The oil sands dig in
Alberta's unconventional output will keep rising - for now. Derek Brower reports
Across the US unconventional oil sector, the steep fall in rig counts suggests that Saudi oil minister Ali Naimi's strategy to force what he calls 'inefficient' producers offline will soon yield fruit.
In Canada, the picture is more complex. As in the US, rigs targeting tight oil in Alberta, British Columbia and Saskatchewan's section of the Bakken shale are coming off line and companies are scaling back drilling plans - a reaction to the collapsing price of WTI, which as Petroleum Economist went to press was trading just above $43 a barrel and threatening to fall farther. The Canadian Association of Petroleum Producers (Capp) predicts conventional output from the Western Canada Sedimentary basin, now 1.3 million barrels a day (b/d), will not grow at all this year, as investment in the play slumps to C$21 billion ($16.6 billion), compared with C$36 billion last year.
In the oil sands, where reactions to price signals take far longer to filter through to investment decisions, production will rise steeply this year and next, adding more than 450,000 b/d of output, predicts Wood Mackenzie, an energy consultancy. This is production that will reach the market even if oil prices trade lower in the coming months, because the economics of oil sands development are different from those in tight oil or conventional drilling. Bitumen production involves longer lead times and plateau output lasts decades. Once projects are under construction, short-term price signals are largely irrelevant. When companies choose to proceed, two oil prices matter: the prevailing one at time of the decision and, more difficult to guess, the long-term future price. Production due on stream in the next two years was planned when the price outlook was far rosier.
That means the oil sands will themselves will contribute to the oversupply that has swamped the North American market and dragged down the price of Alberta's crucial commodity tumbling. Husky's Sunrise was just the start of a new onslaught of output that will include a ramp up of Imperial's Kearl project and the coming-on-stream of Suncor's 180,000 b/d Fort Hills. It's simply too late, and too costly, to stop projects that are under way.
The impact of all this new supply on prices isn't straightforward. WCS, the benchmark for Canadian heavy oil, is for now trading at about a $14/b discount to WTI (meaning it has sometimes been trading beneath $30/b), reflecting the quality difference and tolling costs. As long as evacuation capacity creeps up along with production, giving the barrels an outlet to market, the discount shouldn't widen significantly. Although Keystone XL (KXL), the 830,000 b/d pipeline TransCanada wants to build to the US Gulf Coast, has still not gained US approval - a diminishing prospect while President Barack Obama is in office - and Enbridge's proposal to ship oil to Kitimat, on Canada's west coast, has stalled, other routes have opened up or will. Rail capacity continues to rise; the flexibility of shipping destinations compensating for higher tolls. Kinder Morgan's expansion project to the Vancouver area, which would more than double capacity of an existing pipeline to 890,000 b/d, is pushing ahead. Energy East, another TransCanada proposal, would ship 1.1 million b/d of oil to Canada's Maritime provinces, feeding refineries there and allowing for export into the Atlantic basin. In Calgary, executives think it will be the easiest of the new pipeline projects to bring on line: it has support in the east, commitments from shippers, and part of the project involves the relatively simple task of changing an existing gas pipeline to an oil one. It doesn't need US approval, either; a major bonus, given KXL's travails south of the border.
Including other capacity additions from pipeline expansions and line reversals in eastern Canada, Capp forecasts that evacuation capacity from western Canada will rise from around 4 million b/d last year to about 5 million b/d by 2017. Capp's vice president for oil sands and markets, Greg Stringham, insists that KXL remains a priority, given the extra output due on stream in the next two years from the oil sands. But that project is no longer the make-or-break pipeline for the oil sands that both opponents and supporters have claimed. Indeed, although KXL promised to open up the big refineries of the Gulf and their ample heavy oil coking capacity, Energy East - via shipments around the eastern seaboard -- and rail will get the oil there anyway. Imports from Canada into the Gulf region are already growing steadily, and reached 282,000 b/d in December 2014, according to the Energy Information Administration (EIA). Ten years ago, just 20,000 b/d of Canadian oil reached Padd III, the EIA's name for the Gulf region.
Despite the glut of oil in the US - still Canada's only real foreign market - demand for Alberta's heavy oil remains robust. Refineries accustomed to heavy oil cannot easily or cheaply switch to process light oil instead, so Albertan oil feeds into a different market from the one now gorging on lighter grades from Texas and North Dakota. While imports from most of the US' other main foreign suppliers have fallen sharply in the past three years, the volume of oil bought from Canada continues to rise.
If it lasts, the price collapse will eventually slow - but not stop - some of this Canadian output growth. Even during the boom years, long-term oil sands production forecasts from Capp and others have consistently over-estimated the production beyond 2020. Capp expects it to rise from about 2.3 million b/d this year to 3.2 million and 4.1 million in 2020 and 2025, but these numbers will be scaled down. Wood Mackenzie says that as the impact of decreased investment now becomes visible after 2016, its target of 4 million b/d in production will be pushed back from 2020 to 2024.
As in Alberta's conventional sector, companies are swiftly downsizing their oil sands budgets. Wood Mackenzie says that cash flow could drop by $23 billion between now and 2016. Already, $35 billion of value has been wiped out of the region and if oil prices stay at $60/b or lower, another $121 billion could be at risk. Capp says capital spending will drop to C$25 billion this year, compared with C$33 billion in 2014. Jackie Forrest, a vice president at Arc Financial, a Calgary investment house, predicts investment will shrink even further, to C$20 billion. "Most of this spending cut will impact projects that would have added new supply from 2017 and onward," she says.
The shift in pace has been in the works for over a year. Big foreign investors were starting to stress capital discipline in the sector even while oil prices were above $100/b. Now, says Stringham, Capp's members are targeting at least a 20-25% cut costs. This involves shelving or slowing down projects. Total started the trend last May, indefinitely postponing its $11 billion Joslyn mining project. (It has now withdrawn its plans for it altogether.) In September, Statoil put back its planned in situ project, Corner, by three years. Cenovus Energy has cut projected spending on assets it has yet to develop, including Narrows Lake, Telephone Lake, and Grand Rapids, where combined long-term production capacity would reach 410,000 b/d. This year, the belts have tightened further. In January, Canadian Natural Resources (CNRL) cut its budget and said it would reduce its spending on the Kirby North expansion project from $575 million to $105 million, in practice a shelving of the plan. (The company will keep working on its Horizon oil sands project.) Suncor, the largest producer in Canada, has postponed its 25,000 b/d MacKay River 2 expansion plan, putting back first oil by a year to 2018. In February, Shell said it wasn't even going to apply for a licence to develop the proposed 200,000 b/d Pierre River project. Nor can it say when it will take a decision to move ahead with the 100,000 b/d expansion to its Jackpine mine. China National Offshore Oil Corporation's (Cnooc) Canadian unit, Nexen, says it has slowed plans to develop its 70,000 b/d Kinosis project. All told, predicts Oilsands Review, a publication focused on Alberta's unconventional sector, 600,000 b/d of new supply is now being delayed.
The job losses are starting to accumulate. A few weeks ago, 1,000 Saipem workers at Husky Energy's 60,000 b/d Sunrise development were promptly sacked after bringing the project on line. In January Suncor said it was lopping another C$1 billion from its 2015 budget, and would also sack 1,000 workers. The go-slow plans from Shell, CNRL, Nexen, ConocoPhillips, Cenovus and other producers will all cut a swathe through Alberta's workforce. A Canadian newspaper summed up the mood in a headline: "Don't go looking for a job in the oil sands right now". As real estate values fall, you probably don't want to sell the house you bought in Fort McMurray during the boom years, either.
The unions are unhappy about the relentless bad news for blue collar workers, but more job losses will come. Among oil patch executives, the mood is relentlessly grim. Two years ago, over lunch with Petroleum Economist, a Cenovus board-member dismissed worries that global oil prices could slump. It was a common view among his peers. The Calgary consensus now is that this price downturn is going to last for some time. "This feels a lot more like 1986 than 2008," says one. As royalties fall, the unemployment rate ticks up, and the construction industry slows, the province - an engine of for Canada's economy in recent years - is likely to suffer a "mild and short-lived" recession this year, predicts CIBC, a bank. Its fiscal surplus will fall in 2015 and turn into a C$7 billion deficit next year, the government says. Alberta's success in the past decade drew envy from people in other provinces, especially the east. But the oil sands employed workers from as far away as Newfoundland, too.
A corporate shake-out in the oil sands is also likely, and will also have consequences for the pace of development and the identity of the sector. The stock of pure-play oil sands firms has been hit hard. At about $4.3 billion, the market capitalisation of Meg, a rising star in recent years thanks to its choice assets, is less than half what it was last spring. Other smaller home-grown firms have lost similar amounts. Laricina Energy, a private company, has shut down its small pilot project. Connacher Oil & Gas, a producer with output capacity of more than 60,000 b/d, racked up too much debt to develop its assets, and could only watch in recent months as its share price slumped from around C$0.35 to C$0.03.
"It's feeding time," says an executive from one oil sands developer. Pressed to keep expanding their reserves base while also slashing spending plans, bigger investors will be lured by cheap valuations for firms that have established a position in the oil sands but face insolvency. Foreign firms could have been expected to lead some of this buying, but perceptions since Cnooc's 2013 takeover of- that Canada is a harder place for state-owned companies to do deals could open the field to already established players. New investors will need deep pockets and some expertise. Imperial Energy, ExxonMobil's Canadian arm, is rumoured to be a likely buyer. If consolidation means firms buy production instead of developing it this will do nothing for overall output growth from the oil sands.
Some Canadians will lament the disappearance of the small local firms that have done much of the ground work in northern Alberta.
Eventually, though, the price drop could do the oil sands a favour. Unless the industry deals with its cost-inflation problem, Steve Laut, head of CNRL said in a recent speech, it would fall into a 'death spiral'. But he also added that the price crash was an opportunity for Alberta's producers - not least as they lobby for even lighter regulation of the sector. Runaway cost inflation, combined with the location of the oil sands in a remote area of Alberta subject to severe weather, makes productivity in the projects low by international standards. Cheap oil won't move the oil sands to a more benign place, but it should help the sector get to grips with its cost problem. The sackings to workers will widen the pool of skilled labour and make it cheaper. Welders probably won't command triple-digit salaries for a while.
To shave off costs, companies will increasingly seek efficiency through phased brownfield expansion, a model already followed by companies like Cenovus. Debottlenecking will also offer a cheaper method to lift output and cash flow. When it shelved the Pierre River application, Shell said it would instead concentrate on boosting profitability at its 255,000 b/d Athabasca project. Above all, companies can slow the pace of projects, stretching the capital spend over more budget years. Husky, for example, will push ahead with the second phase of its Sunrise development, but slow it down. An executive at the firm says contractors are already willing to meet his demands when he tells them the company is looking to cut costs by 25%. For services firms, the market now favours buyers not sellers.
As the cost-cutting spreads across the sector, the oil price needed to turn a profit in the oil sands should fall. Full-cycle break-even costs for new in situ and mining projects are now around $100/b, says Wood Mackenzie. Capp's numbers are lower, says Stringham, with the best new in situ and mining projects viable at $50-60/b and $65-80/b, respectively. All of those numbers are too high.
That's for new projects, though. Producing ones will also enjoy a fall in operating costs, but the oil price they need now is already low enough - just -- to keep them pumping oil during the slump and until prices recover, when the cash can be recycled into expansion. Wood Mackenzie says existing in situ projects 'top out' with a break-even price of $37/b, while for mining it is $40/b. "Even if projects do temporarily operate at a loss, we do not anticipate widespread shut-ins due to the reservoir risk and long-life nature of the resource," the consultancy says. Other analysts put operating costs much lower, and say they are already sliding fast. The drop in loonie's value to the US dollar helps, cutting the cost of imported materials.
So for all the gloom in the oil sands, there are also reasons for optimism. The sector is still growing, but the inevitable oil price correction should make it more resilient and efficient. Constructive critics of the developments - including the late Peter Lougheed, a former premier of Alberta - argued that the oil sands needed to be developed a project at a time. The industry disagreed. For now the market is weighing in, on Lougheed's side.
Back in the Gulf, meanwhile, if the architects of the latest oil bust want evidence of its success, they should look away from the oil sands; at least until 2017, when any slowdown will become more visible. Even as more planned projects stall, output from the oil sands will keep ticking ever higher, exacerbating the very glut that will eventually stunt development - just not yet.