New risks squeeze Alberta’s oil sands
Canada's oil sands face collapsing oil prices, limited export routes and higher taxes
Alberta’s oil sands developers dismissed the onslaught of environmentalists for over a decade, but now they face much graver threats: a collapsing oil price, limited export routes and higher taxes. Calgary hardly blinked during the 2008-09 oil-price fall but this time things are different.
Home to the marginal barrel, the oil sands are now the collateral victims of the global supply-glut and the market’s downturn. Even without the slide in prices, executives say the investment climate is worsening. New rules on emissions, higher corporation taxes, uncertainty about royalties and the endless problem of pipeline export capacity combine to chill investment in the world’s third-largest trove of oil.
The gloom deepened in the second week of August. While international oil prices wilted again, the shutting-in of some pipeline capacity in Missouri and the closure of BP’s Whiting, Indiana refinery widened the discount between Western Canadian Select (WCS), a benchmark crude contract for the oil sands, and WTI. WCS tumbled to fresh lows of just over $23/barrel, by some distance the world’s cheapest traded oil.
The wider market-collapse has already depressed Alberta’s economy and its government’s budget. Provincial royalties will amount to just $2bn this year, predicts the Canadian Energy Research Institute (Ceri), an independent think tank. Job losses in Alberta – for years Canada’s most buoyant provincial economy – are mounting as big oil firms cut spending and postpone projects. Calgary executives say another round of cuts is likely in the coming weeks as firms set their budget.
This will hurt Canada’s economy, which has grown used to Alberta and its energy sector as an engine of job creation and growth. The government disburses billions of dollars from Alberta to the east under the equalisation payments system; but Alberta’s net outlay will be much lower in future. The national economy teeters on the brink of recession. Some economists say it is already shrinking and the central bank has twice cut interest rates this year. The Canadian dollar has lost almost a quarter of its value since oil prices began retreating in mid-2014.
Welders and mechanics, who last year were traveling from both coasts to work in Fort McMurray, epicentre of the oil sands, are returning home. The Canadian Association of Oilwell Drilling Contractors (CAODC) said in June that 25,000 oil workers would be sacked in 2015.
But because projects take so long to get off the ground, investment decisions made when Brent was trading above $100/b mean total bitumen output will rise from 2.157m b/d in 2014 to 2.643m b/d in 2017, says the Canadian Association of Petroleum Producers (Capp), an industry body.
The slowdown will be plain after 2018, with the effects of the cancellation or postponement of 29 projects, accounting for more than 1mn b/d of deferred production, according to Oil Sands Review, a local industry magazine. Wood Mackenzie, an energy research firm, reckons that of $200bn cut from the industry’s global spending plans, 30% is from Canada. Capp forecast earlier this year that spending in the oil sands would fall to just C$25bn ($19bn) in 2015, compared with C$33bn last year.
As companies cut investment, there will be revisions to longer-term growth projections. IHS Energy, a consultancy, expects oil sands output to reach 2.9m b/d by 2020. Capp sees 3.9m b/d by 2030. Ceri says 3.1m b/d is “plausible” by 2020 and 4.4m b/d in 2035. All of these forecasts have already been cut in the past year. But each still depends on companies taking decisions to invest in big projects again. One executive says a recovery to $65/b would probably bring some projects back. The forward curve suggests those discussions will wait until December 2018.
Alberta’s industry has been bedevilled by low productivity and above-inflation cost rises. Between 2000 and 2007, costs rose by 150%, says IHS. They rose steeply again after 2009. This year, Capp’s vice-president of markets and oil sands Greg Stringham says costs have dropped by about a quarter. But some, like labour and energy inputs, remain sticky. Where mines are already operating, projects chug along profitably at present oil prices, but Ceri says a greenfield standalone mine, including the cost of transport to the trading hub at Cushing, would need $89.71/b (WTI) to make a 10% return; in situ, projects where the oil is drilled and brought to the surface using steam, would need $80.61/b. Supply costs for in situ producers have actually risen 10% in the past year.
The impact of the price slump has cut the value of some Canadian producers, especially those without refineries to benefit from cheap feedstock. Meg, which produces about 55,000 b/d at its Christina Lake Regional Project and hopes to expand to 212,000 b/d, was seen as a darling of the oil patch a few years ago. Its stock now trades at less than a third of its June 2014 value.
But exposure to the oil sands has also hurt bigger refinery-owning players too. Suncor, the oil sands’ largest producer with a string of refineries in Canada, has seen its share price fall by a third. Canadian Natural Resources (CNRL)’s stock has slumped by a similar amount. Between them, Shell, CNRL, Husky Energy, Cenovus, ConocoPhillips and other producers have shed thousands of employees in the past six months. Some Calgary firms have moved to four-day working weeks.
But the oil price is not the industry’s only cause for gloom. The election of the leftish New Democrat Party (NDP) in May’s provincial elections – ending four decades of rule by Alberta’s Conservatives – was a shock to the system. One of premier Rachel Notley’s first decisions was to lift corporation tax from 10% to 12% and double the province’s carbon levy.
The hit from corporation tax alone has already cost the industry about C$2bn. “That’s your winter drilling programme right there – gone,” says an executive at one big producer. The government rejected industry pleas that it be phased in. For some companies, the impact of the tax was clear in their filings. Suncor reported a deferred income tax charge of C$423m in Q2, at the same time announcing a near-identical-sized drop in its spending plans. CNRL’s boss, Corey Bieber, said the new charge “effectively translates into lower future cash flows and therefore lowers reinvestment in the business.” His company reported a C$405m net loss in the second quarter. But for the rise in tax, CNRL would have been profitable, Bieber said.
Royalties and climate
It could get even worse as Notley has appointed a panel to assess the province’s royalty structure. Its results are due later this year. During years of high oil prices, the province’s low royalties were an easy target. The timing now is awkward, given the government’s desire to increase its royalty income without hurting investment. Some in the industry hope the review will spur spending, by extending royalty exemptions to more marginal fields or by grandfathering existing terms. If so, a period of grace before any new changes take effect could even stimulate investment, as firms move quickly to sew up assets before the regime is altered. In any event, the very notion of a review at all has added uncertainty to an already-straitened sector.
Alberta’s climate regulations are another source of pain. The Conservatives claimed Alberta was the first jurisdiction to impose a carbon levy on its producers. But its terms were hardly punitive as they required cuts in emissions intensity against individual baselines, not absolute reductions. CO2 emissions from the oil sands have almost tripled since 1990, says the Pembina Institute, a local environmental lobby group, and under the new proposals, it says, they would almost double in the decade to 2020, from 48m mt in 2010, to 104m mt.
Notley’s government wants to change this. The immediate solution was to increase the levy from 12% intensity reduction to 15% in 2016 and 20% in 2017. The levy on emissions will rise from C$15/mt this year to C$20/mt next year and C$30/mt in 2017. This will cost the industry C$800mn over two years, says Capp’s Stringham – although some of the international firms, which imposed internal shadow levies, will be affected less. Either way, the changes have added about $0.50/b to operating costs, says Jackie Forrest, vice president at Arc Financial, a Calgary investment house. “It’s adding uncertainty, making decisions harder.”
But an even broader plan is coming. Notley appointed Andrew Leach, a climate and energy economist at the University of Alberta, to chair another panel assessing the province’s climate options. It is due to report before the end of the year – allowing Notley and her aides to attend Paris’s COP21 climate summit and avoid the embarrassment that her climate-laggard predecessors faced at such gatherings.
But, as with the royalties, it is unclear what kind of policy will emerge. The panel itself will not offer a prescription, PE understands. Rather, it will lay out possible paths to reach possible emissions goals.
If that wasn’t vague enough, the whole process is overlaid with the uncertainty of Canada’s federal election. In June, Conservative prime minister Stephen Harper signed up to a G7 declaration calling for deep cuts in emissions by 2050 and an end to fossil fuel use by 2100 – the kind of agreement that, in theory, would probably curtail any development in the oil sands. In reality, Harper’s stance on emissions – no concrete action unless everyone else agrees – has not changed and the targets are far enough away not to trouble Alberta’s big emitters. “It’s pie in the sky,” says one energy executive. “I’m retired and fishing by then.” Nor has Harper said how it will reach its own shorter-term targets to cut emissions by 30% below 2005 levels by 2030. As long as he fudges, oil sands producers sit easy.
A new party in government would change this calculus. The latest polls for Canada’s federal election in October show a close race between all three main parties: Harper’s Conservatives, the federal NDP, led by Tom Mulcair; and Justin Trudeau’s Liberals.
For Albertan oilmen still coming to terms with their provincial NPD government, the prospect of a federal victory for Mulcair spells disaster. His stance on the oil sands is ambiguous: development can still go ahead, he has said, but “sustainably”, with the pollution costs to be “internalised” by producers. On climate, the NDP’s programme is radical, calling for cuts of 34% against 1990 levels by 2025, deeper even than Canada’s Green Party. Any genuine effort to meet the target would mean no more oil sands development, says a person familiar with the NDP’s climate strategy. Oil sands executives were hardly thrilled to hear Linda McQuaig, an NDP candidate for Toronto Centre, say that “a lot of the oil sands’ oil may have to stay in the ground.”
Export routes shut
These political risks, combined with forecasts for slower production growth, have for now transcended the oil sands’ other long-standing problem – how to get its oil to markets beyond the US. No one now expects President Obama to approve the Keystone XL pipeline, the TransCanada proposal that would allow for 830,000 b/d of pipeline capacity to the US Gulf coast and its big heavy-oil processing refineries.
But progress on other export pipelines – all of them within Canada – has also been frustratingly slow. It would not bring about an immediate surge in Canadian exports but the extra capacity would at least allow more options and reduce the discount to WTI that was seen in August.
Of the two proposed projects to the west coast of Canada –Enbridge’s 525,000 b/d Northern Gateway and Kinder Morgan’s 590,000 b/d Trans Mountain Expansion (TMX) – the latter is the more plausible. Although TMX faces opposition in the Vancouver suburb of Burnaby its approval should be more straightforward than Northern Gateway, given it will expand an existing route, not create a new one. Opposition to Enbridge’s project among British Columbia’s First Nations groups, however, has solidified over several years. Early assumptions in Calgary that the groups would be paid off to accept the project were wrong.
While those projects stall, Energy East, another TransCanada proposal, which would ship 1.1m b/d to Canada’s Maritime provinces, feeding refineries and allowing for export off the east coast, has hardly streaked ahead as it should. Technically the project is relatively straightforward, involving the conversion of a natural gas pipeline.
But it too risks being bogged down in local politics. On 13 August the Energy Board of Ontario, through which the pipeline passes, said the environmental risks of converting the pipe would outweigh the potential benefits. Opposition has arisen in Quebec too. It is not clear, either, how enthusiastic shippers will be if almost a third of the crude ends up feeding the Irving refinery in St John’s, Newfoundland, giving power to one buyer with flexibility to buy its feedstock elsewhere.
Expanding rail capacity in North America has, for now, eased the pipeline issue anyway. Including the output growth expected over the next two years, the oil sands’ producers have enough capacity to get their oil out.
The bigger question – not least for the global market – is whether the oil sands will need much more evacuation capacity after 2018. The new carbon policy and Alberta’s corporation tax hardly matter. “At this oil price, you’ll see no growth anyway,” says one industry leader. At the very least, it will take a brave board to sign off on a new project in northern Alberta. Even if prices recover, expect smaller, cheaper increments from existing developments, with a lot more oversight on emissions. The pace of growth from the world’s marginal oil producer has never been less certain.