst Peter Tertzakian of ARC Financial. “A recent swell of Asian money coming into the Canadian oil patch represents one of the biggest megatrends in the business.” Tertzakian does not mention a sub-feature of this shift of Asian funds: much of the money is coming from national oil companies
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By no means is this trend limited to Canada. Increasingly, developing countries with financial reserves are investing those funds in countries with large oil and gas resources. “Relative growth in energy demand has shifted quite dramatically toward Asia,” says Robert Mansell. “As demand shifts, one would expect (Asian) interest to shift to Alberta, especially since the number of countries which are attractive for petroleum investment is shrinking. There has been an expansion of interest in national oil companies for a variety of reasons, one of which is to achieve security of supply. Energy security (in Asia) is an even bigger issue than it is North America.”

Peter Tertzakian puts the issue starkly. “Since world war two there has been a symbiotic, bi-directional flow of capital and energy resources between Canada and the US. Now a new dynamic is emerging…. Growth economies like China look very similar to the United States in the 1950s and 60s – capital rich and hungry for energy.” In a series of charts and tables, he sums up the shift in funding.

“Big foreign companies like India’s Reliance Industries, China National Petroleum Corporation and Mitsui have been teaming up with domestic independents that hold large land positions in shale gas plays, mostly in the US” he says. “Under twelve joint venture agreements these foreign entities have committed $17.2 billion of funding to obtain carried interest in new wells being drilled by independent natural gas producers like Chesapeake, EnCana, Pioneer, Atlas and Carrizo.” The charts illustrate the recent flow of money from overseas economic powers into North America’s shale gas business.

Within Canada, some funds have flowed to shale gas, but more has gone to the oil sands. The table of foreign investments in the last 12 months illustrates that Asian investment in Canada has focused more on the oil sands more than shale gas. The table does not include another notable 2009 investment: Sinopec’s acquisition of Addax Petroleum for $8.27 billion.

Of the new Asian partners, four are national oil companies headquartered in China or Korea. However, the acquisition of Harvest Energy by an agency of the Korean government deserves special note. Harvest was an intermediate-sized Canadian energy trust. From a standing start, in ten years president and CEO John Zahary created an entity he was able to sell for more than $4 billion. That’s a lot of money, but relatively small potatoes in the context of Canada’s hundreds of billions of dollars’ worth of total oil and gas assets. Outside the industry, people paid scant attention
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Harvesting Energy Companies
Of course, Korea isn’t China, and Harvest Energy isn’t Unocal. Even so, the deal stoked concern that, after watching parts of the oil patch go to other state-owned companies, the Canadian government will eventually step in to block transactions.

According to John Zahary, though, the South Korean company’s commitment to boost spending is the only thing that’s relevant. “We see this as an opportunity for increased jobs in the country, increased capital investment in (Harvest’s) assets,” he said. “KNOC (the Korean National Oil Company) now owns 100% of the equity in the company – that’s true. But I believe that even under the new ownership Harvest is still a Canadian company. The management is here, the employees are here, the resources are here and the resource owner is here. We now have a board of directors of eight people: five are Canadians and three are Korean nationals.” To make the deal happen, Zahary negotiated a 47% premium to the company’s then-current price. He now expects to see Harvest continue to grow.

“Why did they want to invest here?” he asks rhetorically. “We have a resource that is relatively underdeveloped, a people base and a technology base. We have relatively stable fiscal and regulatory systems and a history of openness to foreign investment, and that differentiates us from other countries. Canada is an excellent place to invest. I look at foreign investment (in this country as part of the) maturing of the nation.” The University of Calgary’s Mansell agrees. “….In this global environment even companies that you think are purely Canadian are likely to have most shares held outside the country. The key issue is their local presence. The control is local. There are a lot of regulations in Alberta,” for example. “Whether foreign or local, companies have to follow the rules that we make. They can’t avoid them.”

Another rhetorical question: Why did Zahary want to sell Harvest Energy Trust? Partly because Ottawa’s Halloween Massacre in 2007 made energy trusts so much less attractive. Prior to the sale, Harvest’s unit price had cratered since its pre-massacre high – down about 80%. This, of course, illustrates government’s power.

The case for economic nationalism
Perhaps the most unlikely supporter of government regulation is Richard Haskayne. Known universally within business circles as Dick, he has served as the chair of six large Canadian companies: Interhome Energy Inc., TransCanada Corporation, Fording Inc., NOVA Corporation, TransAlta Corporation and MacMillan Bloedel.

“My philosophy is that Canada needs regulation to protect strategic sectors,” he says. “This is not a new hobby horse for me. A few years ago I wrote an article promoting the idea behind Canada’s Bank Act, and I got a lot of flak about it. But recent events have demonstrated that it worked really well for Canada. The reason (I support that kind of government control) is that banking is so strategic for Canada.”

He supports government regulation of energy and mining ownership because they, too, are strategic. “That’s our strength. Of the ten top stocks in Canada there are four banks, three energy companies and three mining companies. Seventy percent of the stocks on the TSX are in those industries.”

“I’m not opposed to foreign ownership as such,” he says “– only when someone takes over 100% of a classic Canadian company like Potash Corp. Look at Vancouver without McMillan Bloedel. Look at the Windsor waterfront now that Hiram Walker is no longer there. Head offices are critical to the operation of Canada and to our decision-making.”

Haskayne sees Canada’s Bank Act as a good model for bank regulation. The act prevents any individual from owning more than 10% of the shares of top tier banks, and says the aggregate holdings of non-residents and their associates may not exceed 25%. In addition, their head offices must stay in Canada and their boards must consist mostly of Canadians. Deeply concerned about what he calls the “hollowing out” of head offices from Canada, he’d like to see similar provisions applied to Canada’s biggest energy and mining companies. “It’s the concentration of shares that’s the critical part.”

An irony of Haskayne’s position is that as chairman he sold Nova’s controlling interest in Husky to Li Ka-shing. “I admit I sold that company to Hong Kong interests,” he says, “but in those days Husky was in terrible shape. It was almost broke. The banks were on their tail. We tried to sell it. I went to David O’Brien at PanCanadian and tried to get him to buy. I said, ‘It’s a hell of a deal for you. It’s got so much heavy oil and it’s got refining interests….’ David turned to me and said, ‘Haskayne, get out of my office. I don’t want that sick dog [Husky] in my kennel.’ You can’t get much more of a refusal than that. So we sold our share (to Hong Kong interests) for $375 million. Well, today that interest is probably worth $15 billion, so they made a hell of a deal. I apologise for that, in a way. However, there wasn’t much we could do. Li Ka-shing’s group was holding the golden shares, and that made it hard to sell” the company to anyone else. Husky is now one of Canada’s biggest energy companies.

Asia’s energy security
Canada’s last round of economic nationalism began in the 1970s, when nationalization of the petroleum sector within OPEC inspired Canadian governments to set up their own oil companies. The idea was to Canadianize a vital resource sector. The last vestiges of those experiments disappeared a year ago, when Suncor absorbed Petro-Canada.

Are Asia’s efforts to find energy security with the aid of national oil companies (NOCs) also doomed to fail? “For the foreseeable future,” says the University of Calgary’s Robert Mansell, “Asian countries are not likely to be getting any Canadian product directly. But they can still do swaps and so on, taking oil that would otherwise have gone to the United States, diverting production. Markets enable you to move that oil around. Different market arrangements will allow you to increase security.”

He cautions against thinking of all NOCs as being the same, however. “There are quite different NOCs. For example, Statoil is really not much different from what we think of as a privately owned company. Some of the other companies are a different animal, though – they are just an extension of the state. There are quite different variations when you start looking at national oil companies.”

Although he sees economic nationalism as a possibility, Mansell is sceptical about its staying power. “A serious political conflict between, say, China and Canada could create a public reaction, and it’s quite easy to imagine” a public outcry against Chinese ownership of Canadian resources. “However, in the long run it seems to me that most Canadians appreciate that we as a country benefit from global investment.”

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If Nobody Hears a Blowout, Did it Really Happen?

Canada’s worst-ever blowout wasn’t a celebrity, and despite the passage of more than a decade the regulator has never formally investigated the event. Is that a good thing?

This article appears in the July issue of Oilweek

By Peter McKenzie-Brown

Klua d-27-J blew out near Fort Nelson BC. No neighbours were under threat, and the blowout took place in the sticks as most Canadians were getting ready for Christmas. No one was injured and, except for an incinerated rig, there was no damage to property. The media didn’t get wind of the disaster, so Klua was relegated to the world of “incidents.”

The blowout began on December 6, 1999 and took 12 days to shut in. But what an incident it was! Chairman Mike Miller of Safety Boss was part of a team of petroleum industry experts who prepared an important paper on Klua for a conference in Texas two years later. “Eyewitnesses reported that the drill string was lowered the last fraction of a meter with no resistance,” the paper says, “as if the bit had entered an underground cavern….” Then all hell broke loose.

According to Miller, at its peak the well spewed an estimated 250 million cubic feet of natural gas per day plus 5,000 barrels of condensate and 45,000 barrels of salt water. After ten days, crews ignited the well, which was flowing mildly sour gas. After pulling the incinerated substructure of the rig from the well, the hole was shut in and a control BOP installed.

When Oilweek recently contacted BC’s Oil and Gas Commission (OGC) for the formal report on this blowout, there was none. The Ministry of Environment would lead clean-up efforts, but otherwise the file is still open.

Team of Rivals

As executive director of the Small Explorers and Producers Association of Canada, Gary Leach leads Canada's "Silicon Valley of oil"

This article appears in the February 2010 issue of Oilweek.

By Peter McKenzie-Brown

A year ago, Stan Odut was chairman of the Small Explorers and Producers Association of Canada (SEPAC), and he was deeply worried about the industry’s immediate future. “The sources of capital for the junior sector are equity, debt and cash flow,” he said, “but many companies are already mired in debt and credit lines are being pulled. You can’t get additional debt coverage. You can’t raise any equity because there is no reason for investors to put money into the energy business right now (because of collapsing commodity prices). And governments (provincially in particular) have strangled cash flow. So help me with the equation: you’ve got to get one of those factors to change to get the business going again.”

In the last year, what has changed? I put the question to Gary Leach, SEPAC’s executive director. He describes a cautious sense of optimism within the junior sector of Canada’s petroleum industry. There’s been a strong recovery in oil prices, for example, although gas prices are still languishing. “In recent months equity markets have been more supportive of the industry,” he adds, although they have been “selective”. They are targeting companies with “strong management, in certain commodity niches. But there is no tide that is lifting all boats.” Bank credit is still a problem for some companies; many are carrying a lot of debt, and lower commodity prices have reduced the value of their assets in the ground. Technically, this is known as a double-whammy.

On the positive side, “Banks have tried to be nimble and flexible. They don’t want to cause a lot of financial wreckage in the junior and midcap sector. A lot of the equity raised in recent months has been used to reduce debt, so things are improving.” However, he cautions, “If we don’t see a sustained rebound in gas prices in 2010, that may change.”

The Gas Story
Gary Leach describes himself as a “pure prairie product”. He was born in Manitoba, raised in Alberta and received post-secondary education (including a law degree) at the University of Saskatchewan. He spent much of his strictly legal career putting together international joint ventures, petroleum production sharing agreements, and international financing loans with multilateral institutions such as the World Bank and the European Bank for Reconstruction and Development.

He joined Calgary-based Canadian Fracmaster in 1995 and stayed with the business after it was acquired by BJ Services Company, the Houston-based petroleum equipment and services giant. His background in down-hole completions is a notable asset for a spokesman in an industry being transformed by horizontal drilling and new fraccing technologies. Soft-spoken and articulate, Leach joined SEPAC – the trade association for 350 small oil companies – in 2006.

We began our discussion with the natural gas story. At time of writing, gas prices are sitting well below their ten-year average. Where are those prices headed? “I think right now there’s possibly a larger gap in opinions about where gas prices are going than any time I can remember,” Leach says. “There are people who say the potential international demand (for gas) has barely been touched, so prices should go up. Others talk about the huge international supply potential, and they see things the other way.” Perhaps remembering the adage that predictions are especially perilous when they pertain to the future, he says “We are never going to get out of these swings in gas prices. I think there are going to continue to be big swings in the gas market. I don’t think anyone can accurately forecast gas prices beyond a couple of quarters.”

“For companies carrying a lot of gas assets on their balance sheets, it’s not a great time to be selling. “There are going to be a lot of assets put on the market. A lot of big companies” – he mentions Talisman, EnCana and Suncor – “are talking about moving conventional gas reserves off their balance sheets. The lowest cost gas resources are the ones they are going to pursue, and those resources are now shale gas resources.”

Since gas-price volatility is a fact of life, he says, “The low-cost suppliers are the ones that are going to do best. Companies have to learn how to drive down their costs.” For the junior sector, which has a lot of conventional gas on the books, the outlook is particularly uncertain. “The leading shale gas resource in western Canada is in a place that’s so remote and so expensive that mostly big players can participate. However, as the technologies and the infrastructure are developed, the smaller players will get in.”

Behind the Curve
When you ask Leach about Alberta’s place in western Canada’s industry, he is oddly ambivalent. For example, on the matter of shale gas he says, “If we were further along the curve in Alberta in developing shale gas resources, the smaller players would be developing them. But Alberta’s industry is behind the curve.”

He notes that both British Columbia and Saskatchewan long ago introduced important incentives for the industry, but that those policy environments didn’t spur high levels of petroleum sector growth until the technological environment changed in recent years. For example, Saskatchewan’s “Bakken field has been known for years. We used to just drill right through it. However, it is only recent that the technologies of horizontal well completions and multistage fracturing” – the technologies that led to the shale gas revolution – “made that reservoir viable.”

Alberta, of course, is quite different from either of those provinces. “The (Western Canada Sedimentary) Basin covers the province from north to south. We have every conceivable hydrocarbon opportunity here. There’s a lot of excitement about using those technologies to improve production from formations in Alberta that are well past their glory days – the Viking formation, the Cardium formation. A lot of companies are looking at targeting oil in these formations, but using horizontal wells and multistage fractures.” Leach thinks the industry will soon successfully use these methods to increase oil recovery in Alberta.

What is SEPAC’s single biggest challenge? Here his message is particularly striking. “We have to help policy makers and politicians understand what a tremendously exciting, dynamic, vibrant group of junior and mid-cap companies we have in Canada. Almost half the world’s publically traded oil companies are here in Calgary. It’s a remarkable statistic. It’s the closest thing to a Silicon Valley type business culture and industry cluster we in Canada have ever developed. It’s emerged on its own without government help. But over the years, we have had all these companies competing with each other. Hundreds and hundreds of companies are competing with each other for land, for resources, for capital. They have a tremendous publically accessible database that puts small companies on an equal footing with big players. It’s the most unique oil industry in the world, and Canada’s most successful business story. We need policy-makers to understand that story, so they don’t see the industry as just eight or ten companies. Let’s see the big picture, and not do things to harm it. This industry is amazing. We don’t want to lose it. We want to nurture it. It’s a great incubator of new ideas.”

Leach sees the Alberta government’s recent adjustments to the royalty changes of two years ago as a SEPAC success. “Both times (Premier) Stelmach came out with revisions to the royalty regime, he specifically mentioned that he wanted to help Alberta’s junior petroleum sector. The Alberta incentives brought additional cash flow, reduced costs, drew some investment into Alberta that would. They helped, but they were not the complete answer. They couldn’t help everybody.”

SEPAC is now working with other industry associations, the financial sector and others in developing a study of investment competitiveness within the province, which will be complete in the New Year. The idea is to answer the question, “Compared to other investment places, how does Alberta rate?” The provincial government will then have to take all that information and decide on new policies. We think if the province can set itself up as one of the world’s best places to invest, its future will be bright.” Citing a report from a large bank, he points out that about 60 per cent of the world’s investible oil resources are here in Alberta. Big international oil companies have been boxed into smaller and smaller bits of the world. This is one of the few places in the world where companies can book meaningful reserves additions.”

Moving Ahead
I’m always interested in the responses of senior people in the patch to the issue of peak oil, so I put the question to Gary Leach. His response is forceful and direct. “I think we’re near peak cheap oil. I think we’re near peak easily accessible oil. But the amount of oil in the world is enormous. The biggest problem to developing oil has to do with policy restrictions – off-limits restrictions on resource development. The US has huge oil shale resources, for example, but they are politically inaccessible.” Working with their client national oil companies, oil-rich countries have put resource development off limits to private sector oil companies. He mentions Venezuela’s Orinoco ultra heavy oil belt, Alberta’s oilsands, the vast heavy oil deposits in Russia, then cites the old gag that the Stone Age didn’t end because we ran out of stones.

He’s now just warming up. “The petroleum age won’t end because we run out of petroleum. Western European countries are consuming less oil than they did 30 years ago, and the United States is consuming less than it did in 2007. The petroleum age may end in a gentle decline because some of the advanced countries begin to move away from (oil). I don’t think it will end with apocalyptic change. Price signals will put a limit on demand.”

I mention the often-cited rapid demand growth in China and India among developing countries and the rapid growth in OPEC countries like Venezuela, where consumer prices are greatly subsidized. “Rapidly growing countries like India and China are still poor countries,” he counters. “They can live with a price around today’s price (US$77 per barrel) but they cannot afford oil at $150-$200 per barrel. (If prices rise to those levels) there will have to be some kind of market response. Before 500 million Chinese own a car, they will be driving something that doesn’t rely on oil: Maybe electricity-fuelled vehicles charged from nuclear reactors.” Whatever those vehicles are, Leach has no doubt “there are going to be other factors on the demand side, the technology side, that will temper those straight-line graphs that say oil demand will outstrip oil supply and prices will skyrocket.”

Of course, a basic principle of free-market economics is that supply and demand must always be in balance. Neither does a world with global economic growth constrained by energy shortages sound reassuring. Indeed, the situation he is describing seems compatible with mainstream peak oil theory, so I wonder whether his arguments against worldwide economic destabilization have settled the issue. All the same, I have thoroughly enjoyed the discussion. We shift gears, moving to lighter topics.

Has he read any good books lately? Yes, he says. He reads a lot, and is now reading Team of Rivals: The Political Genius of Abraham Lincoln by Pulitzer Prize-winning historian Doris Kearns Goodwin. This thick book describes Abraham Lincoln’s leadership skills by focusing on his war cabinet, which included three of the political rivals he beat in the 1859 presidential campaign. According to Leach, “it was amazing how he turned these diverse people into a team during the most cataclysmic period of American history.”

For a guy with responsibility for managing SEPAC’s affairs and representing its views to government, the news media and the public, political genius may be just what the doctor ordered. Bear in mind that “nearly half of the world’s public oil companies are here in Calgary.” Within the modern petroleum age, those hundreds of companies have become a team of rivals for the global oil industry to reckon with.

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Melting Away

Like the Wicked Witch of the West, Petro-Canada has met its demise, and few are around to mourn

An obituary of the company's rise and fall, this article appears in the November 2009 issue of Oilweek

By Peter McKenzie-Brown
About 20 years ago I wrote a speech for Bill Hopper, who was then chairman and CEO of Petro-Canada. He had just taken on a one-year term as chair of the Canadian Petroleum Association (the CPA; now CAPP), which I then worked for.

The process was strange beyond imagination. Instead of simply going to his office to find out what he wanted to say, I learned at the last minute that I was to go with an entourage: CPA president Ian Smyth; vice president Hans Maciej; and my boss, Norm Elliott. Among the other members of the CPA’s board of governors, Hopper alone demanded that amount of attention. The interview took place in Hopper’s palatial offices in Petro-Canada Centre. Not surprisingly, the interview was a flop – a waste of time for all concerned.

This vignette is a reasonable caricature of the early years for the most controversial petroleum company in Canadian history. Especially under Hopper’s leadership, Petro-Canada set the national standard for self-importance, arrogance and underperformance. Although the worst times are long behind us, the company’s epitaph cannot be written without reference to those bad old days. In some ways, they were with the company to the end.

For example, if you believe that markets are inherently rational, try graphing the company’s share price to those of its peers. Every large Canadian oil company has done better than the People’s Oil Company, as it was once unaffectionately known.

When the crash came a year ago, Petro-Canada collapsed more deeply than most. This left it vulnerable to regime change, which quickly came in the form of a takeover encouraged by complaints from a large shareholder, The Ontario Teachers’ Pension Plan, which wanted to increase shareholder value.

The company and oilsands pioneer Suncor Energy soon announced a friendly merger, consummated on August 1st. The transaction created Canada’s largest oil and gas producer, with a market value of more than $50 billion. By the time the companies merged, Petro-Canada had nearly doubled in value from its 52-week share-price bottom, set last November. Clearly, the rational markets felt that with the takeover a better manager was in charge of its assets.

Few people will miss Petro-Canada the oil company. Its corporate history is a bit like the story line for “The Incredible Shrinking Man” – the 1957 movie in which protagonist Scott Carey, who had been contaminated by a radioactive cloud and pesticide, shrank slowly until he was reduced to living in a dollhouse.

In real, inflation-adjusted terms, Petro-Canada was the incredible shrinking company. Notwithstanding infusions of additional cash through equity sales, in real terms Petro-Canada’s market capitalization at the time of its merger with Suncor was less than the federal government’s original investment. In nominal terms (unadjusted for inflation), it lost nearly half the money its founding shareholder, the government of Canada, poured into its maw. And as the shackles of government ownership were slowly removed, it lost a combination of hard cash and opportunity for its second round of shareholders, a long-suffering gaggle of private investors.

The Background
Petro-Canada was founded as a Crown Corporation in 1975 by an act of Parliament and started operations the following year. The company was created upon noble ideals. In a period of intense energy insecurity, the left wing of Ottawa’s political establishment – the minority Liberals supported by the NDP as kingmakers – proclaimed the need for a national presence that would go boldly into the Canadian frontiers, which supposedly were being overlooked by the international players who then dominated Canada’s oil and gas sector. As importantly, the company would serve as a “window on the industry” through which policymakers could peer through clear glass. At start-up, the federal government transferred its 45 percent stake in Panarctic Oils and its 12 percent interest in Syncrude to the newly established company.

While the political issue of the day was ownership of Canadian resources – especially oil – Petro-Canada quickly went into acquisition mode by buying integrated companies rather than pure E and P operations. The idea was to wave the Canadian flag to consumers (aka voters) across the country. Outside Alberta, the political decision to create a national oil company was popular, and the company was given $1.5 billion in start-up money and easy access to new sources of capital.

During its first ten years, Petro-Canada purchased Atlantic Richfield Canada; Pacific Petroleums; Petrofina; most of BP’s Canadian refineries and service stations; and Gulf Canada’s retail and refining operations. The irony was not lost on the oil and gas sector: there were no shortages of refining capacity or retail operations, yet the company paid premium prices for assets which brought considerable liabilities with them. Other companies – BP and Gulf, for example – were selling them partly because the 1980s were a period of consolidation for retailing assets. The era of having a gas station on every corner was morphing into the present era of service stations only in heavy-traffic locations. And with service station closures came significant environmental liabilities, since product leakage from underground storage tanks was endemic across the country. That collective mess had to be cleaned up, and doing so was expensive.

The company did become an important purveyor of gasoline and motor oil at the service station, and one of its few unadorned successes was to develop the trusted and respected Petro-Canada brand of petroleum products. The single biggest boost to that brand came when the company sponsored the 1988 Olympic torch relay – a sponsorship that Ed Lakusta, at the time the company’s president, called the finest thing his company had ever done. Even sceptics began to believe Petro-Canada had a place in the oilpatch, and its gasoline sales soared.

Because of its many acquisitions in Western Canada, the company became one of the largest players in western Canada’s traditional oil fields, in the oilsands and in the east coast offshore. Did this lead to the discovery or development of more oil in the west? Certainly not. In 1927 John Bertram, an American Oil Company operative investigating the energy scene in Alberta, wrote a succinct description of what geologists now call the method of multiple working hypotheses.

“We know from our own experience,” he said, “that the geologists and also the officials of a company that operates in one area for a long time, tend to think along the same lines and to accept the same theories of oil occurrence. When other groups of men invade the same territory, the newcomers work with different methods, use different theories and drill structures the others condemned.” Through its acquisition of numerous companies on the government’s dime, Petro-Canada actually slowed oil development in western Canada – or so says the tried-and-true multiple working hypothesis method.

With the changing of the political winds, governments gradually began privatizing the company. Begun in 1991 under Brian Mulroney (who had ordered the company to act like a profit-driven company when he was first elected), this process was completed in 2004 by the Liberal government of Paul Martin, which sold more than 49 million shares for about $3 billion, bringing the government’s total recovery from its investment to $5.7 billion.

Petro-Canada acquired valuable offshore interests during the Hopper era. These included Hibernia, which is Canada’s most prolific ever oilfield. The company was the operator behind the Terra Nova discovery, which is now Canada’s second-largest offshore oilfield. Also in the offshore, Petro-Canada was the operator of the White Rose oilfield.

But the company did not truly begin operating like a profit-driven private company until 1993, when Hopper was replaced by Jim Stanford. During Stanford’s stewardship, the company made efforts to grow in important ways. Its east coast assets went on production, and the company went international, acquiring and developing in the North Sea, Libya, Syria and Trinidad and Tobago. At the end, those offshore and international operations were its biggest sources of income. After decades of rationalization, its refining and marketing operations – the second-largest in Canada – became a stable and reliable source of cash flow.

For investors, though, the bottom line is the bottom line, and Petro-Canada shares never performed close to the level you might expect from a company with its assets, image and cash flow. An important factor was the Petro-Canada Public Participation Act – Mulroney-era legislation dictating that no single entity can hold more than 20 percent of the company. This made the likelihood of a takeover remote, greatly weighing on Petro-Canada’s stock price. Call it the last curse of public ownership.

The Legacy and the Merger
The storied tale of Petro-Canada is an object lesson in the failures of government interference in the economy. Journalist Peter Foster’s 1992 book, Self Serve: How Petro-Canada Pumped Canadians Dry, won that year’s National Business Book Award and was a factor in unseating Bill Hopper.

At the end of a chilling chronology of hubris and mismanagement during the company’s first 15 years of operations Foster writes, “It can fairly be claimed that Canada is at least $10 billion deeper in debt because of Petrocan, a debt for which there is no corresponding asset. The money has gone….But although the original investment has been largely destroyed, the debt lives with us. We are like bad gamblers in debt to loan sharks, our obligations growing geometrically. The annual interest cost of the Petrocan-associated debt is about $1 billion, and all the income tax from 100,000 average Canadian families will have to go to pay that annual charge.”

According to another, highly hypothetical version of this analysis, Canada would be debt-free if, instead of spending $10 billion on petroleum assets during the high-interest-rate 70s and 80s, the federal government had instead reduced its debt by that amount. More to the point, the creation of Petro-Canada generated few if any useful results. To the extent the company contributed to the policies of the hated National Energy Program, it caused unnecessary and inestimable damage to the country and its oil industry.

Petro-Canada danced into the arms of Suncor with a tremendously deflated cash flow stream and dramatically lower profits after 2008’s oil-pricing bubble. During the company’s last quarter as an independent operator, its net earnings decreased by 95 percent to $77 million, compared with $1.5 billion a year earlier. The company cited the deadly combination of lower commodity prices and volumes plus higher costs and expenses. The recession-related collapse of oil and gas prices was clearly the most important source of this financial disaster.

Disaster that may have been, but for Suncor, with its high-cost oilsands production, the impact was far worse. In the second quarter the company suffered a net loss of $51 million, compared to net earnings of $829 million a year earlier. The financially weaker of the two companies – Suncor – was the acquisitor because of the strength of its management. The company, which at time of writing is trading at about $35 per share, started life in 1993 at about a buck. That’s serious growth – especially compared to Petro-Canada’s original $13 issue price, which had grown to only $41 at the time of the merger. Petro-Canada’s shareholders were a long-suffering breed.

Petro-Canada’s Jim Stanford and Suncor CEO Rick George first discussed merging in 1999, but the negotiations went nowhere. In the crisis atmosphere of the latest recession, though, the players were more motivated to get results. The announcement came less than two months after Petro-Canada’s big shareholder, The Ontario Teachers’ Pension Plan, began agitating for better shareholder value.

At a stroke, the merger between the two companies created Canada’s largest oil company, and the fifth largest in North America. Post-merger, Suncor controls 26.5 billion barrels of oil; the largest suite of oil-sands holdings in the world; daily production of 680 million barrels of oil equivalent; and an international reach that embraces the North Sea, Libya, Syria, and Trinidad and Tobago. The joint Canadian operations of the merged company cover the energy sector, from the Arctic to the east coast offshore, shale gas, refineries and a vast chain of retail outlets. The gas stations and other marketing operations are the only visible remains of what was once Canada’s national energy company.

What is the effect on the new, combined company? The most immediate impact is greater operating efficiency. The designers of the merger – Rick George and Petro-Canada’s Ron Brenneman, Stanford’s successor – forecast that joining forces will save $300 million a year in operating costs and about $1 billion in annual capital spending by eliminating duplication of pipelines, power and water infrastructure for oil-sands operations. In addition, Petro-Canada’s light oil assets are far less vulnerable to another oil price collapse, and will thus stabilize the combined company’s cash flow stream. Also, Petro-Canada brought with it a suite of non-core overseas assets that the company can sell to finance its core oilsands developments, like the Firebag SAGD expansion that went on hold last year.

Professor of economics and academic director of the University of Calgary’s School of Policy Studies Robert Mansell says the deal makes sense in many ways. “In a world with great uncertainty, where we don’t know what is going to happen with climate change policy, it gives you an ability to mix and blend and do all kinds of things that you wouldn’t be able to do if you were just oil sands. Long term, if you can maintain a very efficient, integrated operation that is better than a very narrow, specialized operation. And when you are talking about billion-dollar projects, being a large company is a lot better than being a small company. I see that as being an excellent strength that they can build on.”

If the new company has an Achilles heel, perhaps it is a relic of the Petro-Canada years. As a result of the merger, Suncor is now subject to the Petro-Canada Public Participation Act, which weighed so heavily on Petro-Canada for so many years. That law, which restricts ownership in the company by any single entity to 20 percent, will protect Suncor from predation during the period of consolidation. Longer term, though, will the last curse of public ownership weigh on Suncor’s shares, as it once did on Petro-Canada’s?

From North to South: How Norman Wells led to Leduc

I delivered this presentation to The International Commission on the History of Geological Sciences, August 11, 2009

Synopsis: In Canada’s early years, important hydrocarbon discoveries occurred almost independently of settlement. In the frontiers, of course, that pattern continues. The relationship between Norman Wells and Alberta’s post-war discovery at Leduc is one example of a pattern that turns on its head the American model of petroleum development. Remote exploration has always played a critical role in our industry’s development.

It would be easy to think of Canada’s petroleum industry as one that began in the south, grew wealthy, then began exploring and developing more remote lands. That is indeed a realistic caricature of the US industry, but in Canada the story was different. The most important oil discovery prior to Leduc actually took place just south of the Arctic Circle. In a drama worthy of the great white north, that discovery led directly to the creation of Canada’s modern petroleum industry.

By Peter McKenzie-Brown
Before I address the major topic of my presentation today, I would like to suggest an idea about the development of Canada’s petroleum industry compared to that in the United States. Simply put, the patterns of petroleum industry development in the two countries paralleled their respective patterns of settlement.

As you know, the US takes up the best temperate lands along the eastern seaboard, and there are no major barriers to settlement between New York and San Francisco. The Cordillera is a problem, but settlement in the far west was still not seriously hindered – especially after the construction of the transcontinental railways. That pattern exactly reflects the development of the US petroleum industry. In the US there are many sedimentary basins – smallish, but regularly spaced across the country. Once Colonel Drake drilled his historic well, the American petroleum industry developed with patterns of settlement.

Canada has quite a different geography. Settlement was difficult in this country because of the predominance of the Canadian Shield, which provided barriers in many ways. Trapped between the Shield and the Cordillera, the Western Canada sedimentary basin is far bigger than the many on-shore basins in the US. Because of the Shield, it is well separated from the small basins in eastern and central Canada. The Shield and our northern latitudes created what I call the coureurs du bois model of how the Canadian industry developed.

In case you don’t know the expression, coureurs du bois were fur traders who earned their livelihoods with the aid of canoe transport along our mostly northward-flowing rivers. They played a big role in the creation of Canada. For example, from remote northern locations they brought information about resource potential to our political and commercial centres.

Partly because of their efforts, our earliest hydrocarbons were found in outposts of settlement. Consider our Oil Springs discovery, for example, which was contemporaneous with Colonel Drake’s 1859 well. Based on investigation into the well-known gum beds near Black Creek, the Oil Springs discovery took place on the north shore of Lake Erie – in an area without roads, but along the transportation and trading system afforded by the Great Lakes.

Alberta’s first recorded natural gas find came in 1883 from a well at CPR siding No. 8 at Langevin, near Medicine Hat. This well was one of a series drilled at scattered points along the railway to get water for the Canadian Pacific Railway’s steam-driven locomotives. The unexpected gas flow caught fire and destroyed the drilling rig. The discovery took place as we built our first transcontinental railway – itself an effort to settle our empty prairies before the Americans did the job for us.

The Athabasca oil sands were already well known – in fact, the first recorded mention of Canada’s bitumen deposits goes back to a Hudson’s Bay Company record of June 12, 1719. Hoping to find light oil beneath the sands, in the late 19th century Ottawa undertook a drilling program to help define the region’s resources. Using a rig taken north by river, in 1893 contractor A.W. Fraser began drilling for liquid oil at Athabasca, where the oil sands had been known for centuries. In 1897 he moved the rig to Pelican Rapids, also in northern Alberta. There it struck natural gas at 250 metres. But the well blew wild, flowing huge volumes of gas for 21 years. It was not until 1918 that a crew succeeded in killing the well.

These few examples illustrate my point. Quite unlike the situation in the US, Canada’s early hydrocarbon exploration took place along transportation corridors rather than in settled areas. The country had been well explored during the fur trade era, but settlements were still few and far apart. That pattern is in evidence in the case of Norman Wells, to which I now turn my attention.

Ask any of Canada’s exploration professionals when Western Canada’s oil industry began, and you will get one of two answers. The first is the Dingman #1 discovery, which began disgorging wet gas at Turner Valley in 1914. The second is Imperial’s 1947 oil discovery at Leduc. The more thoughtful industrial historian would probably say Dingman was the critical event for the industry’s early years, while the modern era began at Leduc.

I want to suggest that another event was equally pivotal. The year was 1914. The occasion was an expedition down the Mackenzie River by a British geologist, Dr. T.O. Bosworth. There are direct links between that trip and the modern industry’s birth.

The Bosworth Expedition: Two Calgary businessmen, F.C. Lowes and J.K. Cornwall, commissioned Bosworth’s journey. They wanted to investigate the petroleum potential of northern Alberta and beyond, and to stake the most promising claims. Bosworth did not disappoint. His confidence that the north was highly prospective is apparent on almost every page of his 69-page report.

Bosworth’s own words suggest how ambitious the expedition was. “The undertaking was planned in March 1914,” he says. “In April I consulted with the officers of the Government Geological Survey and other Departments in Ottawa and gathered from them all available information; maps and literature bearing on the subject.

“At the beginning of May, I journeyed from London to Canada accompanied by three assistant geologists and surveyors, and on May 19th, the expedition set out from Edmonton to travel northwards in the Guidance of the Northern Trading Company. We returned to Edmonton September 24th.”

During that period, the Bosworth expedition covered huge distances. And according to his report, there were excellent exploration prospects in three general regions: “The Mackenzie River between Old Fort Good Hope and Fort Norman; the Tar Springs District on the Great Slave Lake; and in the Tar Sand District on the Athabasca River.”

His report offered concise, well-written geological descriptions of rocks, formations and structures. It also included chemical reports on both rocks and oil from the many seepages in the area. Some of his greatest praise came from investigations north of Norman Wells, areas which to this day have not yielded a major oil discovery. “Near Old Fort Good Hope (lat. 67 30’) in the banks of a tributary stream, the shales are well exposed ... from the fossils it is evident that the shales are of Upper Paleozoic Age and probably belong to the Upper Devonian,” he said. “This remarkable series of Bituminous Shales and Limestones, of such thickness and of such richness contains the material from which a vast amount of petroleum might be generated and might pass into an overlying porous rock. It is admirable as an oil generating formation.”

In a discussion of the evidence of good reservoir rock, Bosworth points to a nearby occurrence of “gray clay shales and shaley sandstone,” and to another of “greenish shaley sandstone containing occasional fossils – corals, chenetes and rhynconella.”

Both of the reservoir rocks Bosworth speculates upon lie above the Devonian shales. He was looking specifically for “overlying porous rock” to form the reservoir. It does not seem to have occurred to him that reefs within the shales could have served as reservoirs, even though he specifically noted the presence of Devonian corals.

Before I turn to the outcome of this expedition, which was quite important, I would like to share with you the business advice he gave his clients in the conclusion to his general report. “To avoid all competition,” he said, “I strongly advise that you form a controlling company or syndicate containing the most influential men. I recommend particularly that you arrange matters in such a way that it would be to the obvious advantage of every oil man to join you, and that you freely provide the opportunity so that the Company may include every man who wishes to venture anything in the exploitation of the oilfields of the North. By this means alone can you hope to avoid competition and the unfortunate results which must follow….”

In his report Bosworth noted that he had “investigated” the discovery at Turner Valley. Fifteen months in the drilling, the wet gas discovery came in on May 14, 1914 – just before Bosworth left Edmonton on his expedition. Within 20 years, that discovery would be recognized as “the largest oilfield in the British Empire.” Bosworth, however, was not impressed. In his view, the real potential was in the North.

Believing Turner Valley was doomed to disappoint explorers, he wrote that that “there are a number of oil companies in Western Canada who have capital in hand which must be spent on drilling wells. At this moment they are faced with failure (at Turner Valley), and might gladly turn to any region where there is a genuine reason to expect oil. Any such companies might become associated with your controlling company to the obvious advantage of all parties, on terms which can be mutually arranged...”

After further commentary, he advises his clients in these words: “You would also provide for the transportation; the necessary railroads; the pipe lines, the refineries, and, what is more important than all the rest, and which would give you complete command of the whole situation, all of the oil produced in the region would pass through your hands to be marketed by you.

“If you could succeed in promoting a great scheme on some such lines as these, no smaller rival group could hope to compete against you, and you might eventually be in the position to control the great oil fields of the North.”

One of the great ironies of these comments, of course, is that they came barely three years after the Standard Oil Trust was dismantled for just such anti-competitive practices. In addition, Bosworth completely misread the importance of Turner Valley and the petroleum potential of Alberta, so smitten was he by the North. The practical value of his advice may be seen in the fact that seven decades elapsed before oil from the Norman Wells oilfield actually began flowing to southern markets.

Now, let us push on with our story. Bosworth does not remark on the coming of World War I. However, when he and his men left the world was at peace; when he returned, Europe and the British Empire had become embroiled in that terrible war. He was probably totally unaware of those developments while in the north.

The exigencies of war postponed exploration of Bosworth’s claims. So did the Dingman discovery. The petroleum industry by this time was focused on Turner Valley field development, where standard practice was to strip naphtha from the gas stream and flare the gas itself. By 1918 an Imperial Oil subsidiary, The Northwest Company, had acquired the properties Bosworth had staked for his clients. Imperial had hired Bosworth himself as chief geologist. The company decided to drill on one of those claims.

Imperial Oil Limited’s legendary exploration geologist, Ted Link, led the drilling expedition. By train, scow and riverboat, he and his crew followed Bosworth’s route north to Fort Norman, just south of the Arctic Circle. They had taken with them the wherewithal to assemble a cable-tool drilling rig, and they soon set to work. One valuable member of the party was an ox, which supplied heavy labour during the summer. As the autumn cold began killing off the forage, he delivered steaks and stew.

Before moving on, it is worth noting that the most important early geological work at Norman Wells, including the location of the discovery well, needs to be attributed to Ted Link – not to T.O. Bosworth. In an important 1947 presentation to the AAPG, J.S. Stewart of the Geological Survey of Canada is adamant on this point.

Canol: Imperial’s first well brought in the great Norman Wells discovery, in 1920. However, there was no practical way to get the oil to market. Because demand in the Northwest Territories was marginal, Imperial had little reason to develop the field. However, later in the decade the company constructed a tiny refinery at Norman Wells to supply gasoline and other products to missions, mines, riverboats and other local customers. The company did not need many wells to meet local needs, and did little investigation of the geology of the reservoir.

That changed after Pearl Harbor. When the Americans came into the Second World War, they were extremely concerned about having secure local fuel supplies in the North, especially after Japan took control of a couple of Alaska’s Aleutian islands. They therefore worked with Canada to develop Norman Wells into a source of local oil supply for a refining and distribution complex. This was the beginning of the Canol Project. The name supposedly comes from the contraction of “Canadian” and “oil”, but I suspect the second syllable is actually “oil” with a Texas accent.

Construction crews built a 950-kilometre oil pipeline over the Mackenzie Mountains to a newly constructed refinery in Whitehorse, in the Yukon Territory. The pipeline was built over some of the most difficult terrain in the country, and much of the work had to be done in bitter cold. Crews also laid product pipelines to Skagway, Alaska. In total, they constructed 2,560 kilometres of pipeline.

By any standard those lines were terrible. The line ran on top of the ground, alongside the road, often without supports. Vulnerable to frost heaving, snowstorms and flooding, the Canol pipelines were not designed for extreme cold. They were neither installed nor handled properly, and they failed frequently. The crude oil pipeline leaked onto the permafrost. So did the product pipelines, which delivered diesel and gasoline to a fuelling station in Skagway, Alaska.

To meet the needs of the refinery, Imperial drilled more wells, and began to better understand the Norman Wells reservoir. Of particular note, the company discovered that it was a Devonian reef – of earlier vintage than the Leduc and Redwater fields soon to be discovered in Alberta, but still a Devonian reef. That turned out to be the geological key.

By the time the refinery was ready to begin operations, the company had drilled 60 productive wells out of 67 project wells in total. The test for the field came on February 16, 1944 when the pipeline began operating. As a producer of good-quality oil (39° to 41° API), the field surpassed expectations. By October 1944 Norman Wells was producing 4,600 barrels per day by natural pressure.

The extraordinary Canol project did not contribute meaningfully to the war effort. The threat to west coast shipping had disappeared and it was clear that the war would soon be won. First oil flowed through the pipeline in 1944, and the refinery operated for less than a year before being mothballed. Perhaps Canol was the greatest white elephant in petroleum history.

No one really knows how much the project cost – estimates range up to US$300 million, all paid by American taxpayers. However, for the following calculations I will use one of the conservative estimates: $134 million. Total oil production was about 1.5 million barrels. In as-spent dollars, therefore, it cost $89.33 per barrel. The Whitehorse refinery only produced 866,670 barrels of refined product. Dividing that by total project cost, you get $0.97 per litre.

Now, let’s adjust those numbers by official consumer price inflation in the United States. In today’s money, the oil would cost $982 a barrel. The refined products would cost $10.69 a litre. And that’s before taxes!

Later studies of the project’s environmental impact in Whitehorse were revealing. The Canol legacy included the creation of an environmental horror known locally as the Maxwell Tar Pit. Appalling disposal and clean-up practices during the Canol debacle had created an oily mess that was declared an environmentally contaminated site in 1998. Forty years earlier, a man had stumbled into the pit and got stuck. He later died in hospital.

Leduc: Although Canol had little impact on affairs of state, it had a huge impact on oil development in Western Canada. As the result of wartime field development at Norman Wells, Imperial learned that the field’s reservoir rock was Devonian reef. Armed with this knowledge, the company’s geologists – led by Ted Link, who by this time was in charge of Imperial’s exploration efforts – rethought their approach to Western Canada.

This was an important example of thinking outside the box. Other oilmen at the time were on the hunt for big plays that looked, walked and talked like Turner Valley. They would be roughly 340 million years old. They would be thrusted anticlines of Paleozoic age in a Mississippian formation. Much fruitless drilling in the foothills sought the next Turner Valley.

Perhaps we should not give all the credit to Imperial Oil for the geological idea that there might be Devonian reefs in Alberta. In an email, my friend Clint Tippett asked whether GSC mapping of the Rockies west of Edmonton – work undertaken by Helen Belyea, Digby Maclaren and others – influenced Imperial’s thinking. Before the Leduc discovery, Charles Stelck at the University of Alberta also gave thought to the question of Devonian reefs in Alberta.

However Imperial arrived at its revolutionary idea, the importance of its decision to drill for a reef cannot be understated. That geological idea brought forth a series of great discoveries. The first came with the aid of primitive seismic technology, and it was a big one – the famous Leduc #1 discovery well. When it came in to much fanfare on February 21, 1947, Leduc laid the groundwork for one of the world’s great post-war oil booms.

There is another important connection between post-war oil development in Alberta and the Canol project. The refinery built in Whitehorse played an important role in Alberta’s industrial development. Imperial bought the mothballed refinery for one dollar, dismantled it and moved it to Strathcona, near Edmonton. There, the company reassembled it to handle production from Leduc and other post-war discoveries. That refinery laid the foundation for one of Canada’s biggest refining complexes.

As I leave this discussion, a final piece of trivia. Although Imperial is the hero of this drama, I understand that the company’s geologists mapped the Leduc reefs at a 90° angle to their actual orientation. After mapping them correctly, Texaco came to have the dominant position in the Leduc chain of reefs.

Summary: The Norman Wells story illustrates a pattern that turns on its head the American model of petroleum industry development. Briefly put, remote exploration has played a critical role in the industry’s development since the earliest years of oil and gas exploration in this country. Bosworth was wrong in important areas. However, his work greatly influenced that of his successor, Ted Link, who ultimately proved that Devonian reefs were an important key to Canada’s petroleum wealth. That change in thinking paved the way for a series of discoveries which represented the birth of the modern petroleum industry in Canada.

It would be easy to think of Canada’s petroleum industry as one that began in southern Ontario and Alberta, grew wealthy, then began exploring and developing its frontiers. But this model doesn’t fit the facts. Key discoveries and developments took place in remote regions. In the sector’s early years, important discoveries occurred almost independently of settlement, and a great deal of oil and gas development continues to take place in sparsely populated areas. In our frontiers, of course, that pattern is fully intact.

If not for the Bosworth report, Canada’s petroleum industry would have had quite a different history. Imperial Oil’s efforts were heroic – indeed the stuff of legend. Enormously frustrated with its unbroken string of 133 dry holes, Imperial planned the program that yielded Leduc as its last major wildcat play in Alberta. If Leduc had not come in, it is easy to imagine the Devonian oil fields lying fallow for many, many years. No other big players were exploring the prairies.

In the actual case, however, oilmen around the world soon became aware of this important new discovery, and they began to bring expertise and investment into the province. They created one of the first great post-war oil booms, and helped lay the foundation for one of the world’s most diverse and technically advanced petroleum industries.

In respect to its long-term impact, T.O. Bosworth’s 1914 report may have been the most influential geological document in Canadian history. I hope my brief comments today have given you reason to consider that claim.

References:
1. T.O. Bosworth, 1914; “The Mackenzie River between Old Fort Good Hope and Fort Norman; the Tar Springs District on the Great Slave Lake; and in the Tar Sand District on the Athabasca River.”Available at the Glenbow Archives, Calgary; reference number M-8656; 69 pages.
2. J.S. Stewart, 1948; “Norman Wells Oil Field, Northwest Territories, Canada”; in Structure of Typical American Oil Fields, Volume III, pp. 86-109; original paper read before an AAPG meeting in Wichita, Kansas, on January 18, 1947.
3. Peter McKenzie-Brown, 1988; “Two Historical Documents: Notes for an Address to the Petroleum History Society”; online at http://languageinstinct.blogspot.com/2006/09/two-historical-documents.html