Export plans fuel an old fight in the oil sands
Two visions for Alberta's value added future garner mixed support
Shell Canada recently marked a 100,000 barrel expansion at its Scotford upgrader
Photo courtesy Shell Canada
Shockwaves buffeting international markets did not faze John Abbott. One day after news of a planned release of emergency reserves of crude oil leaked from the Paris headquarters of the International Energy Agency (IEA), temporarily halting a mid-summer bull run in oil prices, the executive vice-president of heavy oil at Shell Canada Ltd. stood amid jumbo tanks and steel pipes at an industrial complex northeast of downtown Edmonton looking preternaturally calm. “The fluctuations in the short term don’t concern us because the long-term fundamentals, I believe, have not changed,” he said, following a formal ceremony that marked a twofold expansion of capacity at the firm’s Scotford upgrader.
For the third time in its 38-year history, the IEA was opening the valves on strategic warehouses of crude oil created amid the fallout from the 1973 oil embargo. Addressing reporters in a hastily arranged teleconference, Richard Jones had one day earlier dismissed suggestions that the intervention was anything but a temporary move designed to offset some of the 132 million barrels of light, sweet crude lost to the Libyan civil war by the end of May. He refused to speculate about future intercessions in the global market. “A lot can happen in a month,” the agency’s deputy executive director said.
Far removed from the turmoil, Abbott was pleased. Under a brilliant blue sky, Shell had marked a 100,000-barrel-per-day expansion at its sprawling processing complex north of the Alberta capital city with an outdoor pep rally. The celebration capped five years of construction, which at its peak involved more than 10,000 skilled tradespeople, more than 30 per cent of them apprentices. Aboriginal drummers, together with provincial and federal politicians, as well as a former TV talk show host, heralded a significant corporate milestone at a smoothly orchestrated press event. Within a decade, daily capacity at the firm’s Athabasca Oil Sands Project, a joint venture with Chevron and Marathon Oil Canada that includes the Jackpine and Muskeg River mines, had grown from zero to 255,000 barrels. “We’ve really entered the big leagues,” crowed Michael Crothers, general manager of the firm’s oil sands and upgrader expansion.
The production target was hard won. Work on the plant extension defied the energy-price collapse and financial contraction that sidelined billions’ worth of oil sands growth projects. Largely isolated from revolution, civil strife and the resulting volatility that has shaken global markets for much of the past year, Abbott viewed the firm’s achievement through a narrow but long prism. “These are projects which exist for 40 years plus,” he said. “So of course today’s economics are important, but when we invest here we’re investing for the future; we’re investing for the long term.” Global energy demand is poised to double by 2050, he noted. As an integrated miner, refiner and chemicals manufacturer, Shell, he said, is well-positioned to meet the world’s needs. “The integrated value chain here is very important.” From biofuel to synthetic crude oil and gasoline, “We can deliver all of that within Alberta.”
In many ways, the Canadian arm of Royal Dutch Shell PLC is an anomaly. As producers eye new export markets, technology evolves to boost recovery rates and global benchmark oil prices hover close to $100, the integrated model of bitumen processing – the value-added activity championed by labor groups and successive provincial governments going back to Peter Lougheed – is once again showing signs of strain. Attendees at a summer forum designed to highlight and address emerging opportunities and some of the sector’s biggest challenges were left with two very distinct impressions of what the future holds for oil sands production.
The rift is not simply a rehash of the domestic jobs-versus-exports debate that characterized disputes between the Communications, Energy and Paper-workers Union of Canada (CEP) and the National Energy Board (NEB) over increased deliveries of raw bitumen to markets in the United States. Much has changed on the oil sands landscape since the CEP, a voice of plant, refinery and production workers from Fort McMurray to the Grand Banks of Newfoundland, fought the national regulator before the Federal Court of Appeal over the initial phase of TransCanada Corp.’s Keystone pipeline and Enbridge Inc.’s Alberta Clipper line.
The labor groups argued then that exporting the province’s crudest product – bitumen – sacrificed jobs by discouraging construction of multibillion-dollar upgraders for turning the raw ore into refinery-ready synthetic crude oil. The NEB rejected that view, but the board’s rationale for approving Clipper, which moves 450,000 barrels of crude per day from Alberta to Superior, Wisconsin, could yet be in for a challenge as calls to put oil sands bitumen on global markets beyond the U.S. grow more acute. “No intervenor or member of the domestic upgrading and refining industry expressed concern about the possibility of lack of access to feedstock,” the board said in approving the Enbridge line. “ … It would not be in the public interest to deny the project in order to make feedstock available to potential domestic upgrading and refinery projects that may or may not be realized.”
Value-added is a staple at Shell’s oil sands operations: “The integrated value chain here is very important,” says John Abbott
Photo courtesy Shell Canada
There are exceptions, but companies today need no incentive to skip building the behemoth plants, a fixture of oil sands mining going back to the days of Suncor Energy Inc. ancestor Great Canadian Oil Sands. At Imperial Oil Ltd.’s Kearl mega-mine, plans instead call for use of a processing technique dubbed “paraffinic froth treatment.” The project’s first phase is due to start pumping out 110,000 barrels per day by late 2012. Imperial says its patented technology, beyond providing relief from the volatile spread or “differential” between grades of crude oil that all upgraders rely on for profit, will produce a quality of crude similar to the Maya variety from Mexico that currently feeds Gulf Coast refineries in the Houston, Galveston and Corpus Christi corridor.
More than the technological breakthrough the project represents, blueprints for Kearl underscore the pliable nature of value-added oil sands production. As the worst of the recent economic turmoil fades from memory, the term has become something of an economic chameleon; depending on the context, it means different things to different people. On one hand, a goal set by outgoing premier Ed Stelmach calling for a greater proportion of mined bitumen to be upgraded at local facilities stands in sharp relief against his government’s desire, aided by calls from operators, to deliver more of their output to Gulf Coast refineries or Asia-Pacific markets. Without new buyers, “Our greatest risk is that by 2020 we’ll be landlocked in bitumen,” Alberta Energy Minister Ron Liepert told a tradeshow audience in June, repeating a now-familiar talking point.
The minister blamed “foot-dragging” by the U.S. Department of State for slowing approval of TransCanada Corp.’s long-awaited Keystone XL expansion, which would connect Cushing, Oklahoma, with refineries in Texas. It’s no secret that storage volumes at the Midwest trading hub – where futures contracts traded on the New York Mercantile Exchange are settled – have surged to record levels as a result of increased production from Canadian oil sands and the North Dakota Bakken formation. The bottleneck means Alberta’s exports fetch considerably less than international benchmark grades of crude oil like North Sea Brent. “We’re taking a $20-per-barrel discount,” says Peter Tertzakian. Left unchecked, he predicts projected daily exports of some two million barrels of Alberta oil could see as much as $40 million in added wealth go unrealized every day. “This is, I think, troubling,” the chief economist with ARC Financial Corp. says.
But not all export markets promise stellar returns. With a clutch of slides to demonstrate his point, Tertzakian warned a breakfast crowd in Edmonton that U.S. consumers are driving less and buying smaller and more fuel-efficient vehicles. “One of the largest drivers of oil consumption in the United States has flattened out, and it’s not, in my opinion, coming back.” Worse still, he said, a steady decline in domestic U.S. oil production, aside from a slight spike when offshore volumes from the Gulf of Mexico came on stream in the 1970s, has been arrested. Daily production from the “tight” oil Bakken formation in North Dakota will soon hit 700,000 barrels – part of an overall increase projected by the U.S. Energy Information Administration that sees American onshore production peaking at 3.9 million barrels per day by 2025, thanks mainly to advances in horizontal drilling and hydraulic fracturing.
The same technology that has redrawn the natural gas playbook across North America has also revived legacy oilfields in the Western Canadian Sedimentary Basin. Combined with higher oil prices and favorable royalty changes crafted by the Alberta government, the rebirth of assets once deemed marginal has transformed a 10-year decline in production of light crude oil tracked by the Canadian Association of Petroleum Producers into a projected short-term supply bump. Revisiting old reservoirs like the Cardium, Pekisko and Viking will see conventional oil production increase from 1.2 million barrels daily in 2010 to 1.5 million barrels per day by 2015. “The oil sands have to take this into consideration,” Tertzakian argues. “North America has been tooling up for heavy oil and now all of a sudden we’re getting light oil, and to ignore these trends, much as the trends were ignored in July 2007 on the shale gas side, I think, is something that we cannot afford to do.”
Even the largest oil sands operators support, in principle if not in the form of binding commercial agreements, reaching Pacific tidewater as a way to increase the value of Alberta’s exports. “We need to support at least one line to the West Coast,” Suncor Energy Inc. president and chief executive Rick George said following a keynote address in June. He did not endorse any one project for accomplishing the job; nor did he rule out backing either Enbridge Inc.’s Northern Gateway or Kinder Morgan Canada’s TMX proposal. “I’ll let the market decide” which project wins out, George said.
The sprawling Scotford upgrader north of Edmonton
Alberta’s industrial heartland region northeast of Edmonton is no stranger to the whims of the herd-driven market. Big plans ran aground when oil prices plummeted from US$147 per barrel in mid-2008 to $34. The province’s would-be upgrading and petrochemical mecca saw as many as seven of the mega-plants temporarily shelved or permanently scrapped. “That doesn’t mean value added is dead,” insists Justin Riemer, assistant deputy minister of Alberta Finance and Enterprise. “This cannot be highlighted enough.”
Evidence suggests he may be right. A joint venture struck late last year between Total E&P Canada Ltd. and Suncor Energy Inc. to revive that company’s mothballed Voyageur plant was finalized last spring. At the center of another battle against the tide of planned exports is the small community of Redwater, Alberta, just east of the Fort Saskatchewan hub. The town of 2,100 people is the future home of North West Upgrading Inc.’s $15-billion refinery. Production from the first of three 50,000-barrels-daily stages of the mega-plant is due to begin by 2013. Two-thirds of the initial feedstock for the project will come via the province’s bitumen royalty-in-kind program, with the remainder contributed by Canadian Natural Resources Ltd. Blueprints for the facility call for production of diesel, as well as premium-priced “diluent” or thinner used by oil sands producers to make their product flow in pipelines.
The plant will further reduce exposure to the volatile price difference between crude oil grades by churning out light ends of the oil barrel – including butane, propane and ethane – ideal for supplying petrochemical plants with a reliable feedstock. North West chairman Ian MacGregor says the facility has one main advantage over export projects that plan to ship raw oil sands production south and west for processing. Compared to controversy that continues to dog proponents of TransCanada Corp.’s Keystone expansion, Enbridge Inc.’s Northern Gateway and Kinder Morgan Canada’s Trans Mountain Pipeline, “Fuels are easy to export,” MacGregor says. He betrayed no anxiety about the future of value-added production in Alberta at a summer showcase for oil sands technology, even as he shared the stage with a senior executive from the major projects division at Enbridge Inc. Can the upgrader project succeed where so many before it have faltered? Without question, MacGregor says. “We’re small. We’re presumptuous. But we believe we can do it.”
Not long after the North West chairman left the stage, David Chappell, vice-president of the Canadian arm of Oklahoma-based Williams Energy, indulged in a brief fantasy. His firm – currently midway through a $650-million expansion program in Sturgeon County – is a pioneer in the emerging art of capturing oil sands “off-gas,” a byproduct of bitumen processing rich in vapors that condense into petrochemical building blocks like ethane, propane and butane. Imagine a businessman in China sitting in a conference, Chappell said. The man’s attention starts to wander. His fingers turn over a plastic pen, manufactured in a far-off province known for its cold weather and vast resource wealth. “This is the opportunity for us,” Chappell said. He smiled, “Made in Edmonton – wouldn’t that be nice?”