Illustration by Kelly SutherlandIt was a spring William Andrew would prefer to forget. Wildfires that razed the northern Alberta town of Slave Lake did not leave nearby oil installations unscathed. For Calgary-based Penn West Exploration, the blaze came just as southern Saskatchewan and Manitoba were inundated with severe flooding.
In the span of a month, roughly 20 per cent of the firm’s daily production was shut in because of natural disaster. “On an annual basis, it will be about a 4,000-barrel-per-day hit,” says Andrew, who stepped down as Penn West’s chief executive in August. By July, the firm was still taking stock of nature’s fury. “We have far-flung operations in Western Canada,” Andrew says. “We have production that continues to be shut-in in Manitoba and Saskatchewan with flooding. We had the wildfires in and around the Slave Lake area that limited our ability to produce anything for over a month.”
The Slave Lake saga highlights a recurring theme of life in the oil patch: the business rarely stands still. Not only are commodity prices volatile, but reservoirs that appear spent can reveal new riches just as today’s technology can quickly become old hat. “It’s not a game for boys in short pants,” Andrew puffs. “It’s a commodities game, and our investors know that. You try to de-risk it as much as you can, but at the end of the day, there are things you can’t control.”
Until recently, variables outside of the industry’s control did not include pipeline expansions. But controversy over TransCanada Corp.’s Keystone XL expansion, Enbridge Inc.’s Northern Gateway pipeline and even Kinder Morgan Canada’s phased expansion of its half-century-old Trans Mountain Pipeline system have exposed Alberta’s petroleum producers – in the oil sands but also in conventional reservoirs – to a new level of risk.
[Related: Analysis: Oversight would bolster oil sands exports]
The growing bottleneck at Cushing, Oklahoma, has already pinched producers’ bottom lines. Record storage levels at the Midwest trading hub mean barrels of benchmark West Texas intermediate crude now regularly trade at a discount to international varieties like North Sea Brent. Economists say Alberta, along with the federal government in Ottawa, are both forfeiting substantial tax windfalls because the country is beholden to a single customer whose appetite for crude oil has reached a plateau.
The trend, although not as dramatic as a wildfire, could prove far more costly than economic damage inflicted by natural disasters. Building takeaway capacity – that is, new pipelines – to handle production volumes expected out of the Western Canadian Sedimentary Basin has quickly emerged as a serious challenge for industry participants. Enbridge Inc. now regularly casts its $5.5-billion Gateway project as a national endeavor. That was the message delivered at an industry forum in Edmonton by Kent Cornelius, vice-president with the firm’s major projects division. In a presentation at the city’s Shaw Conference Centre, he compared the controversial export line to construction of the St. Lawrence Seaway, calling Gateway a “highly strategic project for all of Canada.”
It’s easy to see why. Canada’s natural wealth – which comprises land, timber and known reserves of energy and natural resources – stood at $3 trillion in 2009, Statistics Canada reported in June. The value has tripled since 1990, due in large part to higher oil prices. Crude bitumen locked in the oil sands region was worth $19 billion in 1990, representing about 13 per cent of the country’s resource wealth. By 2009, the value had skyrocketed to $441 billion – more than the combined value of the country’s reserves of coal, crude oil and natural gas.
Pipelines are a linchpin in realizing that wealth. Alberta Energy Minister Ron Liepert has repeatedly raised the alarm about the province being stuck with “landlocked” bitumen if projects like Gateway and Keystone XL, which would shuttle 700,000 barrels per day of oil sands crude to refineries on the United States Gulf Coast, are unduly delayed. At stake are growth projections that see oil sands production hitting 2.2 million barrels per day by 2015 and rising to 3.7 million barrels daily by 2025, and the royalty and tax windfalls that come with increased field activity.
[Related: Three pipeline builders race to reach new markets]
The risk was flagged again in a mid-summer medium-term review of oil and gas markets conducted by the Paris-based International Energy Agency (IEA). Growth in the oil sands and in U.S. “tight” oil plays “depends on the timely completion of new transport infrastructure,” the IEA warned, singling out TransCanada Corp.’s Keystone project. Daily production of one million barrels from the oil sands plus another 200,000 to 300,000 barrels from the North Dakota Bakken formation “risks being stranded if pipeline delays materialize,” the IEA said.
The prospect of pipeline bottlenecks curtailing oil sands production is an issue the industry’s main lobby group has only begun to address. “How we reconcile what’s in the broader public interest in energy development with the local communities is important,” says David Collyer, president of the Canadian Association of Petroleum Producers. “Part of that story is the economic benefit that flows to communities as a result of oil and gas development.”
That narrative carries a particular resonance for the government of Alberta as it begins to work on slaying a $3.4-billion deficit, only recently slashed to a forecast $1.3 billion. Bitumen has replaced natural gas as the province’s revenue-generating star as tides of shale gas unlocked across the continental United States undercut Alberta’s exports. But Alberta Minister of Finance and Enterprise Lloyd Snelgrove suggests any delay in delivering oil sands output to new markets is also a threat to the national economy. “The reality is you cannot just look at the oil sands from the environmental point of view without the balance of the economic benefit to the rest of this country,” he says.
Steel Resolve
The race to break a storage bottleneck heats up
[Related: Looking beyond TransCanada’s summer of discontent]
TransCanada Corp. is not the only firm with blueprints to link Cushing, Oklahoma, with refineries on the Gulf Coast. The Calgary-based company is still awaiting approval for its $7-billion Keystone XL expansion from the United States Department of State.
Pipeline operators, perhaps sensing there is money to be made by opening an outlet to refineries in Texas with a less high-profile project, are lining up to break the storage glut at the Midwest trading hub, where more than 42 million barrels of crude oil sat in terminals at the onset of the summer driving season.
Fewer than 100,000 barrels a day of western Canadian crude oil – the bulk of it carried on the Pegasus pipeline owned by ExxonMobil Corp. – currently finds its way to the Gulf Coast refining corridor. The region is viewed as a major growth market for Canadian heavy oil as U.S. imports of Mexican Mayan crude and Venezuelan oil dwindle.
At the outset, the southern leg of Keystone would shuttle 150,000 barrels per day from Cushing to refineries around Port Arthur, Texas. If approved, the Keystone expansion could ultimately transport 700,000 barrels per day south from Hardisty, Alberta.
TransCanada says it has secured firm commitments for 380,000 barrels per day under long-term contracts from shippers along the pipeline expansion. What follows is a brief look at various proposals to deliver crude to Gulf Coast refiners from the Midwest storage hub.