Investments in additional oil sands production capacity in Alberta will be boosted with a WTI price hovering between $55/b and $60/b even as producers spare no effort to reduce their capital costs, executives said Wednesday.
"It is still tough out there, but in the past year we have dropped operating and capital costs by 17% and 30%, respectively, with our focus still being on consolidation and optimization," Lyle Stevens, Canadian Natural Resources executive vice president, told the 2016 TD Securities Energy Calgary Conference.
CNR is adding 23,000 b/d of oil equivalent of heavy and light oil output in Western Canada over the coming six months at a cost of C$17,000 ($13,120)/flowing barrel and is also three months away from adding 45,000 b/d of bitumen output at its Horizon facility in northern Alberta, he said.
Flowing barrel costs include construction costs and sustaining capital and operating expenditure.
"We're feeling a lot better this year than last year and have also been successful in cutting costs by 40% primarily due to the application of new technologies and deflation in the service sector," Harbir Chhina, executive vice president of oil sands development with Cenovus Energy, told attendees of the same event.
Cenovus will restart three projects that were put on the backburner last year due to low oil prices. But the company would seek "price sustainability" before taking a final investment decision, Chhina said.
"We are going to design this [oil sands] business at WTI $55/b," Chhina said, without naming the three projects that would likely be sanctioned for development.
No decision has been made yet about the restart of deferred projects as oil prices move higher, Cenovus spokesman Brett Harris said separately in an email, adding that the earliest an update on capital allocations would likely be available was in the company's second-quarter earnings later in July.
MEG PLANS BITE-SIZED PROJECTS
Fellow producer, MEG Energy, which is producing at less than C$10/b, could "very quickly turn on" a few bite-sized oil sands projects typically of 10,000 b/d to 15,000 b/d if prices were to rise to $60/b, company spokesman John Rogers said at the same event.
But Suncor Energy, which is on track to produce first oil in late 2017 from its 180,000 b/d Fort Hills development, will be less proactive in loosening its purse strings, the company's executive vice president for refining and marketing, Kristopher Smith, said.
"We need some very strong signals on prices before we sanction new projects beyond Fort Hills and Hebron," Smith said.
Hebron is a heavy oil development in offshore Newfoundland and Labrador that is due to start up in late 2017 and is being developed by operator ExxonMobil Canada along with Suncor, Chevron, Statoil Canada and Nalcor Energy.
In 2015, Suncor reduced its costs by $1 billion, with a target of doing so again by C$500 million in 2016, Smith said.
"This is not a crash diet, but a life-cycle change. With cash operating costs of just north of C$24/b, managing costs will be a focus and a challenge and there is a need for a structural change," Smith said.
OIL SANDS VERSUS TIGHT OIL
While the oil sands sector will likely receive the bulk of the planned investments, availability of financing will decide the future growth of tight oil production in Alberta and Saskatchewan, MEG Energy's Rogers said.
"For an oil sands project, we spend 20% of our cash on maintaining the facility while the remaining 80% is available for growth. But for tight oil, it is just the reverse," Rogers said.
Tight oil output in Western Canada is forecast to decrease 13% by 2019, the Alberta government said in a report in April.
Compared with production of some 560,000 b/d in 2015, output will decline to 529,000 b/d this year and 524,000 b/d in 2017. In 2018 and the following year, production is forecast to be 506,000 b/d and 486,000 b/d respectively, it said.
