CALGARY, Alberta (Reuters) - Falling oil prices are rekindling fears that Canada’s oil sands industry could start to put some projects on the back burner, like it did in the last financial crisis, to cope with weakening returns and stubbornly high costs.
So far, development in Northern Alberta has stayed on pace as West Texas Intermediate crude sank to current levels around $84 (54.6 pounds) a barrel, from more than $104 six weeks ago, and no analysts are calling for large volumes to get shut in.
Still, some marginal developments without money committed may be shelved if world oil prices remain low amid a worsening global economy while an oversupply of Canadian crude floods into the U.S. Midwest market, spelling ever-deeper discounts.
“Oil sands projects display some of the highest break-evens of all global upstream projects. The potential for wide and volatile differentials could result in operators delaying or cancelling unsanctioned projects,” Wood Mackenzie Ltd said in a report on Monday.
“Pure-play oil sands companies without hedges in place, such as a U.S. downstream position, are the most exposed.”
In 2008 and 2009, more than $80 billion worth of developments were shelved, rejigged or cancelled outright when oil sank below $40 a barrel and corporate credit dried up. But since then investments have roared back.
The industry currently predicts oil sands output could hit 3 million barrels a day by 2020, up from the current 1.6 million, and at least one analyst believes that to be a conservative figure.
Some projects say production could bump up against export capacity as early as 2016, a major factor in the industry’s and Ottawa’s push to advance TransCanada Corp’s (TRP.TO) Keystone XL pipeline to Texas and Enbridge Inc’s (ENB.TO) Northern Gateway pipeline to the Pacific Coast against protests from environmental groups and some native communities.
WoodMac noted an unprecedented 16 bitumen projects are slated to start up by 2016 with potential to add more than 1 million bpd of production.
Still, companies face growing risks, including a tightening skilled labour pool, clogged pipelines to U.S. markets and, most recently, competition for pipeline space and refinery purchases from North Dakota Bakken shale oil, output of which is forecast to double to 1.2 million bpd by 2015, it said.
“It’s now a new concern that oil sands operators have to handle, besides looking at costs and labour,” said Mark Oberstoetter, one of the report’s authors.
Even before the recent drop in U.S. benchmark crude, oil sands producers were hit this winter by gaping discounts for their extra-heavy crude due to tight pipeline capacity and a glut of supply in the U.S. Midwest and Midcontinent regions.
With a discount quoted on Monday at $25 a barrel under WTI, Western Canada Select heavy blend, a frequently quoted oil price, was worth around $59 a barrel, a few dollars below even the depths of the first quarter.
Still, only the smallest and most indebted oil sands players will be put under enough financial strain to force some production off line, said Samir Kayande, analyst at ITG Investment Research in Calgary.
He pointed to Connacher Oil and Gas Ltd CLL.TO, which shut some operations during the last financial crisis and has struggled with high debt and management changes, as having among the highest chances turning off output again. However, its total bitumen output was 12,429 bpd in the first quarter, a tiny fraction of Canadian production.
For the large producers that use stream-assisted gravity drainage, or SAGD, technology to pump oil sands crude, such as Cenovus Energy Inc (CVE.TO), cash costs of production are around $25 a barrel or less, Kayande said.
Unlike open-pit mining, SAGD involves injecting steam into the ground to loosen up the tar-like bitumen so it can be pumped to the surface in wells.
“So as long as you’re achieving that in terms of your revenue, which implies a lower-than-$40 WTI price, you’re probably OK,” he said. “You’re not going to shut in as long as you’re making cash flow.”
Production costs for integrated oil sands mining and upgrading operations, such as the 350,000 bpd Syncrude Canada Ltd and Suncor Energy Inc (SU.TO) ventures, are in the $35 a barrel range. Their light, synthetic crude currently sells for less than $77.75 a barrel, still leaving a healthy margin.
But break-even costs for building new steam-driven projects are in the $65-$70 a barrel range and mining developments need at least $90-$100 oil, Kayande said. Upgrading pushes break-even levels well above $100 a barrel.
“The reason we see mining and upgrading economics as being worse is your (price) spread is similar to what you would get in the Gulf Coast, but your costs are 50 percent higher,” he said.
However, last week, Royal Dutch Shell (RDSa.L) chief executive Peter Voser said last week his integrated oil sands operation can add up to 90,000 bpd by the end of the decade by “debottlenecking” the current 255,000 bpd operation at a cost of under $50 a barrel.
Editing by Sofina Mirza-Reid