Change has come swiftly to Canada’s energy industry through the first decade of the new millennium. Abundance has replaced scarcity as new technologies have unlocked vast supplies of once-inaccessible reserves of natural gas and oil. It is a story that will define the next decade, shaped by innovation and ingenuity, market access, big builds and environmental anxiety. What follows are four themes you can expect to hear more of in 2012.

Illustration by Michael Byers

Innovative In Situ

Breakthrough ideas can sometimes fail spectacularly. Opti Canada Inc. learned that the hard way. Difficult reservoir conditions at the firm’s Long Lake joint venture with Nexen Inc. caused serious problems for the firm’s novel OrCrude upgrading technology, exacerbating debt woes that ultimately sunk the company and led to its purchase by CNOOC Limited last summer for $2.1 billion.

The specter of Opti’s collapse has not gone away. It hangs over Ivanhoe Energy Inc., which remains a risky bet among investors in part because of technical and economic uncertainty surrounding the planned use of an untested heavy-to-light upgrading technology at its Tamarack oil sands development. “There’s a lot of appeal to companies that don’t try to use new technology,” says Mark Friesen, an analyst with RBC Dominion Securities Inc.

Compounding the perceived risk is the fact that both Long Lake and Tamarack – which has yet to be sanctioned by Alberta’s Energy Resources Conservation Board – rely on in situ, thermal processing techniques to melt and thin bitumen before pumping it to the surface. More than three decades after its birth as a curiosity pioneered by the Alberta Oil Sands Technology and Research Authority, the production technique does not easily accommodate revolutionary change.

“This is the toughest production in the oil business,” says Dick Gusella, chairman and chief executive officer with Connacher Oil and Gas Ltd. Incremental advances are another matter entirely. “These things are all big capital, long time frames, and so anything you can do to enhance the rate at which [you can] get these wells to produce is important – so long as you can do it economically.”

Connacher did not hesitate this fall to describe trial results of a solvent-steam application at its Algar oil sands project as a breakthrough. “The outcome warrants the adjective we assigned to it,” Gusella says.

Indeed, daily average bitumen production at two wells undergoing tests increased 23 per cent. Use of solvents also cut the average steam-to-oil ratio by 15 per cent for the duration of the 12-week trial. That means 85 per cent of the solvent injected underground in concert with steam was recovered – a key metric given the production technique’s higher costs. “That’s fundamental to its success,” Gusella says. “Solvent is at the far end of the price curve. It’s the Brent of the oil business, the equivalent of diluent or condensate.”

Another trial using the steam-solvent application, which the company has trademarked SAGD+, was carried out through the fourth quarter. Gusella says the technology represents another step in the long-running commercial evolution of so-called drillable oil sands. SAGD is now widely forecast to eclipse traditional Fort McMurray-area strip mines as the number one means of production by the middle of this decade. Forget proof of concept, in other words. And say goodbye to commercialization. “This,” Gusella says, “is the age of innovation.”

Western Shores

David Pryce skipped over a slide in his PowerPoint presentation highlighting what many at a fall gathering of shale gas advocates in Calgary already knew: natural gas prices are low, and poised to stay that way for the foreseeable future. “I don’t want to depress us too much,” the vice-president of operations at the Canadian Association of Petroleum Producers said, jumping ahead in his prepared remarks.

He nevertheless went on to describe the central predicament faced by natural gas producers in Western Canada. The rapid proliferation of shale gas in basins closer to the burner tip continues to eat away at their traditional share of the U.S. export market. “We’re now at the far end of the pipe in terms of supplying the marketplace,” Pryce said. “We’re having huge challenges in competing with those markets.”

Across town that morning, Ken Fung offered a paint-by-numbers portrait of the pain to a conference organized by the Canadian Society for Unconventional Resources. Since 2007, American shale gas production has surged by over 15 billion cubic feet (bcf) per day to account for nearly 35 per cent of the country’s total supply portfolio. Fung, associate director of North American gas with consultancy IHS CERA, said the growth is equal to Canada’s dry gas production on an annual basis. “It’s a sharp contrast to Canada’s decline [in conventional production] and it’s happened in a relatively short period of time,” he said.

Canadian gas exports to the U.S. have declined “significantly” as a result, from an annual average of nine bcf per day as recently as 2005 to just under six bcf per day in 2011. Fung said the drop has been especially precipitous in eastern markets that increasingly draw gas from basins like the massive Marcellus shale, where estimated potential reserves top 300 trillion cubic feet. In 2005, western exports to eastern markets averaged three bcf per day. Today, “They’re almost nothing.”

The vanishing act is one reason interest in reaching Asia-Pacific markets goes hand-in-glove with developing Canadian shale reserves. “We need to be diligent around and very much aware of the market circumstances as we look at developing this resource,” Pryce said. Four proposals to liquefy and ship gas from Canada’s West Coast to markets in China, Japan, Taiwan, South Korea and India are at varying stages of development.

China alone is expected to account for “significant LNG demand growth,” Fung said, as officials look to fulfill a mandate contained in the country’s most recent five-year plan to build more gas-fired electric generation capacity, 80 per cent of which comes from coal today. A significant hurdle remains cost. LNG projects are “a niche build,” Fung says. With more than 20 bcf per day of supply potentially on order books in Australia, construction costs in Canada could climb rapidly. “The cost escalation from that standpoint could be huge.”

Moving Liquids

Like an old house in need of new plumbing, North America’s pipeline industry is in line for a dramatic overhaul as regional flow patterns change and infrastructure expands to deliver previously untapped supply sources to new markets.

Ground zero for the capacity additions is the prolific Bakken formation in North Dakota, where producers of shale oil are flaring commingled natural gas for want of available infrastructure needed to move the stuff to processing hubs. “In some of these remote locations, there’s no infrastructure out to the well and there’s probably no electricity either,” says Murray Birch, president and chief executive of Alliance Pipeline Ltd. “They’re flaring because there is no other option.”

Cue Alliance’s Tioga Lateral Project, a 77-mile (124-kilometer) pipe with initial capacity to bring 120 million cubic feet of natural gas per day east from the Williston basin to connect with the firm’s mainline in North Dakota. Calgary-based Enbridge Inc. also hopes to lay pipe out of the region. An application for an expansion project that would move 145,000 barrels of Bakken crude oil per day north to connect with the firm’s half-century-old mainline in Canada is before the National Energy Board for the regulator’s review. The roughly 400,000 barrels of Bakken crude produced daily also underpins growth plans put forward by Plains All American Pipeline LP.

Leaving aside oil-related infrastructure, the U.S. Federal Energy Regulatory Commission says major projects announced between 2008 and September 2011 add up to 2,700 kilometers worth of new pipe capable of transporting a whopping 14.2 billion cubic feet of natural gas. The story is the same in the remote northeastern region of British Columbia, where midstream and gathering systems are needed to match production increases from budding shale development in the Horn River and Montney fairways. Plans are underway or proposed by TransCanada Corp. subsidiary Nova Gas Transmission Ltd., Spectra Energy, Enbridge Inc. and Apache Canada Ltd.

Enbridge alone expects to spend $1.1 billion to expand its Cabin Gas Plant, in which it acquired a 71 per cent stake from Encana Corp this fall. And at least a portion of the $4.5-billion capital outlay planned for the Apache Canada-led Kitimat LNG export project is earmarked for the proposed Pacific Trail Pipeline, itself needed to carry gas from Summit Lake to the coast for export as a supercooled product.

In all, the Canadian construction projects – including the hotly contested Northern Gateway pipeline and an expansion to Kinder Morgan Canada’s Trans Mountain Pipeline – add up to a potential $40-billion private stimulus package for an economy still experiencing sluggish growth, says Philippe Reicher, vice-president of stakeholder relations with the Canadian Energy Pipeline Association. “The interesting part about this is if you look at a pipeline project originating in Western Canada, it has some pretty significant national repercussions from an economic perspective,” he says. “A lot of the parts that are bought for various pipeline facilities are coming from Ontario or Quebec.”

“That’s a story that is not really well understood,” he adds. “It’s not even necessarily well understood in the energy-producing provinces.”

Green Peril

A previously unspoken truth about modern oil and gas development is beginning to find a voice. “Managing outrage has become an integral part of doing business,” Mike Dawson, president of the Canadian Society for Unconventional Resources, told an industry forum late last year.

The formerly ethereal idea that companies must obtain a “social license” in order to realize everything from large-scale development of shale gas in regions unaccustomed to fossil fuel activity to oil sands export visions has very suddenly taken on concrete dimensions. A key to understanding – and perhaps mitigating – the sort of anxiety increasingly encountered by shale developers lies beneath the thin veneer of NIMBYism blamed for sidelining TransCanada Corp.’s $7-billion Keystone pipeline expansion last fall.

Concern that a pipeline rupture would potentially foul the massive Ogallala aquifer, a shallow underground lake that spans eight states, was a rallying cry for project opponents throughout the regulatory saga. Water has likewise been at the center of public backlashes against shale gas.

“Hands up if you’ve seen a YouTube video of somebody lighting their tap water ablaze,” veteran pollster Bruce Anderson, senior vice-president with National Public Relations Inc., asked a room full of shale gas advocates at Calgary’s Telus Convention Centre last fall. Hands shot up. “That’s what I thought,” he said. “YouTube has probably had a more significant impact on the shale gas debate than just about any other issue I can think of, and I would assume that that’s going to continue to be the case.”

The medium, disruptive and unwieldy though it may be, does not dilute the message. Water handling is “a sleeping giant,” says Derek Brown, principal of Saanichton, British Columbia-based consultancy Strategic West Energy Ltd. and project manager for the Geoscience BC Montney Water Project.

Armed with a $1-million budget, Geoscience BC is working hard to ensure the giant doesn’t wake up. The industry-government agency has been compiling a water inventory of the remote gas play since 2010. The project’s first phase was completed this fall. It involved collecting, analyzing and interpreting data on surface water, shallow-and deep-bedrock aquifers and disposal zones. Assessments were also carried out to better understand the availability of non-potable, deep saline aquifers as a water source for hydraulic fracturing operations.

The difficult work arguably lies ahead. Anderson notes a “huge gulf” exists between the language spoken by engineers and industry specialists and a public increasingly swayed by rhetorical arguments that appeal to emotion above all else. One way to narrow the gap involves assembling “the best available science” and presenting it in a way that is accessible to the public. “You can’t whitewash,” Anderson advises. “You need to deal on the level of what it is that people are concerned about.”

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