Cost inflation has replaced market access as the biggest worry for operations in Canada's oil sands
In rail cars, through new and expanded pipelines, and even aboard Mississippi river barges, Alberta's bitumen is crossing the continent. With or without Keystone XL (KXL), Canadian oil sands producers are finding new markets.
Buyers beyond North America, long the prize for the developments' land-locked producers, are in sight too. Progress on two pipelines to the Pacific Coast remains slow. But soon Alberta's oil should at least begin flowing east, to Canada's maritime provinces. Supplies to that region will force out West African imports and then some: much of this Canadian oil will be shipped onwards, ending up in the Gulf of Mexico. Other barrels may reach southern Europe or India.
Executives in Calgary grudgingly admit that KXL's opponents in the US - whose protests have for years stalled the project's approval from the White House - did them a favour, forcing open new routes to new markets. Energy East, the 1.1 million barrel a day (b/d) pipeline that will ship Alberta's crude to Ontario and the east from 2018, was only conceived because of the delays to TransCanada's flagship KXL project. Rail capacity has surged to meet demand for more evacuation capacity. Calgary is now home to several merchant rail operators. Thanks to the abundance of short-term projects to increase takeaway infrastructure, oil sands producers can afford to wait for KXL.
Yet as the threat of tight pipeline capacity eases an older problem has resurfaced in the oil sands: cost inflation. One project, the proposed Joslyn mine, was a casualty of this in May, when Total and its partners shelved the development. Local oil sands executives, many of them reflecting new cost discipline imposed by foreign bosses, now talk of a drive to cut costs and lift productivity. "We're opportunity rich and capital constrained," says Lorraine Mitchelmore, head of Shell's business in Canada. And costs, says Andre Goffart, head of Total's Canadian business, "are rising faster than the price of the product".
On the production side, things are looking rosy. Output from the oil sands, now above 2.1 million b/d, is rising steadily. Another 300,000 b/d will be added in the next 18 months, says the Canadian Association of Petroleum Producers (Capp), and the developments will produce 3.2 million b/d by 2020 and 4.1 million b/d by 2025.
Two years ago, such rising output forecasts were a mixed blessing, because new pipeline capacity wasn't keeping up. The bottleneck would drive down the price of Canada's crude. A taster of this came in the winter of 2012-13, when pipeline outages, refinery maintenance in the Midwest, including delays to BP's Whiting plant upgrade, and strong output blew open the discount for Western Canadian Select (WCS), the benchmark for Alberta's heavy oil, against West Texas Intermediate (WTI).
By February 2013, WCS had lost touch with international benchmarks and was selling for less than $60 a barrel. WTI and even Mexican Mayan, a heavy crude similar to Canada's, were fetching around $100/b. Alberta's then-premier told her province that a "bitumen bubble" could wreck the government's finances by slashing royalties. Analysts said the plummeting values for oil sands bitumen would threaten planned investments.
Pipeline tightness temporarily widened the discount last winter, too. But the problem has since eased significantly thanks to the surge in rail capacity, the opening of some new pipeline capacity and progress on greenfield export projects. Above all, say executives in the sector, an era of volatility in the differential may now have passed.
Rail's rise, given momentum initially by similar pipeline constraints in the US' Bakken play, has been startling. New loading terminals and thousands of cars are under construction in Alberta, Saskatchewan and Manitoba. Capacity was just 200,000 b/d at the start of 2013 but should reach 1 million b/d by the end of this year and 1.6 million b/d by 2016, says Capp. (Some estimates suggest another 1.5 million b/d of rail capacity is under construction.) Capp expects the volume of oil to be transported by rail will reach 700,000 b/d by 2016 - almost the equivalent of KXL's proposed capacity.
While rail transport costs are typically higher than a pipeline for the equivalent distance, the tracks give producers more shipping flexibility. If refineries in the Midwest are full, the oil can move to the Gulf now, says Jackie Forrest, vice president of research at Arc Financial, a Calgary private equity firm. As a pressure valve for tight pipeline capacity, rail should end the surges in Canadian oil prices that characterised the past few years. Despite slow progress on the big pipeline projects, several smaller debottlenecking and expansion programmes, many in Enbridge's export network, are also adding new capacity. Its Seaway pipeline expansion between Cushing, Oklahoma and Texas, undertaken with partner Enterprise Products Partners, has more than doubled capacity to 850,000 b/d. It is one of a host of other projects in the US south, including a $1.5 billion build out of new infrastructure from Kinder Morgan and completion of the southern section of KXL, designed to ease the flow of oil to the Gulf's big refineries.
Other projects in Canada itself will offer similar flexibility for oil sands producers. Enbridge's Alberta Clipper project will add 350,000 b/d of capacity to 450,000 b/d already in use. An expansion of the Southern Access Pipeline, which runs through the US, will increase its capacity from 400,000 b/d to 1.2 million b/d.
Then there are the three big export projects to open new markets: TransCanada's Energy East, which will convert a gas pipeline into an oil service stretching from Hardisty, in Alberta, to Ontario and Quebec; Kinder Morgan's Trans Mountain Expansion (TMX), a $5.5 billion plan to build a new heavy oil line along an existing route between Edmonton and British Columbia (BC) and Washington state, more than doubling capacity to 890,000 b/d; and Enbridge's Northern Gateway, which aims to ship 525,000 b/d from Bruderheim, Alberta, to Kitimat, on the BC coast.
TMX faces opposition from Vancouver and residents in nearby Burnaby, and several First Nations groups oppose Northern Gateway, despite backing from the federal government. Energy East has won support in eastern Canada. It will be the first of the pipelines to go ahead, with start up possible in 2018. A new provincial government in Alberta has pledged to negotiate with aboriginal groups and other opponents to push through the west coast pipelines, but they remain in limbo. TMX, which has already secured commitments from shippers, is the likelier of the other two. But neither seems likely to be on stream before 2020. Indeed, Deloitte said in a recent report that a majority of industry experts it surveyed in mid-2013 expected neither KXL or Northern Gateway to break ground.
Even without the two west coast projects, or approval of KXL, the export infrastructure exiting the Western Canadian Sedimentary basin now looks ample to cope with the forecast rise in output from the oil sands (see Figure 3), especially given the slack in the system offered from rail. The vehemence of the opposition to KXL in the US and the struggles to win local approval for the lines to BC sticks in the craw of oil sands boosters in Alberta. But for the developments their construction is no longer an existential matter.
To judge from the latest obsession of Calgary executives, cost inflation is the bigger threat. No wonder. The Canadian Energy Research Institute (Ceri) said in a recent report that the cost of steam-assisted gravity drainage (or in situ) operations rose by 5.1% between 2011 and 2013, while mining and extraction costs jumped by 6.1%. Those figures help explain the institute's guess about how much investment will be needed in the oil sands over the coming years: its reference case scenario, assuming output growth to 3.4 million b/d in 2020 and 4.8 million b/d in 2048, sees investment of almost C$600 billion ($546 billion) pouring into the oil sands. Capp says the industry will invest C$29 billion this year alone, or C$2 billion more than in 2013. With such inflation in mind, some analysts are sceptical that output growth will happen at the pace predicted by Capp and others. Andrew Leach, professor of energy policy at the University of Alberta, points out that the most recent forecasts for 2025 now expect fewer barrels at oil prices of around $100/b than were predicted when prices were a quarter of that level. "A lot of the pipeline hand-wringing is about what we are going to do when we produce 5 million b/d in 2020. But we're not going to." He expects future output forecasts to be trimmed back, too.
The C$11 billion Total-led Joslyn mine was the most recent casualty of the cost-inflation problem. The partners, which include Suncor Energy, Occidental Petroleum and Japan's Inpex, shelved the project at the end of May. "The economics as they stand today are not good enough," Total's Goffart said in an interview. And he had a warning for investors in the oil sands generally: "If the oil price remains stable we can't afford to have cost inflation continuing the same way. There is a time when it won't work." Joslyn, said Goffart, was a 'wake-up call' for the industry.
But those alarms have been ringing for a while. Suncor's decision last year to scrap the planned $11.6 billion upgraded project, Voyageur, was just another example. Exporting unprocessed bitumen, instead of converting it to light synthetic crude within Alberta, was a more profitable option, given soaring capital costs and an abundance of light oil supply in the US.
Then came Imperial Oil's C$12.9 billion Kearl project. It came on stream in April 2013 and production should double in 2015 to 220,00 b/d. But its original development plan was for output to start in 2012 and rise to 300,000 b/d at a cost of C$8 billion. Imperial says it has learned lessons from the overrun and expects the next C$8.9 billion phase to run more smoothly.
The cost problem isn't as bad as it was in 2007, when several projects were underway at the same time, competing in the same small pool for skilled labourer while also facing globally inflated costs of other inputs, like steel.
The prices of some of those inputs - especially natural gas, used extensively in the oil sands' thermal projects - have fallen and the pace of development has slowed. Labour costs, though, remain sticky, especially for mines, because of the sheer number of labourers needed to keep a digging, scraping, loading and upgrading enterprise going round the clock. Qualified workers command eye-watering salaries. A welder with his own fleet can contract to an oil company for C$300,000 a year, says one. A single welder can cost $250 an hour, says Total's Goffart. Drivers of the oil sands' enormous dump trucks can earn well into six figures.
Part of the problem is Fort McMurray itself, the city at the epicentre of the oil sands. "You're trying to build a massive industrial project at the end of a dead-end road," says Leach. Severe winters and long commutes - many workers are still flown in on a week-on-week-off basis â€“ see many man-hours lost. The city's infrastructure, say residents, can barely cope with the influx of people. Workers talk of poor air quality and list other complaints about life in the city, especially high rents. One heavy-duty mechanic moved to Fort McMurray for a year with his family before leaving. Canadian Natural Resources now flies him in from British Columbia every second week, but he still pays C$1,800 in rent for basic lodging. "People take jobs there because they think the roads are paved with gold," he says, "but you end up paying all your salary just to live there."
To retain staff, salaries have to compensate them well. Even so, it remains common for workers to move between jobs, sometimes just crossing the street to take a new position. That causes delays. A project development lasting 15 years might go through three or four different project managers in that time, points out Leach.
With the majors now stressing capital discipline many of the local units are under pressure. The companies are deploying different strategies to cope with costs, especially given perceived softness in global oil prices. Canadian producers are price-takers, not setters, but "cost is an element we can do more about", said Dave Collyer, president of Capp.
Modularisation can help save money. Units built in Asia or simply down the road in Edmonton are part of this strategy. (Others point out that one of the problems with Kearl was the long distances needed to bring in some of its modules.) Some companies, such as Husky Energy at its Sunrise project, have agreed ceilings on costs with contractors before the work begins.
Shell says it has studied other industries to learn about "warehousing". Countless hours are lost by mechanics needing to find bits of kit, says Mitchelmore. Shell has added chips to each piece of pipe, so no one wastes time scouring the inventory. Warehousing now saves the company $20 million - a drop in the bucket by oil sands standards, but progress in a sector long characterised by lost productivity. "We can track 76% of our inventory and we'll get to 96% in a couple of years," pledges Mitchelmore.
Drawing in new workers is another priority. A programme for temporary foreign labour has helped, though it has also brought opposition from some unions who say it is taking away jobs from Canadians. Goffart says Total will rely on foreign workers for future projects, like the Fort Hills mine, which it says will hit 180,000 b/d by 2018. Capp continues to arrange jobs fairs around Canada, in the US and in Europe.
The biggest change, however, is that as in situ projects increasingly account for the bulk of oil sands extraction the developments will grow in smaller incremental stages - more of a manufacturing process. Expansions to existing projects, such as phases 5 and 6 of Suncor Energy's Firebag in situ project, and staged repetitions, a method used by Cenovus to expand its output, will add capacity but take advantage of some economies of scale. "This is exactly what the industry is witnessing," said a recent Ceri report, "a move towards more in situ projects as their smaller scale allows for more efficient management of capital and scheduling to match the availability of key inputs such as skilled labour". The era of the truly mega-project is fading.
That doesn't mean the oil sands won't remain a hive of activity, with fierce competition for labour and resources. The Alberta government says 12 projects are presently under construction in the Athabasca region - almost all of them thermal in situ developments. Another 11 have been approved, with 31 more either in application or planning stages. The development free-for-all that characterised the boom years up to 2008 has, though, been replaced with a more measured pace of growth. There is "good visibility" on the project schedule now, says Goffart. Producers "should be able to manage the load" over the next six years.
Nonetheless, the oil sands could also face competition for investment and resources. The raft of proposed liquefied natural gas (LNG) projects in northern British Columbia is now a threat - they will draw on the same supply of workers as the oil sands. Deloitte said recently that between them western Canada's oil and LNG sectors could need "upward of 41,000 new hires over the next decade" to meet production targets. Saskatechewan's generous fiscal regime has also brought upstream investment to that province, draining some labour from Alberta. Even the province's own Duvernay play, a liquids-rich shale gasfield, could begin to divert investment away from the oil sands, say some executives.
But the oil price - an element out of control of the producers - is a worry. Although the new rail and pipeline capacity has taken some volatility out of the price differential, the upwards cost pressures have left margins tight, though break-even costs for new projects range widely. Collyer says new in situ projects would need between $55 and $80/b to generate a 10% return on investment.
For mines, the number is between $75 and $100/b. Shell says its new investments, including an expansion of the Jackpine mine and its in situ Carmon Creek project, would not be viable at a Brent price of $70/b, leaving plenty of wiggle room: Brent's lowest point in the past three years was still above $90/b. But the comfort zone for other greenfield developments in the oil sands is much narrower. An integrated mining and upgrading project would need an oil price of more than $107/b, says Ceri (see Table 1).
After adjusting for blending and transportation to Cushing, moreover, in situ production costs would rise to almost $85/b and standalone mining to almost $110/b.
Those break-even prices leave the oil sands looking vulnerable to a prolonged downturn in crude prices, but analysts of North America's oil patch are sanguine. US tight oil output is much more responsive to price, says Arc's Forrest. Any drop in global prices would find a floor when new US supplies started tailing off - and at which oil sands output growth remains viable.
The Bakken and Eagle Ford, not the oil sands, may now offer global oil's marginal barrel. Meanwhile, despite the tight oil surge in the US, its spare refining capacity remains biased to heavy oil, leaving robust demand for Alberta's bitumen. As long as that's the case, the oil sands can keep chugging away.