China: Panda or Dragon?

This article appears in the August 2008 issue of Oilweek.

By Peter McKenzie-Brown

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Genesis of a Giant

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

By Peter McKenzie-Brown

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Losing The Arctic Edge

This article appears in the July 2008 issue of Oilweek.

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

By Peter McKenzie-Brown

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Pushing South

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Damage Control

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

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

By Peter McKenzie-Brown

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Last of a Breed

This article first appeared in the April 2008 issue of Oilweek.

By Peter McKenzie-Brown

Jim Kinnear makes it sound compelling.

During the last couple of decades, “the trust took over the mid-cap end of the market. The junior companies are the explorers. The independents are doing the large projects – EnCana and CNRL (Canadian Natural Resources). Then there are the super majors. This type of vehicle (the trust) is ideal to fit that part of the market. It’s a difficult business model – how much should we reinvest, how much should we distribute to our unit holders. (The trust) is a very efficient way to reallocate capital. If you acquire an interest in an oil and gas asset, there’s good margins and good cash flow. You’re buying a good income stream. Our concept was to buy a cash flow stream. I’m a financial analyst. BSc – very general degree – then became a financial analyst. These assets provide cash flow, part of which is depletion of assets. You put up $100, get $20 back per year for five years, say, then you own the property. You can get a 15-20 per cent rate of return each year.”

These notes give you an idea of the depth, intensity and direction of Kinnear’s thinking.

Trusts evolved out of managed limited partnership (MLPs) for the wealthy and professionals. They are a financial vehicle developed to answer the question, “Can we expand the closed-end trust?” Trusts and MLPs combine the cash flow business model with a tax ruling that exempts them from tax.

Pengrowth: Kinnear’s Pengrowth was the third trust; the first two were Enerplus and Royal Trust Energy. Kinnear remembers when Marcel Tremblay started up Enerplus in the mid-1980s. “He started his first fund with less than $10 million,” Kinnear says. “He got a comfort letter saying that he could distribute all this cash to his unit holders without paying tax. His unit holders would pay the tax on all the net revenue, not the trust. If unit holders lived in another jurisdiction, like the United States, they would pay tax in that jurisdiction.” Companies and corporations pay tax, but royalty trusts do not. They began as vehicles which pass oil and gas cash flow through to investors, and they still serve this purpose.

Pulling out a writing pad, Kinnear draws a graphic showing how trusts work. With an expensive-looking fountain pen he draws a graphic showing cash flow coming from operations and being dispersed to individual investors.

“You’re buying a cash flow stream,” he says. “We called it financial engineering. It’s like a REIT, except instead of owning buildings we owned revenue-generating oil and gas properties.” Taxes would be paid by investors, who could purchase trust units through stock exchanges. This very clever model enabled taxpayers to defer and avoid taxes – for example, by holding their trust in RSPs. The trust/RSP combination postpones taxes, sometimes almost endlessly.

During a shift as an oil and gas analyst in Calgary, Kinnear acquired some petroleum interests. He incorporated Pengrowth in 1987. The year was significant because, in the dramatic first two months of 1986, oil prices had dropped precipitously from $26 per barrel to ten dollars. The drilling industry was flat on its back. Large projects were being cancelled and postponed. Oil and gas companies were earning negative rates of return. In Alberta, housing prices crashed.

Yet the larger Canadian economy was doing well. “I felt like a turd in the fruit bowl” said the president of a major Calgary-based oil company (not Pengrowth) after addressing a business conference in Toronto in 1987. There seemed to be rising prosperity almost everywhere else – partly because energy prices were so much lower. Lower prices benefitted most of the country, but Alberta suffered.

In those days, the late 1980s, oil and gas properties were there, in the gloom, for the asking, and that’s when Kinnear began to buy properties for Pengrowth. Pengrowth is one of the largest and most profitable energy trusts in Canada. Now 20 years old, the trust is worth about $5 billion (total assets). Enerplus and Pengrowth have both become major players in the energy trust business, and they are close in size. In 2006 Enerplus had $2.7 billion in net equity on the balance sheet, compared to Pengrowth’s $3 billion. Marcel Tremblay left Enerplus quite abruptly in 2001.

Pengrowth Manager: Kinnear has created an organization on which, to a much greater degree than is common, he leaves indelible marks – especially in the area of corporate branding.

Pengrowth is one of a declining number of income trusts which still has a one-person manager – essentially, a management contract with the founder and CEO of the company. Pengrowth Management Ltd. is owned 100% by Jim Kinnear, and it puts millions of dollars into not-for-profit events and charities each year.

This arrangement means that Jim Kinnear’s management fees and bonus include millions of dollars for philanthropic sponsorship. Pengrowth’s major sponsorships tend to be high-profile events: The Pengrowth Saddledome, the Duke of Edinburgh Awards and the Canadian Open – the world’s third oldest open golf tournament. “For all (Pengrowth’s) community endeavours the money comes from the manager,” Kinnear explains, “and I am 100% owner of that.” Since the trust’s purpose is to pass cash flow on to investors, as a trust Pengrowth can’t sponsor charitable events directly. “When we invest in these programs, we don’t just give money, though. We get involved. We help make these organizations better. We really feel we can make a difference.”

Kinnear has an encyclopaedic knowledge of the business and of the energy industry as a whole, especially from the perspective of a dealmaker and a salesman. He brings an analyst’s mind, a quick tongue and a great deal of charm to an interview. How has the report of Alberta’s Royalty Review Panel affected his trust? “We don’t have all the details, but it seems to be only 4-5 per cent. What is really important for us is the maintenance of credits for EOR (enhanced oil recovery).”

Of more concern to him was Jim Flaherty's Scary Halloween Trick. Also known as the Halloween Massacre, federal finance minister Flaherty announced this new tax on October 31, 2006, and it will start taxing trusts in 2011. The tax, which will impose a 31.5% duty on the net income of energy trusts, has a catchy acronym, SIFT. The word stands for “specified investment flow-through tax”.

As a result, the price of Pengrowth units “has declined by about 20 per cent on the markets and (the new rules have) made it more challenging to do our business.”

Besides SIFT, Kinnear gives a litany of problems facing the Canadian industry. “The high dollar has affected costs and adversely affected margins. Over the last two years costs have really skyrocketed. They are now twice what they were in 2001. Globally, everything is way up, construction costs, drilling costs, everything. The cost chart in the last two years has become parabolic. Then there was the royalty review in Alberta. The gas market in North America has had major problems and there’s talk of recession. Stock markets around the world are volatile. We call it piling on. What more can happen?”

Outlook: Given all that piling on, Kinnear seems sanguine about Pengrowth’s future. “We have a number of potential development projects down the road that can offset our depletion over the years,” he says. And “we have a huge accumulation of tax pools, we have about $2.5 billion in tax pools, and we can use those to offset this new tax. We continue to be a high-yielding Canadian energy trust. We want to deliver as much cash as we can to our unit holders before we become taxable.”

He argues that a flight to quality in the industry has driven a lot of investors to Pengrowth. “We have a lot of heritage assets. Judy Creek, Sable Island, Swan Hills and the Weyburn field in Saskatchewan. Weyburn,” he adds parenthetically, “is currently the world's largest carbon capture and storage project.” Producing these assets during this period of high-priced oil means high rates of return. “In 2006 we were among the top ten oil and gas property acquisitors in North America. We can double the size of our assets under the SIFT rules.” He also notes with satisfaction that the federal government expects to have Canada’s tax rates at the lowest level in the G-8 by 2012.

Asked about the price outlook, he says “We’re not very good at calling prices. We think there will be recovering gas prices over the next year or so. Storage in Canada is closer to the five-year average than it was, and gas drilling is down” both in Canada and, recently, the US.

Will oil prices climb or collapse? Kinnear is just back from a CERA (Cambridge Energy Research Associates) conference in Houston. One speaker was Matt Simons – author of Twilight in the Desert, and a fierce sceptic of Saudi Arabia’s ability to increase or even maintain oil production capacity beyond the next few years. In a recent pronouncement, Simons proposed that the world reached maximum production two years ago. The apparent increase in supply since that time has been essentially a drawdown in global inventory. The interview turned to a discussion of peak oil.

Peak Oil: Peak oil is the notion that the world has produced about half its producible reserves, and that implied demand will soon outpace available supply.

Kinnear begins in a humourous way. “You usually see a peak in oil prices in the spring, and the low point for oil demand is usually in December.” It is not clear whether he understood the question until he adds this: “In the second half of last year something very interesting happened. Look: we have $90 oil, and most companies are still missing their production targets. Maybe the oil just isn’t there.”

He warms up to the topic. “It took about 250 million years to create all this oil, and we have used about half of it in the last three generations. It’s amazing. Whether you do or don’t believe in peak oil, there just hasn’t been sufficient reinvestment in the business. There’s been a classic cycle of underinvestment. What are the major companies doing with their cash flow? Spending some of their cash on new development and buying back stock to increase shareholder value. Some major companies are replacing as little as 15% of their reserves.”

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

Kinnear echoes a century-old refrain: “It’s a capital-intensive business. You’ve got to keep offsetting depletion and there’s a massive amount of capital required just to maintain production. And suppose there’s not enough investment to both offset the decline and grow production in the near term. What’s going to happen if India and China continue to boom and expand their requirements for energy?” That is a good question.

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

There is an irony in this. Trusts like Pengrowth do not take large exploration risks or develop such megaprojects as oil sand plants. Instead, they acquire producing assets from other firms, and often operate them directly. For firms with that business model, the risk of peak oil can create an ideal business environment. Under peak oil, energy trusts would generate increasing cash flow as a result of rising energy prices. Those funds would come from existing operations, and they would fund future distributions and expansion. While not involved much in the hunt for new fields, trusts like Pengrowth provide an efficient way to harvest known reserves. This is a profitable business model.

India Beckons

This article appears in the April 2008 issue of Oilweek; image from this site.

By Peter McKenzie-Brown

With the head of an elephant and the body of a man, Ganesh is one of the most revered deities in the Hindu pantheon, and certainly the most easily recognizable. Ganesh is the patron of arts and sciences; the god of intellect and wisdom; the remover of obstacles; the propitiator of business.

On one of the coldest days of winter, Ganesh seemed to arrive in Calgary, offering to remove obstacles for companies prepared to help unlock India’s petroleum wealth. The occasion was a travelling road show hosted by the government of India and advertised under the bureaucratic name NELP VII.

For the E&P sector, the prizes on offer are huge: 57 blocks of land in highly prospective but poorly explored sedimentary basins. As the presenters quickly made clear, the financial rewards can be high, and the geological and geopolitical risks are low. There are also excellent opportunities for the service sector.

NELP stands for New Exploration Licensing Policy, and it reflects the reform and liberalization of the country’s economy – a process which began in the early 1990s and has gathered steam ever since. Under the policy, which went into effect in early 1999, the government has held six rounds of bids, awarding 162 production sharing contracts. As a result, the country’s petroleum industry has grown from two companies producing from three basins in 1990 to 49 companies producing from ten basins today. There are 26 basins in the country in total, only 15 of which have been explored. India’s sedimentary basins (more than half of them offshore) total more than 3 million square kilometres in area.

The seventh round of NELP will likely be the most successful yet. On April 11, companies from around the world will submit bids on 57 exploration blocks – 19 in deep water, nine in shallow water and 29 onshore. Whether from government or industry and whether Indian or foreign, all of the road show’s speakers agreed that the bids will be evaluated through a transparent, competitive process with single-window clearance.

According to Les Kondratoff, whose Canoro Resources was successful in the last round of bidding, “going to India today is like coming to Alberta was in the 1940s” (because of the low drilling density). “Why wouldn’t you go there?” he asks. “The risk is lowest.” He points to his company’s Amguri field on a 53-square-kilometre exploration block. He believes it may be a 70 million barrel field. “In Canada, we’d be popping Champagne with that big a field. In India, big discoveries are not too uncommon.”

Indeed, according to information provided by the irrepressible V.K. Sibal, director general of India’s Directorate of Hydrocarbons, Indian gas reserves are growing more quickly – 6 per cent a year during the last seven years – than in any other part of the world. Because of the huge market in India, he stresses the potential for monetizing gas discoveries within India. “Our vision is that we can take gas from everywhere (in India) to anywhere, from anywhere to everywhere.”

Calgary-based NIKO Resources has been the greatest Canadian success story in India. Since the company was awarded exploration blocks in 1999, its stock has risen from $3 per share to a peak above $100, and one of its biggest Indian successes is yet to come on stream. The company and its partner, Reliance Industries, plan to bring a deepwater gas field on stream this coming June; production is expected to peak at 80 million cubic metres (2.8 billion cubic feet) per day.

You have to be a bit cautious when looking at the numbers which the Hydrocarbon Directorate’s Sibal uses in his presentations. The country’s “prognosticated resources” in the 15 basins explored to date, he says, are 205 billion barrels of oil and equivalent. Of those, 66 billion barrels have been identified as “in place reserves,” including 15 billion barrels discovered in the last seven years. However, pending further evaluation and appraisals, so far his directorate has only assigned 4.73 billion barrels of in-place reserves to this century’s 49 Indian discoveries.

Sibal offers compelling exploration numbers. During the first nine months of the 2007-2008 reporting year (it ends in March), the industry drilled 35 exploration wells in poorly explored basins and came up with 17 discoveries. In the previous three years, the success rate for discovery was an excellent though less eye-popping 18 per cent.

Resources Needed, and Available: Speaker after speaker at the NELP conference raved about the opportunities India presents. However, in addition to the obvious opportunity offered to the E&P sector, there was an undercurrent of opportunity for the service sector. Although there are already many service providers in India – international companies like Weatherford International and domestic ones like Jindal Drilling – opportunities for the service sector are clearly outstanding.

Getting the equipment and services needed to explore and develop are slowing down the country’s exploration effort. According to Jindal Drilling’s Naresh Khumar, “There is a huge demand for all kinds of services. Companies are asking for drilling holidays because they cannot get rigs to drill.” From cementing to wireline to workover services, from marine logistics to jack-up rigs, the situation in India is dire.

Frankly, this explains India’s highly attractive NELP energy policy. The country expects demand for both oil and gas to more than double by 2025, leaving huge gaps between consumption and domestic supply despite large anticipated increases in production. National security and trade balances make this problem paramount. The country is anxious to develop a world-class petroleum industry, with much greater capacity in the areas of service and supply.

Weatherford Tools’ David Reed – his company (a US-based international oilfield service provider) is growing rapidly in India – is impressed with the “ease of entry, access and equity” which players encounter there. It is “at the top of the scale” as a country to work in, yet “standards for service providers are very high. There are no compromises in India.” He is also smitten with the people. “There is a tremendous skill-set in India, and you would be crazy not to leverage that for your business.”

The skill-set Reed is referring to represents one of India’s many paradoxes. While 40 per cent of Indians are illiterate, the country has the world’s second-largest pool of trained scientists and engineers. Those skilled masses enable India to develop more computer software than any other nation in the world – worth $22 billion last year in export income.

Doing Business in India: The story barely begins with the skilled workforce. Now firing on all cylinders, at 9.4% last year India’s economic growth rivals that of China. Since 1991, when the country began its program of economic reform, annual growth has averaged 8%.

India speaks 23 major languages and 22,000 distinct dialects but, stresses Canoro’s Les Kondratoff, “the language of business is English.” India boasts the 12th largest economy in the world – $1 trillion last year, with net exports of $127 billion. The country has large and diversified infrastructure, including 15 international airports and 449 domestic ones.

Indians practice many religions. Hindu is the most important, but the country also has the world’s second largest Muslim population. Despite inevitable tensions, the great diversity of Indian people is held together by the largest and noisiest democracy on the planet.

India’s use of British-style common law means contracts signed in India are honoured. According to the Hydrocarbon Directorate’s Sibal, “production sharing contracts are sacrosanct to us.” He cites “attractive, competitive and transparent bidding terms,” a positive climate for investment, efficient infrastructure, expanding domestic oil and gas markets, higher returns and lower risk than in other developing countries. He then throws out a challenge: “Compare us to the world’s best. We come out on top.”

One India hand is Don Whelan, who went there in 1996 with the late Bill Olsen, the founder of NIKO Resources.

A real fan of the small company in India, Whelan is now creating a Mumbai-based petroleum service company called Today’s Petrotech. “Little companies, as NIKO was when we went there, are more adaptable,” he says. “The first two years were a real learning curve. After we got over that hump, it became easier and easier. Now it seems like second nature.” He warns, though, that the Indian demand for paperwork sometimes seems endless.

Having married since moving to India, Whelan has no intentions of returning to Canada. For him, the expat life in Mumbai is just fine. “Our maid, our driver, our gardener – their wages are about $100 per month each.” He worries, though, that Mumbai’s infrastructure isn’t keeping up with changing times. The streets are increasingly gridlocked, and that is going to get worse in the fall when Indian automaker Tata Motors begins selling its long-awaited People’s Car, with a sticker price of about $2,500.

Amarjeet Singh, a KPMG partner, is headquartered near New Delhi. He says the comparisons between investing in India versus investing in China favour India every time. “If you just look at the experience of all big multinationals going to China, most of them will vouch that they are still struggling to make money. In India there are many roadblocks, but if you are doing your business properly, if you understand the market, if you adapt yourself to Indian conditions and frame of mind you will make as much money as a domestic player.” But he cautions that “you have to have a long-term view. If you have a long-term view you will always make money.”

Singh recommends that entry-level players in India “outsource all of the functions – accounting, administration, all of those things. Those are not your core business.” Singh admits that taxation in India is complex, but says “it’s complex in Canada, too. If you plan well, if you handle it well, taxation is not a roadblock to doing business in India.”

According to Singh, “The fiscal regime which is applicable to exploration in India is at least as aggressive as in any other part of the world. There are tax holidays, you are permitted to set off losses in one block against income in another, you can aggregate all your expenses against aggregated production and so on. The government has carved off benefits for the E&P industry that are far above those in other countries and other industries in India. And once you have a production sharing contract, you can operate any way you want.”

Canoro’s Les Kondratoff echoes those sentiments. “Projects aren’t ring-fenced and there’s a seven-year tax holiday from the time you begin commercial production. Royalties are low and you are entitled to full-cost recovery.” He adds that there is enormous demand for bottled propane, and refineries want ever more crude. There are opportunities all around to monetize petroleum assets.

His company had a devastating experience in Russia. Canoro’s Rus