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Canadian oil sands produce more but slash planned capex

Oil sands producers have announced plans to decrease capital expenditure, but many expect increased production levels this year

Many of Canada’s oil sands producers are predicting increased production from existing projects in 2015. But there is no disguising the impact of the oil price collapse – together with rising costs – on the sector, as firms announce plans to curtail their spending on new developments.

The latest indicator of the problems facing the sector was Shell’s announcement in early January that it planned to reduce the workforce at its Albian Sands project in northern Alberta by 5-10% from around 3,000 people at present. The company also said last May it was suspending work on another planned oil sands project in Alberta, the 200,000 barrels a day (b/d) Pierre River mine.

But the complexity of the situation facing producers was illustrated by the view at Cenovus Energy. The Canadian oil sands specialist said in December it expected a 9% rise in production from its Alberta oil sands acreage in 2015, but, at the same time, it said it would cut its capital expenditure budget to between C$2.5 billion ($2.1bn) and C$2.7bn this year from $3bn to C$3.1bn in 2014.  

Estimates of new oil sands capacity scheduled to start operating in 2015 range from 300,000 b/d to more than 400,000 b/d, compared to around 115,000 b/d last year.  

This projected rise in output may seem like bad timing, given that North American unconventional oil production is under pressure due to the low oil price – and that the fate of the Keystone XL pipeline to feed Canadian heavy crude to the US Gulf coast refineries best suited to process it remains in the balance.

But, the rise in production is unavoidable, given that oil sands producers would find it next to impossible to dramatically scale down production from existing projects even if they wanted to – and many of them will have contracted volumes to supply to clients profitably in any case. Meanwhile, many shareholders that have bankrolled new projects are unlikely to be impressed if those developments are summarily mothballed – much of the cost of oil sands projects lies in their construction rather than the production phase.

Once the next wave of almost completed projects are built, investor appetite for further projects seems limited, against a background of cost inflation and uncertain oil prices.    

Services firms feel pinch  

The gloomy outlook is perhaps best demonstrated by news from companies providing support services, whose contracts provide leading indicators of producers’ plans. For example, Houston-based Civeo, which provides camp facilities for the oil and gas industry, said in December it was slashing its workforce around the world, including a 30% reduction in Canada, - where the oil sands are the main driver for its business – citing capex reductions by its clients. 

The firm said only 35-40% of its lodge rooms in Canada were contracted at the start of 2015, compared to more than 75% contracted for 2014 at the start of that year.    

The acid test for the oil sands will be whether it is able to weather the current turbulence

And it is not just Canada’s oil sands producers that are being affected. In fact, the projected increase Canadian oil output – in large part from the oil sands – in tandem with the low oil price also have ramifications for Canada’s conventional and shale producers, several of which are also reining in spending on new projects.

For example, Calgary-based Crescent Point Energy said in early January it foresaw production of oil, gas and liquids rising 9% from 2014 levels to 152,500 barrels of oil equivalent a day (boe/d) in 2015, but at the same time, said it would cut capital expenditure to $1.45bn, 28% lower than in in 2014. 

Containing costs

The acid test for the oil sands sector will be whether it is able to weather the current turbulence and remain in good enough health, despite scaling back new projects, to take advantage of any improvement in business conditions in the future. This is a struggle likely to be exacerbated by high costs and the potentially constricted pipeline capacity – as well as the challenges posed by whatever carbon emissions agreement may emerge from global climate change talks in Paris at the end of this year.

Shell said its decision to scale back staff at Albian Sands was not specifically related to low oil prices, saying it would have been looking at cost-cutting measures even if the oil price had been stable. 

Similar reasons have been given by other major international oil companies who have delayed or abandoned oil sands projects over the last year. Statoil said in November it was putting on hold for at least three years its 40,000 b/d steam-driven  Corner project in northern Alberta, citing high construction costs and delays in developing export pipelines. The company’s 20,000 b/d Leismer project in the same area was not affected by the postponement

The Norwegian firm’s move followed the decision of France’s Total and Calgary-based Suncor Energy in May to suspend development of their $10-bn Joslyn project. The partners said rising costs were a key factor in the decision.

The impact of cost rises on the sector’s development is highlighted by a comparison of past forecasts for the growth of Canada’s oil sands with the current situation.

Andrew Leach, Enbridge Professor of Energy Policy at the University of Alberta noted in a recent article on the Maclean’s news website that a look at past predictions for the industry suggest cost rises rather than oil prices have been the most important factor in constricting the sector’s growth.

In 2006, the country’s National Energy Board (NEB) base case forecast for oil sands production in 2015 was some 3.2 million b/d, while the figure for crude bitumen production now predicted by the Alberta Energy Regulator for 2015 is around 2.5m b/d – some 20% lower. 

The oil price used in the 2006 calculations was $50 a barrel for West Texas Intermediate, while the Canadian-US dollar exchange rate was C$0.85 to C$1 – both very similar to today. But what does differ is the NEB’s assumption that a new oil sands project would be economically viable at $20-25/b (in current dollars adjusted for inflation). That is well under half of the actual figure cited for most projects today, due to soaring costs.  

Expanding pipeline network 

Figure 1: Left Production and associated well count

Whatever the industry’s travails, those already producing from oil sands can at least get more of their output to the US Gulf refineries. While the Keystone XL pipeline’s future remains uncertain, a further bottleneck in the existing pipeline network has been removed. 

Enterprise Products Partners shipped the first crude through its 450,000 b/d capacity Seaway Twin pipeline from Cushing, Oklahoma to the Texas coast in December. This supplements the 4000,000 b/d capacity existing Seaway pipeline along the same route and TransCanada’s Gulf Coast line, also running from Cushing to the Gulf coast, which started operations last year. 

The Gulf Coast pipeline is intended to reach a capacity of 0.7m b/d when the $2bn-plus project is completed. It was to have joined up with Keystone XL, but, with that project still bogged down by environmental objections, the pipelines running to the Gulf coast are being supplied by existing cross-border pipelines, while TransCanada and others are now working on alternatives to Keystone XL.   

Of course, improving access to the Gulf coast refineries is one thing, while selling the oil in an uncertain market is quite another. The next task for Canadian producers is to persuade the refiners to continue to take their oil, rather than competitively priced crude from Latin America and elsewhere. 

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