• The current five per cent, front-end  incentive for natural gas and conventional oil wells will become a permanent feature of the royalty regime.
• The maximum royalty rate for conventional oil will be reduced from 50 to 40 per cent effective Jan. 1, 2011
• The maximum royalty rate for conventional and unconventional natural gas will be reduced at higher price levels (the exact threshold remains a question mark) from 50 to 36 per cent effective Jan. 1, 2011.
• The bottom rate for both will remain at five per cent.
• Exact royalty curves will be finalized by May 31.

On the regulatory side, there was a lot of talk about unburdening industry from the status quo. “I regret we didn’t start acting on it back in 1995,” Liepert said in response to a question about whether the government thought it should have overhauled the regulatory process earlier. Among other changes anounced, expect the ERCB to streamline the process for harmonizing well spacing. In addition, a task force has 90 days to report back on ways to further slash red tape.

The premier and energy minister were asked about shale gas, but said little to indicate a B.C. style incentive program was in the works. Stelmach noted U.S. shale supplies are “putting a lot of pressure on us” because the province is shipping less of its traditional supply south of the border.

On a general note, Liepert said Alberta’s oil and gas sector is poised to contribute $2.5 trillion to the provincial GDP over the next quarter-century. He stressed that the changes announced wouldn’t impact the government’s pledge to balance the books by 2012-13.

Source: PHRCC

Source: StatsCan

If convicted, the company could be fined up to $500,000 under Alberta law and up to $300,000 with a six month jail sentence for executives under federal penalties. Momentarily eschewing the fence-sitting vantage common to his trade, reporter Darcy Henton speculates that the ducks could very well be the canaries of the tar pits.

Could be, but there’s a sense, too, that the bird brouhaha obscures the forest for the trees. The controversy hasn’t, for example, prompted a dramatic rethink among firms looking to capitalize on Alberta’s energy assets. Nor has it caused foreign investors to lose sleep.

Korean National Oil Corp. certainly isn’t coasting. The firm snapped up Calgary-based Harvest Energy for $1.8 billion last October, and is poised to spend upwards of $6.5 billion more on foreign acquisitions this year, according to the Journal’s Gary Lamphier.

In fact, evidence suggests it’s business as usual in the bitumen belt. More than a dozen projects – the majority of them using comparatively benign in situ extraction methods – have come off the shelf in recent weeks.

Elsewhere, another Asian entity, Korea Gas Corp., recently gained a $1.1 billion toehold in the shale gas plays of northeastern B.C. The firm expects to extract a trillion cubic feet of gas from a tract of land owned by EnCana Corp. of Calgary, the Globe and Mail reports.

The move is no doubt bolstered by plans to build an export terminal at Kitimat, B.C. Korea Gas has a 40 per cent stake in designs for the $3 billion export hub, which is being developed by Kitimat LNG Inc. and has also attracted investment from U.S. gas producer Apache Corp.

What does Syncrude’s day in court amount to? A blemish, sure, but development could well trump duck deaths as western Canada increasingly becomes a target for energy-hungry Asian tigers.

Source: World Energy Outlook

Source.: Royal Dutch Shell PLC

Source: WEF

FUTURE STOCK
Not Settling for Second
The next bitumen wave is poised to grab the top spot on the world’s oil ranking

HOT TOPICS
Economics
An Edmonton author crafts a formula to walk the talk when it comes to clean air

Dec 2009-Jan 2010 Volume 5 Issue 7
	FEATURES Tanker Rush Offshore oil traffic is igniting environmental concerns in the Maritimes FUTURE STOCK Not Settling for Second The next bitumen wave is poised to grab the top spot on the world’s oil ranking HOT TOPICS Economics An Edmonton author crafts a formula to walk the talk when it comes to clean air

]]> http://www.albertaoilmagazine.com/2010/02/2010-archives/feed/ 0 http://www.albertaoilmagazine.com/2010/02/feb-mar-2010/ http://www.albertaoilmagazine.com/2010/02/feb-mar-2010/#comments Fri, 05 Feb 2010 15:37:38 +0000 Gunnar http://www.albertaoilmagazine.com/?p=1599
ON THE COVER:
Photography By Colin Way COVER STORY: Innovation Nation
The long-standing pedigree of oil sands ingenuity is fast approaching a crossroads. Improving efficiencies demand new technology. But novel ideas don’t come cheap

HOT TOPICS

DEPARTMENTS

By Bill Sass

The history of science is crammed with anecdotes of discovery, and inventing oil sands production is no exception.

The Greek scientist Archimedes is reputed to have jumped out of his bath and run naked through the streets of Syracuse, Sicily, shouting “Eureka” after hitting on the principle of using buoyancy to measure the volume of an object with an irregular shape. Charles Goodyear is said to have discovered vulcanization of rubber by accidentally dropping some raw rubber on a hot stove.

Then there’s Karl Clark’s washing machine.

Clark, an Alberta scientist, in 1920 commandeered his wife’s washing machine, threw in a bucket of oil sands, a measure of caustic soda and agitated the mixture with hot water. Bitumen separated and floated to the surface.

There seems to be no record of how agitated Clark’s wife was. But his process was the first workable way to get oil from the sticky ore of tarry sand in northeast Alberta. It was an idea whose time hadn’t quite come. Nearly half a century passed before Great Canadian Oil Sands Ltd., ancestor of Suncor Energy Inc., began commercial production in Fort McMurray in 1967.

The second and biggest plant, Syncrude Canada, began as a research consortium of oil companies in 1964. Construction of the first Syncrude commercial operation began in 1973 and it took until 1978 for its first oil to flow. The research arm of the operation never stopped.

To Cheryl Robb, Syncrude’s media relations adviser, and many of the 100 staff and scientists at the company’s research center in south Edmonton, this is the stuff of history books. A new generation is looking for ways to make its own history and its own breakthroughs at the bright facility, ergonomically designed to allow researchers easy ways to collaborate and disseminate ideas.

The $20-million center, built in 1994, is the industry’s only in-house research facility. If something is new and state of the art in bitumen extraction, it likely came from there. Syncrude spends $50 million a year on research through lean and flush times alike.

“Knowing everything there is to know about what you’re doing” is a good way to describe what Syncrude does, Robb says. “What we do at research is to find ways to do things better and doing it the best way that we can.”

By Gordon Jaremko

Joe Lukacs, a serial innovator with almost a half-century of experience as an engineer on energy technology frontiers, has invented a name for the field: “productization.” It means, “You convert a need to an idea to a gadget,” he says.

Never expect to succeed overnight, Lukacs adds in his post-retirement role of technology development coach as president of Canadian Environmental Technology Advancement Corp. West, a non-profit advice firm founded by Environment Canada and supported by its provincial counterparts. “This is a conservative industry. You have to prove things work over and over and over again.”

Eminent scholars teach the same lesson more formally in a 2009 report on a two-year inquiry by the Ottawa-based Council of Canadian Academies. The authors, an 18-member expert panel on business innovation appointed by the federally financed agency, echo an old saying that genius is one per cent inspiration and 99 per cent perspiration.
“An innovation is not simply an invention or even a practical prototype. There must be implementation to a meaningful extent,” says the 268-page document.

“Innovation is not limited to products and services, or to the direct application of science and technology. Indeed, many of the most far-reaching business innovations – such as the factory assembly line, television advertising, just-in-time inventory management, web-based commerce and artistic commercializations like rock music – have little to do with the traditional image of breakthrough products coming out of the lab.”

Profiles by Gordon Jaremko

Winning plaudits from green factions may not rank high on industry’s to-do list. Yet Alberta Oil’s list of innovators — from companies pioneering new supply chain relationships, to those using next-generation technologies to reshape age-old practices — proves that environmental imperatives and profit are anything but mutually exclusive. Welcome to the new frontier.

By Bill Sass

The story of inventors can have many beginnings. Let’s pick one that leads to success. It starts in the cattle country of Uruguay in South America and adds a calamity that brought Scott Van Vliet back to Alberta and placed him firmly on a different road in life.

Van Vliet is now vice-president of Environmental Refuelling Systems Inc., a family firm whose purpose is to make sure its customers’ mining machines in remote worksites never run out of gas. But in 2004, as a graduate of the Montana State University agriculture program, he was involved in exporting cattle from North and South America to markets around the world.

An outbreak of mad cow disease in Canada devastated the cattle industry. Investors started pulling out funding as international markets slammed their doors to meat from the western hemisphere. “I came back to Alberta in 2004,” Van Vliet recalls. “I was done with agriculture.”

He still needed a job. He went to work for his father, Maury, who was a partner in an aviation fuel enterprise called EnviroTankers, and soon settled into a management role.

Maury, son of a University of Alberta sports legend of the same name, already had a solid business career. He worked for Amoco, Enbridge and Oxford Properties before going into aviation fuel.

Another son, Chris, a Canadian Forces pilot who spent some of his holidays flying helicopters to fight forest fires, called the family’s attention to mobile refueling technology. “They needed a fuel source to follow them.” Scott says. “They needed a mobile system.”

Scott was doing some marketing work for the long-proposed, never-built Mackenzie Valley pipeline when he talked to some Nexen Inc. representatives who were involved in the Long Lake oil sands project and were unhappy with the reliability of their fuel supply in their remote camps in the Athabasca Oil Sands Region.

Scott and Maury asked for – and got – carte blanche to design and build a fuel system for the large but hard-to-get-to project, deep in bush south of Fort McMurray. “We started building the system even before the negotiations were done. Maury helped with the new designs that had never been done before.” The result was a 50,000-liter gas tank on skids, featuring a cardlock payment system and its own power supply.

Enter the third partner and president of the family operation, Todd Van Vliet. “When we got operational at Long Lake, we realized the fuel projections were out to lunch. The fuel demand was through the roof,” says Todd.

Maury’s partners in the EnviroTankers aviation fuel firm weren’t interested in taking a plunge to expand operations or try new directions. So a new company, Environmental Refuelling Systems (ERS), was launched in the fall of 2005.

Todd left his Edmonton law practice to join his father and brother in the venture. Maury oversees the company and Todd and Scott handle day-to-day operations, Todd in Edmonton and Scott in Calgary.

“We started at zero and grew at 100 per cent a month for five months. We got stretched pretty thin. Sometimes success can kill a company. Lots of people have sold their way into bankruptcy,” Todd says.

The staff expanded from the three founders to 60 in the winter of 2007. Lean times in the energy industry pared the payroll back to a staff of 36 by late 2009. The concept of the company is to provide worry-free, reliable refueling systems to remote worksites – essentially gas stations on skids backed up by a company-created distribution infrastructure. All the machinery and vehicles used in the energy industry – from pickups to bulldozers to heavy haulers to generators driving pumps and creating electricity for bunkhouses – is worthless without fuel.

“Someone told me ‘Fuel is our breath,’” Todd says. “When a heavy hauler stops at -40 °C because there’s no fuel, there’s a real money issue. When you run out of fuel at a northern camp, it’s a long turnaround time.”

Imagine standing on an Alberta hilltop and looking east along a smooth trench lined with steel, 25 meters wide and two meters deep, that stretches over the horizon for 2,400 kilometers – almost the entire distance to Toronto as the crow flies. The $600-million cluster of 19 jumbo tanks that Enbridge Inc. finished erecting last fall at Hardisty, 160 kilometers southeast of Edmonton, would fill such a Pyramids-scale landmark to the brim with oil.

Steve Wuori, Enbridge’s executive vice-president of liquids pipelines, boils the main service provided by its new tank farm down to a single word – time. “It’s a valuable commodity in the oil business.”

No Canadian fossil fuel producers or marketers claim to be big enough to change the direction of movements by the international markets that determine the value of their wares. All Alberta energy companies – and the provincial treasury, which relies on oil and gas royalties as its biggest revenue source – have routinely called themselves price takers since the mid-1985 end of the National Energy Program and the inauguration of the free trade era.

But the new storage site, formally titled the Enbridge Hardisty Contract Terminal, enables Alberta oil suppliers to try managing the effects of uncontrollable price movements with a technique known as arbitrage. An ability to stockpile and drain inventory in response to market trends is the key to practicing the complex art, which juggles timing, delivery destinations and types of shipments. Enbridge’s attached pipeline network carries about 90 different varieties of oil, in batches kept separate with hydraulic engineering techniques, to markets across Canada and the United States, Wuori reports.

At the 2009 average price of US$70, the 7.5 million barrels contained by the Hardisty tank farm – enough to fill 48,000 Olympic swimming pools, Enbridge calculates – would be worth $452 million. But the value is a moving target.

On any given day, owners and merchants of the black gold river make educated guesses about how much it will be worth tomorrow or next week, month, season or year. Markets gyrate around the clock. Consequences of making the right judgment calls – or mistakes – about when to buy, sell or hold are often huge.

In 1998, a hardship year when oil averaged $14.44, the entire 7.5-million-barrel Hardisty reservoir would have fetched $108.3 million. In 1999, the beginning of the long climb by global markets towards new 21st-century heights, the value recovered to $19.25 a barrel or $144.4 million.

At the 2008 top of the fossil fuel economics cycle, the giant pool was worth $747.3 million at the annual average price of $99.64 a barrel. At the dramatic moment in July 2008 when the oil bubble blew up to its peak at $147.50, Hardisty’s 7.5 million barrels was worth $1.1 billion. But by Christmas, when oil deflated to $30.28 in the darkest hours of the global financial crisis, the pool’s value shrank by 80 per cent to $227 million.

Big economic and financial questions refuse to go away. Are consumers liable to take beatings on gasoline and home-heating bills if they buy big cars and houses in the belief that the energy ingredients in the cost of living will stay at the reduced levels of 2009 compared to painful 2008? Will oil executives take a chance on losing their shirts if they start projects that rely on prices remaining stable in their recent healthy trading range of US$70-$80 a barrel?

Yes on both counts, says the fact-finding arm of the United States Department of Energy. The answer shows up on a price risk monitor that Washington’s Energy Information Administration (EIA) added last fall to its influential oil and natural gas inventory records, which are mainstay weekly information sources for suppliers, buyers, and commodity and stock exchange traders around the world. The new indicator appears in monthly short-term energy outlook reports that review current conditions and make projections for the next 12 to 24 months.

Called “price confidence intervals,” the risk measurements are an energy adaptation of computer statistical programs that the U.S. Federal Reserve Board and the Bank of England employ to anticipate financial behavior. The EIA explained that it devised its own probability models of potential changes as a reality check on its projections. International corporate giants of the energy scene have long been known to use proprietary, confidential versions of the economic wizardry for internal planning purposes. Details of the mathematics are bound to vary, but the main difference is that the EIA publishes its methods and results.

“Energy prices are volatile, primarily reflecting market participants’ adjustments to new information from physical energy markets and/or energy-related financial derivatives,” the Washington agency said in documents describing its innovation. “EIA quantifies this uncertainty, or risk, in the market by using ‘implied volatilities’ derived from the New York Mercantile Exchange (NYMEX) options markets for light, sweet crude oil and natural gas futures prices.”

The first use of the energy price risk monitor highlighted the vulnerability to extreme changes of the global fossil fuel markets mirrored by NYMEX trading. EIA unveiled the new service last October, the first anniversary of the start of the dizzying three-month slide that drove oil down from a high plateau around the 2008 record peak of US$147.50 a barrel into the dumps at $30.28.

The new monitor predicted a 2009-10 winter confidence interval or potential trading range of $49 to $96 a barrel – an uncertainty band of $47, or 48 per cent. The longer producers and consumers try to look ahead into the future, the greater the errors they are liable to make, EIA added. For oil prices at the end of 2010, the monitor said the confidence interval was $32 to $168 per barrel – a colossal uncertainty band $136 wide.

Shortly before the onset of the 2009-10 heating season, which started late but with a bang due to blizzards across North America, the risk barometer was registering that natural gas was vulnerable to even stormier prices. The confidence interval was $3.70 to $8.50 per thousand cubic feet – an uncertainty band of $4.80, or 56 per cent.

As Alberta’s technological formula for cutting greenhouse gas emissions with carbon capture and storage (CCS) goes into action, the policy’s costs are starting to show. Ironing out just a single wrinkle triggered an industry fund raising drive this winter.

“It’s one of about 150 things we have to move forward,” says Rob Craig, strategy director for the Integrated Carbon Dioxide Network (ICO2N). At forums provided by the Petroleum Technology Alliance Canada, he set out to raise $500,000 in cash and donated technical services to generate fine print required by emissions reduction planners.

The money will pay for a research effort titled the Alberta CO2 Purity Specification Project. The study will determine how dry, concentrated and free of impurities that carbon dioxide must be made to qualify for removal by pipelines and injection into underground disposal sites.

All CCS projects need product specifications in order to move off industry drawing boards and into implementation stages of design and construction, Craig says. “They need to understand what product they’re working towards.”

For disposal pipelines, purity standards affect key issues of steel corrosion, safety and operating procedures. In disposal sites, the nature of the product affects how it will behave in variable underground features and its chances of escaping from the natural geological vaults relied upon by the policy.

Above all, purity targets will decide how much equipment and expense will be required to create the key link in the planned disposal network — the capture of waste carbon dioxide at emissions sites. “In some cases raising purity increases capture costs exponentially,” Craig reports.

“There are no really cheap sources of large volumes.” Even the least costly opportunities that ICO2N has identified for use of the technology work out to about $50 per tonne of greenhouse gas. “We never developed any of our infrastructure in anticipation of carbon capture,” Craig says. “It’s a massive undertaking.” At coal-fired power stations, “the infrastructure you need is almost as big as the plant.”

At most industrial sites, carbon dioxide is thinly diluted in other gases such as nitrogen. The exhaust is also damp, contaminated with impurities like sulphur and vented at atmospheric pressure. Costs of compression for pipeline transport alone are about $20 a tonne, Craig reports. “The more you investigate, the more you find out needs to be done. The more you dig into it (CCS), unfortunately, the more expensive it seems to be.”

Potentially staggering bills for stripping greenhouse gas out of industrial plant exhaust are no surprise to government or industry experts. Digging deep into disposal issues began well before the 1997 Kyoto climate change treaty. The Alberta Research Council and Alberta Geological Survey started compiling a catalogue of underground storage sites in the province’s porous rock formations as international scientific work on carbon control gathered steam in the late 1980s. United Nations-sponsored action plans fostered practical engineering and economic studies into adapting Alberta’s fossil fuel industry.

The initial estimate of the price tag for relying on CCS to hit even relatively modest emissions reduction targets in the Kyoto agreement was an astronomical $10 billion a year. The figure emerged as the bottom line of the pioneer research in the field, a 2002 report by the Canadian Energy Research Institute (CERI). “The costs for this are comparable to those for nuclear or renewable energy options,” the report said.

Not all Albertans frown when the talk turns to carbon emissions. Christine Schuh lights up when she describes working on the cutting edge of adapting industry to the emerging new era of greenhouse gas control.

“I absolutely love this stuff,” Schuh says. “I think I’m actually helping the world. I’m using my skills. It uses a blend of things. I like creating solutions out of a blend of things.”

She has a mandate to channel out the trademark can-do personality of Alberta engineers in her role as leader of the climate change services group in the Calgary office of PricewaterhouseCoopers LLP. Her credentials as an associate partner in the accounting firm’s advisory services practice include two engineering degrees, industry experience such as working with mammoth stationary motors in natural gas field compressors, a PhD in environmental science and a teaching role as an adjunct professor at the University of Calgary.

Her seven-member group does what engineers like best: build. The team is laying foundations for new professional and business fields that combine engineering, science, financial auditing and law. The work has a pioneer flavor as an economic and technical frontier. “I’ve been doing this since 2001, and I’m probably one of the gray-haired people in the business,” Schuh says.

A dozen years after the Kyoto treaty served notice that greenhouse gases will be taken seriously by making the first stab at global emissions reductions, outlines of the new clean energy regime are starting to come into focus. The Alberta government has sharpened its rules, in keeping with declared intentions to anticipate developments rather than wait for clarity to emerge from slow and amazingly complicated international deliberations such as the Copenhagen climate change conference held in December by the United Nations.

As of mid-2009, Alberta tightened up regulation of carbon exhaust by industrial and public facilities. Before, the rules caught only very large operations with annual waste gas emissions equivalent to 100,000 or more tonnes of carbon dioxide per year. The change expanded policing to all sites venting 50,000 tonnes or more.

The reduced emissions tolerance still leaves personal energy consumers alone. But Schuh observes that the tighter regulatory mesh in the new version of the greenhouse gas dragnet catches relatively small facilities, at least compared to the jumbo targets of the original system, like coal-fired power stations and petrochemical plants.

The tightened regime potentially affects industrial sites as small as production batteries or clusters of heavy oil wells if they vent natural gas, which as methane is rated as about 20 times more potent as a greenhouse gas than carbon dioxide. Large hospitals and universities also have to start thinking about their emissions under the new Alberta standard, Schuh says.

The regulatory net is expected to become steadily tighter. In Ontario and British Columbia, where the governments do not face such large-scale issues of economic and technical adaptation to carbon control as Alberta, the emissions ceiling is already down to 25,000 tonnes per year. Standards proposed at the federal level would set the bar as low as 3,000 tonnes per year, which could sharpen the focus of greenhouse gas policing down to single oil wells.

The goal of pioneer professionals in the fledgling field of carbon control is a system of environmental monitoring, measurement, record keeping, reporting and auditing that is as clear and reliable as financial accounting. The apparatus will be essential regardless of how governments eventually settle a heated global argument over types of standards, Schuh says. Trustworthy information will be required whether the new regime sets absolute limits on greenhouse gas emissions or uses less drastic “intensity” standards that regulate volumes of waste gas output per unit of energy use or production.

While the oil sands get the bad rap, coal-fired power plants hold the lead in Canadian industrial greenhouse gas emissions. Utilities, a category which is chiefly electricity-generating stations but also includes pipelines, account for 43 per cent of carbon dioxide discharges in the latest national inventory by Statistics Canada and Environment Canada. Manufacturing comes second at 32 per cent. Oil and gas extraction, mining and quarrying collectively rank third with 21 per cent. The figures take months to compile from industry reports, and the latest inventory, released this winter, covers 2008.

Alberta has 109 of the 350 industrial operations required to file greenhouse gas reports because their annual carbon dioxide discharges exceed 100,000 tonnes. The energy province also has seven of the top 10 emitters: two are the biggest oil sands plants and five are coal-fired power stations. Eight of Canada’s top 10 greenhouse gas sources are electricity plants.

The national inventory is dominated by 58 sites with annual emissions exceeding one million tonnes that are responsible for 69 per cent of the industrial total of 263 million tonnes. The 2008 carbon dioxide discharges were down by 15.7 million tonnes, or six per cent, from 2007 due to plant closures and varying production by continuing operations. Alberta recorded a 3.5-million tonne drop but still led the nation by a wide margin with 2008 emissions of 111 million tonnes, or 42 per cent of the Canadian industrial total. Ontario came second with 67 million tonnes, or 26 per cent, but has Canada’s biggest emitter: the Nanticoke power plant southwest of Toronto.

Big industrial sites account for 35 per cent of the nation’s estimated total of 750 million tonnes of greenhouse gas emissions from all sources including personal and small business consumers of fossil fuels. Canada, in turn, has 2.5 per cent of total world carbon dioxide discharges estimated at 30 billion tonnes.

By Gordon Jaremko

In the fashionable theory of innovation, an embarrassment of riches stunts the growth of Canada, and especially Alberta. Abundant natural resources are said to stifle creativity. Energy price drops provoke disparaging comparisons to countries with other livelihoods and notably, nowadays, information and communications technology (ICT).

A commentary by the Canada West Foundation recites the view in vogue under the title The Albatross: Natural Resources and Western Canada’s Economic Future. “The traditional emphasis on natural resources perpetuates our overreliance on the bottom end of the economic value chain. Pulling stuff out of the ground, whacking down trees and growing grain all contribute to the western Canadian economy, but they also rely on highly volatile commodity markets and do not capture the value that can be added to them down the line.”

Similar thinking inspires a 268-page report – titled Innovation and Business Strategy: Why Canada Falls Short – by the Ottawa-based Council of Canadian Academies. The staples thesis, a university economics mainstay for 80 years, explains why. Canada is held back by a colonial past of importing technology to export resources, which breeds exposure to global market risks and a timid business culture. Breaking old habits is the formula for catching up with higher productivity in ICT-rich countries, notably the United States.

The theoretical critiques ignore realities of ICT use and 21st-century resource development.

In the U.S., digital tools are cornerstones of industries that look hugely productive on statistical charts of revenues per employee: health care, financial and insurance services. Texas billionaire Ross Perot, an ICT pioneer whose feats included a credible run as an independent presidential candidate against the first George Bush in 1992, made his fortune as a health-care computer contractor. Before the bubble burst in 2008, the financial sector’s share of U.S. gross domestic product doubled to eight per cent, or more than $1 trillion.

But big ICT users are vulnerable to market risks. Perot is also famous as the biggest individual loser ever on the New York Stock Exchange because the value of his shares in his computer firm fell $450 million on one bad 1974 day. The U.S. financial sector is forecast to lose at least $100 billion a year and 700,000 jobs in the current market spasms.

Economists are starting to question whether the natural resource sector deserves its dinosaur image. “Innovative firms are found across all industries,” says a research paper in the winter edition of Statistics Canada’s Canadian Productivity Review. The study proposes including resource exploration in national ledgers of wealth generation. “An expanded definition of innovative activity is necessary to analyze fully the role of scientific knowledge creation in advancing economic growth.”

Fashionable opinion needs to take Statistics Canada’s cue and quit ICT worship. To open minds, a wide streak of creativity is obvious in the energy industry. It lives and grows by mastering – partly with ICT – adversities from gyrating prices and costs to increasingly difficult resource deposits and regulation.

Gordon Jaremko

By Patrycja Romanowska

Now that “peak oil” is a household phrase, armchair energy philosophers debate grand questions. When will supply end? Will it be market prices or government policies that force a large-scale transition to different fuel sources? How will it be possible to soften the blow when raw material for 90 per cent of the goods society consumes disappears or becomes too expensive to extract?

Only the guys in the business can be overheard, amid talk of de-industrialization and an oil-free world, telling each other that new technology will enable them to extract harder-to-reach fossil fuels and save them from the ugly reality of no longer being able to sell their wares.

What rarely, if ever, enters the debate is the game-changing question of whether fossil fuels are in fact, fossil fuels. And they are not, says geologist Vladimir Kutcherov in a rolling Russian accent. Oil and gas are generated by physical and chemical processes under pressure – not, as conventional wisdom has it, as residues of organic matter that have been squeezed and heated by various geological processes over millions of years.

The concept of the abiogenic origin of petroleum was developed by Russian and Ukrainian scientists during the last half century and has three main points, says Kutcherov in an Alberta Oil interview from his home in Sweden. First, he explains, hydrocarbon compounds are chemically generated in the upper mantle of the Earth. Then they migrate through deep faults into the crust of the Earth. “There they form oil and gas deposits in any kind of rock – crystalline basement, volcanic and volcanogenic rocks – in any kind of structural position.”

If Kutcherov is right, then the implications are enormous: “Hydrocarbons were generated, are generating and will be generated forever. This is a natural outgassing process of our planet.” Or in layman’s terms, Earth will never run out of oil and gas.

The theory of the abiogenic origin of petroleum predates the green movement. So it can’t be dismissed as an oil company invention meant to stifle creation of new fuels that do not generate carbon dioxide exhaust. It is hard to imagine that even oil companies would be entirely thrilled if the supply were limitless. This would revive the early days of black gold rushes and has potential to cause a collapse of prices for one of the world’s most precious commodities.

Scientifically, the main disadvantage of this different theory has been the absence of experimental data, says Kutcherov. However, in the last few years, the Russian scientist and his colleagues at Sweden’s KTH Royal Institute of Technology have made some progress. Their recent results, received by the geophysical laboratory at the Carnegie Institution in Washington, D.C., indicate that at least natural gas (as a mixture of methane, ethane, propane and butane) can be produced in a laboratory by modeling the conditions of the upper mantle of the Earth. These results were confirmed by a team of American colleagues, he adds.

Kutcherov also points to data from Saturn’s largest moon, Titan, indicating that there are lakes or even oceans of hydrocarbons on its surface. And as all know, “There are no organic compounds in space,” he says.

Kutcherov admits that the fact that natural gas can have an abiotic genesis is not the most controversial aspect of his theory. If you were to ask geologists, he says, “Thirty to 40 per cent will agree that natural gas is abiotic in origin, and 90 per cent would say yes but add that it is a minor source of natural gas.”

Oil is a different matter. Kutcherov estimates, and a quick scan of both scientific and popular literature confirms, that 99 per cent of geologists do not believe in the abiotic origin of oil.

“What kind of geological evidence confirms our theory and do we know where people should find oil and gas deposits? The answer to the second question is yes.”

He has an answer to the first question too. According to Kutcherov’s theory, if hydrocarbons are manufactured under upper mantle conditions, they have to migrate to the Earth’s surface through faults.

Interview by Gordon Jaremko

Tim Shipton occupies a vantage point in Edmonton that gives him a big-picture view. As president of Alberta Enterprise Group, he leads a public policy advocacy group of businesses with more than 30,000 employees in fields from accounting to steel. As a former finance director for the Progressive Conservative Party of Alberta, he knows politics inside out.

Alberta Oil: You told a Calgary industry conference held by the Canadian Institute that Alberta needs an “oil sands response team.” Why?
Tim Shipton: We’re at a political crossroads. We all cheered when we were recognized as having the world’s second-biggest oil asset. We forgot the responsibility that goes with such an asset. We have to stand up with confidence and defend our industry. If some of the climate change policies that the critics talk about pass unopposed, by default we’re going to see a historic transfer of wealth out of Alberta to the rest of Canada and the world that is going to tear up the fabric of Confederation.

AO: When will this all come to a head?
TS: We’re paused now. We’re in a time out. I put the critical moment five years down the road. We’re going to come out of recession. We’re going to see if the oil sands industry learned its lessons or whether it will go at breakneck speed, driving up costs and environmental effects. There has been a shift in society. The industry’s mantra has been that oil demand will always be there and criticism is no big deal. But political pressure against it, originating with environmental movements, isn’t going to go away. We need a fundamental rethink about how we’re perceived globally and how we do business.

AO: Do business leaders understand the risks?
TS: They’ve seen they can no longer sit on the sidelines and let government tell the story in isolation. During the trade mission that Alberta Enterprise Group took to Geneva in 2009, it was made obvious to us that there could be massive costs placed on every barrel that comes out of the oil sands. But we’ve seen no practical or tangible result.

AO: What is to be done?
TS: Industry needs to embrace organizations like ours who want to get out and help. There needs to be a sharing of information. The only way we’ll be successful is with the facts. The facts are on our side. But the facts need to come out in a timely fashion. If they don’t, you’re lost. You need to be there. Resources have to be dedicated to this. A segment of society is immune to facts. What we’re fighting for is the hearts and minds of average Canadians. That’s who is going to decide whether we should have the trust to develop the resource. It’s not going to be radical environmentalists. You don’t demonize those people. You work hard and earnestly to respond with the facts. This is the first time Alberta has been global news. We have to develop coherent strategies to deal with that.

A new frontier is emerging for work-starved western Canadian oilfield contractors. Look to Quebec and the Maritimes for the next expansion of natural gas production, say business and government participants in an embryo eastern branch of the energy industry.

Lower Canada and the East Coast have so few services that Quebec City-based Junex Inc. has reverted to Alberta’s all but forgotten pioneer era. The exploration and production firm operates its own drilling rigs. No contractor was available for gas wells along the St. Lawrence River by Junex and partner Forest Oil Corp. of Denver.

The drilling is speculation on an infant development prospect, Junex chief operating officer Peter Dorrins admitted at a 2009 annual fall investment fair held by the Small Explorers and Producers Association of Canada. But the payoff could be big if new techniques for tapping gas in dense rock can be transplanted to the Quebec target, the Utica Shale geological formation, he added.

The budding Quebec gas scene has economic attractions that financial analysts and industry leaders described as sorely missing from Alberta at a gloomy 2009 fall annual meeting of the Petroleum Services Association of Canada (PSAC). Eastern production fetches a price premium of about $1 per thousand cubic feet on vast markets along the Atlantic seaboard of the United States because it does not have to pay stiff tolls to travel thousands of kilometers through pipelines, said Dorrins. And Quebec’s gas royalties top out at 12.5 per cent, with no sign of any provincial plans to raise the rates, he reported.

At home in Alberta, the 270-company PSAC foresees stagnation this year due to low gas prices and slow progress on replacing 2007 provincial royalty hikes with a regime more suited to changed energy markets. The association predicts only about 8,000 wells will be drilled across Western Canada in 2010. The bleak outlook calls for a repetition of 2009, with western Canadian activity stagnating at one-third of the record 24,666 wells in 2005 and most of the losses concentrated in Alberta while the smaller British Columbia and Saskatchewan industries perk up.

The action represented by Junex, although still tiny by Alberta standards, shines a ray of hope that new outlets might develop for underemployed western contractors. The Quebec City firm alone has 24,375 square kilometers of eastern mineral rights, and its holdings are in turn only a fraction of the new eastern energy frontier.

Wells and associated sources of demand for oilfield services could eventually multiply in a geological region that sprawls across an area about 40 per cent of Alberta’s total size, suggests the nation’s earth sciences agency. There will be no shortage of fresh, large drilling targets as exploration spreads out east of Montreal, says a report by the Geological Survey of Canada (GSC).

The new resource assessment is a bulky, densely technical document by seven specialists that has nevertheless become an instant GSC bestseller. The report points to high potential across 250,000 square kilometers of sedimentary rock deposits beneath swaths of Quebec, New Brunswick, Nova Scotia, Prince Edward Island, Newfoundland, the Gulf of St. Lawrence and Cabot Strait.

In the black gold rush that followed the 1947 Leduc discovery south of Edmonton, D.H. (Derry) MacFarlane and his peers stopped short of killing for oil. But taking chances on succumbing to exposure or dying in road, snowmobile and airplane accidents went with their turf.

“I was thinking all the time, ‘I’m going to freeze to death,’” MacFarlane recalled as he reminisced about his youth as an industry pioneer at a Calgary meeting of the Canadian Petroleum History Society. He paid plenty of dues while rising to the top of his professional ladder, where he served terms as president of the Canadian Oil Scouts Association and, eventually, the International Oil Scouts Association.

MacFarlane also accepts a blunter word for himself and his occupational peers: spies. Industrial espionage was a fixture of the exploration era. Until the late 1970s, swaths of Alberta – with an area 95 per cent as big as Texas but only 15 per cent of its population – were terra incognita for oil and gas hunters. Fresh gushers were still to be had. Rivalry for prime drilling targets was fierce. Companies watched one another for clues that untried patches of mineral rights – “land,” in industry jargon – were worth bidding on at fortnightly provincial auctions.

Alberta let explorers keep well results secret for two years as “tight holes.” But drilling rigs were too big to hide and exhibited telltale signs of discoveries or failures. Scouts staked out wells, watching the action with telescopes and binoculars. Depths could be deduced, for instance, by counting standard-length pieces of drill pipe that crews hauled up to change bits. Use of some equipment – such as geological core sampling devices or production testing gear like tanks and flare stacks – was a dead giveaway of a discovery.

Nature made the stakeouts dangerous. In the exploration heyday, as now, most drilling waited for winter to freeze northern mud and muskeg swamp hard enough to support heavy machinery – and potentially congeal a spy’s blood.

Espionage was so common that the industry evolved an institution to save on spying time, costs and personal risks. Scouts held weekly meetings called checks to swap status reports on routine wells that only extended or developed known discoveries.

But oil companies kept rights to hold back information on fresh exploration by designating wells as tight or “wildcat” throws of investment dice. The secrets were duly noted as dares to venture out for frigid vigils at remote drilling sites.

MacFarlane had two brushes with hypothermia. Both were lethal reality versions of Jack London’s classic 1902 short story, To Build a Fire, about a Klondike gold prospector who froze to death because a small mistake out in the Yukon cold left his fingers too numb to light a match.

By Cindy Chiasson

Give yourself a few minutes’ break to indulge in a little imagination. Picture yourself as a member of one of the most influential regulators in Alberta: the Energy Resources Conservation Board (ERCB). Envision yourself seated at the front of a hearing room, listening to evidence from industry and landowners on proposed oil and gas projects. You have power. There is potential for you to affect the direction of Alberta’s future.

Now bring this picture into a bit tighter focus. Add to it the need for you to hear and weigh this evidence in order to meet the duty the provincial government has given the ERCB – to decide whether proposed projects are in the public interest. How hard can that be?

You may be surprised to discover that making decisions in the public interest is harder than it appears. Research has shown that the public interest can be defined in many ways. Academic theories have defined it as any interest common to all members of society, the interests of the majority, a balancing of competing interests, a determination based on the “best” ethics or science, shared values held by most of society, or any decision arrived at by following an appropriate process. There are also those who suggest that the public interest is meaningless as a concept because it cannot be defined.

In most jurisdictions where the public interest must be considered, government has put guiding principles in legislation to assist decision-makers. Many commentators agree that there is no one expert, person or organization that can bring forward the full range of views and values that are relevant to assessing the public interest. As a result, an important part of making public interest determinations is to hear from a wide range of interests.

As an administrative tribunal, the ERCB receives all of its powers and authority, as well as the limits of its decision-making, from legislation created by the provincial government. The Energy Resources Conservation Act created the ERCB as Alberta’s energy regulator. That bill gave the ERCB the duty, when holding hearings on proposed projects, to decide whether those are in the public interest, taking into consideration social, environmental and economic effects. Based on that limited direction, which is long on goals and short on details of how to achieve them, it is up to the ERCB to determine the public interest.

Now step back into your imagination. Given the limited direction and broad discretion the ERCB has, as a board member are you hearing all the voices, viewpoints and values you need to help you decide whether the proposed projects are in the public interest? The primary goal of corporations is to make money for their shareholders. Can industry operators fully and fairly provide all the evidence required to help you decide on the public interest? Does economic benefit automatically ensure social well-being and environmental protection? Landowners near proposed energy developments have a wide range of concerns including possible effects on their property values, health and businesses, particularly where agricultural operations are involved. Are their concerns and the evidence they may provide extensive enough to help you determine whether a project is in the public interest, or are their concerns mainly personal in nature and not necessarily representative of Albertans as a whole?

By Jeff Lewis

Trade shows are invariably rife with opportunities to network. There are the lunches, innumerable coffee breaks and proverbial keynote addresses to navigate, not to mention the endless array of booths showcasing the latest in industry wares. Circuit veterans are doubtless wise to the best meet-and-greet tactics, but there are times, too, when chance run-ins prove as valuable as orchestrated encounters.

“I meet the best contacts sometimes in the elevator on the way to my room,” laughs John Jurcik.

For Canadian supply chain firms looking to get in on Alberta’s oil patch, few events offer a better point of connection than Edmonton’s National Buyer/Seller Forum (NBSF). As president of Venshore Mechanical of Thunder Bay, Ont., and chair of the Thunder Bay Oil Sands Consortium (TBOSC), Jurcik speaks for 22 companies from the northern Ontario industrial hub. He’s direct about the NBSF’s role in connecting project owners with would-be service suppliers.

“It’s extremely important,” he reports. “And I think even last year when everybody was hit with the slowdown, we thought it was very important for us to be there, to show we’re there to support the western provinces.”

Hosted jointly by Canadian Manufacturers and Exporters and the Alberta government, the NBSF has long been a mainstay on the trade show circuit for oil sands players. This year is the forum’s 10th anniversary, and it marks the fourth year that out-of-province businesses have taken part. For organizers, the anniversary is an auspicious milestone in challenging times.

Indeed, the 2010 theme, The Maturing of the Oil Sands, is a far cry from even 2007, when the NBSF website implored companies interested in the bitumen belt to “Get your piece of the action.”

Today, it’s no surprise that economic imperatives have changed. Forecasts were turned on their head following the price collapse of 2008. For supply chain companies – the steel fabricators, welding outfits, and value-added engineering, procurement and construction firms that regularly attend the NBSF – the fallout was characterized by a drastic scaling down of operations, says Grant Hammond of the Hammond Group. In some cases, he notes, it meant bankruptcy.

“It was a tough, pivotal year for suppliers,” the consultant says, with a touch of understatement.

Yet 2010 could be a turnaround year. Hammond, the organizational head behind the NBSF’s speaker series and thematic planning since its inception, says the 2010 outlook reflects a new reality in oil sands activity: incremental growth in smaller stages. For supply side firms, that means an emphasis on maintenance, repair and operations (MRO), a market opportunity with a potentially large payoff. “I know a couple of plants that have $10 and $12 billion MRO budgets, and people don’t see that instantly,” Hammond notes. “Some do, but the masses don’t. It’s becoming a bigger factor.”

The 2010 presenter lineup includes representatives from ConocoPhillips, Cenovus Energy, Suncor and Imperial Oil. Calgary-based FT Services will also be on hand, along with supply chain innovator Exel.

A shift from years past lies in the increased presence of so-called green firms, among whose ranks will be Enhance Energy Inc. The Calgary-based company is engineering the Alberta Carbon Trunk Line (ACTL), the province’s first tangible foray into enhanced oil recovery and large-scale carbon storage. “We support the forum,” declares Susan Cole, the green outfit’s president. “[The trunk line] will play a part in supporting the ongoing development of the oil sands … and will be utilizing many of the same companies that work on oil sands projects.”

Companies like Enhance were scarcely on the NBSF radar back in 2000.

The NBSF began as a joint venture between CME and Alberta Economic Development (now Alberta Finance and Enterprise.) At the outset, the conference attracted roughly 200-250 people and rotated between Edmonton and Calgary. But as the oil sands garnered national – and increasingly international – attention as a resource play, Hammond says smaller, supply chain firms (the homegrown fabricators, welders, etc.) couldn’t cope with the startling rate of growth that came with increased exposure.

“Nobody in the world at that time had developed projects of this size,” he points out, noting that project owners, too, were caught flat-footed as investment in the oil patch ramped up. “They thought they had the project management experience, but in fact it proved somewhat tenuous. If you have 4,000 electricians and 5,000 boilermakers on a site at the same time, it doesn’t really work. And they had to live through that experience to find that out.”

Cue the NBSF. In its earliest incarnation, the conference was something of an industrial matchmaker. The idea was to get supply firms and project owners working collaboratively. As the oil sands expanded, so too did the scope of the forum.

• Husky Energy Inc. is proceeding with its $2.5 billion Sunrise oil sands project in northern Alberta. The firm announced Jan. 20 that it had completed front-end engineering and design work for the project’s first phase, which company officials say will yield 60,000 barrels per day using Steam Assisted Gravity Drainage (SAGD) technology. Well pads are being built and site prep for central facilities continues, with construction anticipated to start in the second half of 2010. Phase 1 production will begin in 2014. Husky estimates Sunrise contains 3.7 billion barrels of proven reserves.
• Total E&P and ConocoPhillips Canada announced Jan. 19 that the second phase of the Surmont oil sands project is moving ahead. Initial construction will begin in 2010. Gross production is pegged at between 27,000 and 110,000 barrels per day using SAGD technology. Phase 2 won’t begin production until at least 2015. It’s expected Surmont will yield 2,500 construction jobs and 300 permenant operating positions.
• Despite fears of renewed labor shortages, Canadian Natural Resources Ltd. has given a green light to its Horizon and Kirby projects. The Horizon mine began producing last year and is expected to ramp up to 110,000 barrels per day. CNR expects Kirby, yet another in situ operation, to produce 45,000 barrels per day, but it must first gain regulatory approval.
• Meanwhile, Royal Dutch Shell, in spite of acitivty at Scotford and its Muskeg River Mine, was labelled a black sheep after the company signalled it would look to conventional energy projects for new production. Plans to scale oil sands production from a 250,000 bpd outlook to 700,000 bpd have been shelved. Still, the firm is seeking regulatory approval to expand operations (from 12,500 bpd to 80,000 bpd) at Carmon Creek north of Peace River, the Edmonton Journal reports. Following the pullback, Calgary Herald columnist Deborah Yedlin argued Shell was out of step with the oil patch.
• Suncor is moving ahead on Firebag 3, another in situ effort. Work is also progressing on the first stage of ExxonMobil and Imperial Oil’s $8 billion Kearl megamine.
• A smaller firm, Calgary-based Osum Oil Sands Corp., is seeking regulatory approval for a 35,000 bpd in situ project in Cold Lake.

Canada’s biggest energy company, Suncor Energy Inc., posted a $457 million profit in the final quarter results from 2009, the Globe and Mail reports.  The figure is below analyst expectations, but improves on a net loss of $215 million in the fourth quarter of 2008.

Suncor CEO Rick George said the firm will continue to shed assets (between $2 billion and $4 billion) in 2010 following its merger with Petro-Canada last August. The company earned 29 cents per share in the final three months of 2009.

The results follow news that Canadian Oil Sands Trust, which boasts the largest stake in a Syncrude Canada Ltd. oil sands partnership, suffered a 23 per cent drop in fourth quarter profit over 2008 results. The profit slide comes amid oil prices that averaged $76.13 U.S. throughout the quarter.

The Obama administration is championing a net-zero appraoch to emission reduction legislation, the NY Times reports. A climate bill currently making the rounds would increase government revenues by $873 billion through 2019 but would cost $864 billion to implement.

Revenue would stem from the auction of carbon credits. But, the Times points out, the government has yet to fully endorse a cap-and-trade system for reducing emissions, and it remains unclear  how emission allowances would be divided or what percentage of credits would be auctioned.

The president’s address also included an olive branch for Republicans favoring nuclear power and increased offshore oil exploration. Whether or not nuclear enters the climate debate in a significant way remains to be seen. In Alberta, the greenest power of them all remains in limbo, although a new report from the University of Alberta’s Environmental Research Studies Center has attached a $9.4 billion price tag to the Bruce Power proposal in Peace River.

Gordon Kelly has been in training for all 75 years of his life for the advocacy role he takes on as author of The Oil Sands: Canada’s Path to Clean Energy? He was born into the officer class of the global energy industry.

An international oil company built Kelly’s birthplace – Talara, on the Pacific coast of northern Peru – as a refining and shipping port for wells dating back to 1850. Use of surface seeps that attracted the industry has an even older pedigree. Early Spanish seafarers caulked wooden sailing ship hulls with boiled tar skimmed from pits dug into foothills of the nearby La Brea Mountains.

His father, T.D. Kelly, worked in the Peruvian seaport for Imperial Oil before the Second World War. At the time, the Canadian firm doubled as a foreign expansion arm of its majority shareholder, the ancestor of ExxonMobil Corp.

After wartime service as a naval captain, the elder Kelly moved the family to Canada and helped launch the modern Alberta industry as manager of Imperial’s transportation department. The son joined Imperial after earning an engineering degree in Toronto. Kelly also obtained an MBA from Harvard University, but not before he got his hands dirty learning industry ways.

Until the mid-1970s, Imperial owned drilling rigs and put freshly hired engineers and earth scientists through rugged basic training on them. Kelly’s 1956 rig classmates included the late Bill Hopper, going through his industry baptism by labor with Imperial two decades before he rose to national fame as chief executive officer of Petro-Canada.

Kelly attained prominence as planning manager of Dome Petroleum, a 1970s household name that rivaled Hopper’s federal government-owned national oil company as a driving force of Canadian corporate takeovers and frontier drilling. Kelly unsuccessfully opposed the final takeover that eventually bankrupted Dome, and then switched into international consulting. He has worked in 24 nations for private and state clients including the Organization of Petroleum Exporting Countries.

Kelly poured about three years of work into his 324-page book, hiring Calgary contractor Kingsley Publishing for editorial, printing and marketing services. He rapidly attracted an industry following, selling about 1,000 copies or one-fourth of the initial press run before its official launch in Calgary last November.

Kelly voices the often espoused philosophy of Alberta engineers and managers that knowledge is power and accurate information changes minds. Facts can effectively counter emotionally tinged enviro-political campaigns pressing for a halt to oil sands development, Kelly insists.

“The strength of this is it doesn’t take sides,” he says, holding up a copy of his book. The author says he worked overtime on purging his text of personal feelings. The tone is cool. The oilman-author does not rant. He does not hesitate to discuss industry flaws.

Source: World Bank

Source: CIPEC

Source: Alberta Energy Research Council

Source: International Labour Organization

By Graham Chandler

In a modern building on Research Road, the northern edge of the University of Calgary campus, the groves of academia meet the outside world. It’s a fitting location for Gushor Inc.

The firm is young, entrepreneurial and designed to make commercial items out of advanced and groundbreaking research done by teams of university professors and graduate students. The target market is the oil and gas industry. The chief executive officer unites business and scholarship. Steve Larter is also a U of C professor and scientific director of Carbon Management Canada, a new national “center of excellence” endowed with a $25-million federal government grant. IBM is far older and bigger but its immaculate downtown Calgary building, with its new age decor of rich symbols highlighted by Spartan brightness, gives visitors a feeling of entering a laboratory. Both IBM and Gushor work on technology aimed at improving efficiency, productivity and cleanliness.

“In our starting phase, Gushor is sort of an incubator of the university,” says Larter. “We get use of this facility, office and some lab space. The idea is that if it succeeds, we will be out in a proper commercial center.” He won 2009 kudos like the trophy for outstanding commercial achievement at the Alberta Science and Technology Awards and election as a fellow of Britain’s Royal Society. But Larter feels a little frustrated by slow market acceptance for some of his programs on the cutting edge of the emerging next generation in oil sands production, steam-assisted gravity drainage, or SAGD for short. It seems no one wants to be the first adopter.

“Our take on it is we need a revolution,” he says. “And it’s not just a technical revolution. It’s almost a social revolution in how we deploy technology, probably 50 per cent technical and 50 per cent structural.” He says this need is not necessarily restricted to Alberta’s economic mainstay. “But it’s most crucial in the energy industry. Carbon is on everyone’s mind and it looks like a pretty big problem. Even if we had technologies that could solve that problem today, if you look historically at the rate new technology replaces old, it won’t happen fast enough. If you want to meet our targets made today, you’ve got to replace technologies in 40 years. If you look in the past – coal replacing wood, oil replacing coal – to achieve 80 per cent adoption, you’re looking at the end of the 21st century.”

Larter’s ideas are advanced even for oil sands professionals, who take pride in calling their field the industry’s technical frontier. His research interests lie in the production of heavy oil, petroleum biodegradation and the deep biosphere. The recent focus of his research is in novel uses of petroleum reservoirs as in-situ or underground refineries, where native microorganisms can be harnessed to speed up natural processes of oil and gas formation to recover as methane or hydrogen rather than heavy oil. The ultimate goal of such visionary work is emission-free energy production from bitumen deposits.

“We’ve got these complex reservoirs that to get anything out of is an achievement,” he says. “And, basically, SAGD today doesn’t look that different from 1981 [when the concept took form]. Why isn’t it different? Why don’t we have 20, 30 or 50 technologies competing for the one that’s going to give us zero emissions? In that sense, you have to say there has probably been a market failure of innovation in the energy industry.”

Larter blames some of the lack of progress on the competitive intellectual property (IP) environment of oil patch research. “The patent system tends to force everybody into kind of a monopoly position, yet they all face the same problems,” he says. “They’ve all got complex reservoirs and know it is a difficult thing to do. And yet they’re all trying to do it by themselves.” He contrasts the prevailing regime to other industries like pharmaceuticals, which use patent pools to seek common objectives. “And with software there are no patents really – and people still make a lot of money. I think the IP model in the energy industry is particularly destructive. Everybody’s got their secret and no one’s sharing.”

He reckons the oil sands are ideal for a new IP regime because there are no exploration results to hide. The field is all about production and technology. He credits the surviving streak of secrecy to the industry’s roots as a hotly competitive hunt for the buried treasure of naturally flowing oil and gas reservoirs.

Larter likes the software industry model. “There’s a famous quote from Bill Gates to the effect that if in the early stages of the software industry we’d had to deal with patents, the industry would be at a complete standstill. They just used copyright and went to the do-it-faster-than-anybody else model. So you’ve had this explosion of technology, this explosion of competition that I don’t see in the energy industry.”

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Source: OPEC World Oil Outlook, 2009

Source: World Bank, Rising Food and Fuel Prices: Addressing the risk to future generations

Source: CERI

Profiles by Gordon Jaremko

Times turned tough. Talent stood out.

Alberta Oil’s first annual C-Suite Stars awards recognizes those individuals that proved to be capable of surviving, thriving and building platforms for future growth through events that few imagined to be possible until they happened.

As this year wore on, the shocks of the late-2008 energy price drop and global credit crisis faded but severe effects lingered. It has been survival of the fittest.

Within the context of this challenging year, the 2009 C-Suite Stars were selected based on observed trends and performances. This group of six emerged from qualified candidates.

The selection process started with recognition that there is far more to industry leadership than can ever be measured by quarterly financial statements. Alberta Oil bases its views on trends spotted with full-time daily tracking of developments revealed by an array of sources, from corporate disclosures and article interviews to regulatory cases and travel to industry operating areas.

Alberta Oil identified three key trends this year. First was the rise of resource plays, with the formerly little-known term coming into common use for a harvesting or manufacturing approach to producing energy commodities with advancing technology. Not surprisingly, there was also sharpened focus on economic efficiency as energy prices slid and showed signs of staying well down from 2008 highs for the foreseeable future. Finally, the industry responded to a growing emphasis on adapting to increasingly sensitive natural and human environments.

As the inaugural C-Suite Stars demonstrate, the fittest can do more than survive – they can excel.

Encana’s CEO is transforming the gas industry’s M.O.

Randy Eresman’s enthusiasm is infectious. Zest breaks through the professionally reserved exterior of the petroleum engineer in the chief executive officer’s suite at EnCana Corp. when he talks about the future his teams are building.

The example set by EnCana’s rise to the top among North American natural gas producers – a stature highlighted by the Eiffel Tower-like steel frame under rapid construction for the firm’s new 58-storey headquarters and Calgary’s tallest skyscraper – is changing the structure and vocabulary of the energy industry. Enter resource plays.

“We now call them gas factories,” Eresman says in describing the new M.O. The old standard method of operating prompted previous generations of trend-setters to call themselves hunters and coin the word explorationists. The new pattern has industry leaders billing themselves as manufacturers.

The old way was a secretive pursuit of wealth needles – scattered fossil fuel deposits concentrated by natural pressure on porous rock formations into pools that flowed at the touch of drill bits. The new approach harvests entire geological haystacks by using advanced technology to extract resources embedded too tightly in dense rock to flow except through artificial capillary webs of man-made channels.

Instead of derricks built in portable pieces that spend much of their time roving around widely dispersed targets, the new M.O. is evolving fit-for-purpose rigs that work around the clock at fixed locations. In a resource play, ownership is acquired over a big block of rock saturated with fossil fuel. A stable pad or working surface is built. Self-propelled rigs that swivel and move short distances, akin to robots on auto assembly lines, drill potentially dozens of kilometers-long horizontal wells across the geological formation. Multiple “fracs”, or injections of fluids under extreme pressure, fracture myriad flow channels into tightly grained rock by breaking it up the way a sudden impact shatters a safety glass window.

“You gain amazing efficiency by not moving equipment,” Eresman says. Along with the specialized drilling rigs, truck-mounted frac pumping equipment stays on location and uses low-cost deliveries of bulk materials. Sites are organized and lit up to run safely around the clock seven days a week. Operating services such as pipelines, power supplies, instrument arrays, control systems and crew quarters are large and concentrated with their costs spread thinly over high production volumes. Environmental effects are reduced compared to the old pattern of widely dispersed wells, spiders’ webs of long but small-diameter pipelines and scattered processing plants.

EnCana uses the new approach in Wyoming and Texas, and is transplanting it into Canada, initially at northern British Columbia’s Horn River shale gas deposit. The new industry M.O. is tailor-made for the long-range market outlook that overtook the old hunting methods in 2009. “A lot of our industry has been inspired with the idea of ever-rising energy prices,” Eresman recalls. “This new strategy works well with flat long-term prices. We think natural gas will be constrained in a narrower and lower range than we used to believe in.”