None of the four executives who appeared on a senior oilsands producers panel at a conference this summer in Calgary predicted greenfield oilsands projects will get the go-ahead anytime soon.
But there was some talk of brownfield developments, de-bottlenecking work and restarting projects deferred after world oil prices crashed three years ago.
Executives from Suncor Energy, Cenovus Energy, Husky Energy and Canadian Natural Resources Limited took part in a panel discussion at TD Securities’s annual Calgary oil and gas conference. The topic was capital allocation when WTI crude is trading around US$45–$55/bbl.
“I think we will see a concentration on some brownfield, high-return projects, some de-bottlenecking—and in our case with the Syncrude project—some synergy projects. There may be some interconnectedness there,” said Steve Reynish, Suncor’s executive vice-president of strategy and corporate development.
“I think we will see less greenfield sanctioned,” Reynish predicted, referring to the rest of this decade. He added that the next wave of greenfield oilsands projects will likely be in situ rather than mining and will likely proceed in the 2020s.
He summed up the oilsands capital allocation philosophy at current oil prices: “Stick to what you’re good at. Make sure you can produce cash even at these oil prices. And then be very selective with your investments going forward. Short term: probably brownfield. Greenfield: yet to be determined, but it’s some way off in the future.”
Next-gen in situ technology
Asked about the next generation of in situ oilsands technologies, Reynish cited solvent-assisted extraction methods, which are expected to cut capital and operating costs, more effectively mobilize bitumen, reduce water use and cut CO2 emissions.
On a notional development using the next generation of in situ oilsands technologies, the facility footprint would be about 45 per cent smaller than existing thermal oil facilities, Reynish suggested. About 15 per cent less equipment would be needed. The number of valves on a well pad would be cut to 30 from 230. And construction hours would shrink to 3,000 from 7,000 hours.
“So I give you that level of detail just to give you a flavour for some of the kind of dramatic changes that we think are possible—and quite frankly, required—to get to the level of capital intensity that would justify new projects in this volatile oil price world going forward,” Reynish said. “So, exciting stuff. It’s a number of years away. But there’s some good engineering work and good technology development work going into making that a reality during the 2020s.”
Read more about the next generation of oilsands technologies in the latest Oilweek.
Corey Bieber, Canadian Natural’s chief financial officer and senior vice-president of finance, gave no hint of the company’s specific plans for the Athabasca Oil Sands Project assets acquired from Royal Dutch Shell.
In keeping with Canadian Natural’s focus on long-life, low-decline assets, the company’s top priority is completion of Phase 3 of the Horizon oilsands mine and upgrading operation.
Bieber said Phase 3 is on track for tie-in during a turnaround in late summer and for first production in the fourth quarter. “So that’s all going very well.”
Beyond that, Canadian Natural’s current capital allocation favours projects with less capital risk that can be brought on stream faster, albeit with higher decline rates. Bieber noted the company is spending about $1 billion on Horizon versus about $2.5 billion to $3 billion elsewhere in Western Canada and internationally.
As for how the company allocates capital with oil prices hovering around US$45/bbl, he said, “the focus at $45 is the same as $55. It’s really optimizing capital returns. So if it doesn’t make sense to invest at $45, we’re not going to do that.”
In Canadian Natural’s non-oilsands businesses, Bieber said the company is taking more of a “drill-to-fill” approach as opposed to going into growth mode.
As for SAGD and cyclic steam projects, he said many of the company’s new well pads could be very economic at a $45 oil price.
In summary, Bieber said Canadian Natural’s capital allocation is mainly focused on completion of the mine at Horizon, integration of the former Shell assets and “drill-to-fill economics.”
For the near term, Husky Energy expects to allocate more capital to small—and hence lower-risk—but profitable thermal heavy oil projects in Saskatchewan.
“I think in the nearer term we’ll be focusing a lot more of our capital in heavy oil around Lloydminster where we’ve got about 150,000 barrels a day of production that we can bring on with frankly better economics than the oilsands at the moment,” said Darren Andruko, Husky’s deputy chief financial officer and treasurer.
Andruko noted operating costs on those projects are less than $10/bbl.
More broadly, Husky has laid out precise parameters for capital allocation. The company requires all new investments to generate at least a 10 per cent after-tax internal rate of return at $45 WTI, and to at least break even at $35.
“So that’s the line we draw for all of our projects,” Andruko told the conference.
Husky’s current focus is more on high-margin, small projects than megaprojects.
“For us, two-thirds of the capital that we’re going to spend over the next five years is going to be on projects that we can deliver in a year to two years,” the deputy chief financial officer said.
“The only projects in our portfolio that we plan to develop that would have longer development times than that would be a second asphalt refinery at Lloydminster—because it’s such a good business—and the West White Rose extension offshore Newfoundland.”
In the oilsands sector, Husky’s near-term focus will be on ramping up its Sunrise Phase 1 SAGD production to full plant capacity of 60,000 bbls/d.
“And we’ve got a solid plan to do that by the end of 2018—at which point we’ll then turn our focus to de-bottlenecking and the low-hanging fruit from there,” Andruko said.
As for future phases of Sunrise, he said the aim is to cut costs. “Our goal will be to bring those future phases to a cost structure that gets us that 10 per cent return when oil is at $45.”
Cenovus deferred three oilsands projects in late 2014 and early 2015. Last December, the company announced the restarting of one of those, the 50,000-bbl/d Christina Lake Phase G. That SAGD project is expected to be on stream in 2019.
The in situ oilsands producer has said the other two deferred projects—Foster Creek Phase H and Narrows Lake Phase A—will have to await debt reduction. Cenovus borrowed money to help pay for the $17.7-billion acquisition of oilsands and Deep Basin assets from ConocoPhillips.
“We will not be starting another oilsands project this year,” Al Reid, executive vice-president, environment, corporate affairs, legal and general counsel, said.
“And likely the first one that would get restarted is Foster Creek H because it is further along,” he said. Cenovus recently raised its production target for the proposed Foster Creek Phase H to 40,000 bbls/d from 30,000 bbls/d.
Narrows Lake, which will be the first commercial-scale project to use the company’s solvent-aided process (SAP), is further away, Reid said. Cenovus also recently raised its Narrows Lake production target to 65,000 bbls/d from 45,000 bbls/d.
SAP adds a small amount of a natural gas liquid, such as propane or butane, to the steam injected into SAGD reservoirs.
Also, Reid said Cenovus won’t have two oilsands construction projects running concurrently.
However, thanks to its acquisition from ConocoPhillips, the company now has short-cycle assets in the Deep Basin to which capital will also be allocated. For 2017, Cenovus is running a three-rig program in the Deep Basin and will spend about $170 million.
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