Oilsands costs chopped by 30%
‘More than a glimmer of hope’
• Canadian oilsands players have drastically shaved costs during the past three years as they scramble to shrug off the perception that their operations are too costly to compete with U. S. shale and other rivals. “There is more than just a glimmer of hope but a potential line of sight to cutting capital costs down very significantly in coming years — even from current levels,” says Mike Dunn, an analyst with GMP FirstEnergy based in Calgary, who puts the costcutting at 30 per cent over the three years.
Construction costs have plummeted, while new production techniques have driven down the amount of steam required to bring bitumen to the surface, lowering costs and emissions.
Oilsands firms have also begun using roughly half the steel to build well pads compared to a few years ago, as designs are modified to be simpler and smaller.
The slew of measures has helped l ower breakeven costs across entire oilsands operations. Cenovus
Energy Inc. estimates its total break even price for 2017 will be just over US$40 for U. S. crude, down from over US$ 60 in 2014. The company has reduced the overall cost of its well- pad construction by between 35 and 55 per cent, and hopes to lower break- evens to below US$40 in the next five years.
U. S. crude benchmark West Texas Intermediate was trading at US$49.26 on Wednesday.
Suncor Energy Inc.’ s most recent estimates suggest a break- even WTI price of US$37 per barrel, and the company has cut back its total engineering hours for well pads by 90 per cent. It has also begun to replicate more cost- effective design models across its operations.
The Calgary- based company has already applied to the Alberta regulator to begin replicating its future operations at its Meadow Creek East lease.
“Replication will be a central focus of the next phase of oilsands growth,” Suncor chief executive Steve Williams said at an energy event in New York Wednesday.
Suncor has identified 10 locations where it plans to construct identical facilities over several years, each producing around 40,000 barrels per day. The first iteration is expected to begin producing oil about 2022.
Imperial Oil Ltd. has sketched out similar plans to move toward leaner facilities, while Husky Energy Inc. has begun building well pads at its steam-driven operations along the Alberta- Saskatchewan border in small, 10,000- bpd increments.
MEG Energy Corp., meanwhile, says it is profitable at US$ 45 WTI price, and has dramatically cut back its steam- to- oil ratio ( SOR), a measure of how much water is used to pro- duce a single barrel of oil. Due to the high costs of generating steam, SORs often serve as an industry metric to gauge efficiency.
MEG has al s o begun ramping up a new technology that injects non- condensed gas into wells as a way to better retain heat in the reservoir, lowering both emissions and capital requirements. Canadian Natural Resources Ltd. recently applied to the Alberta energy regulator to use a similar technology at its Kirby North project, currently under construction.
Earlier this year Suncor announced it was moving beyond the pilot phase with a technology that cuts water out of the production process entirely.
The oilsands have been synonymous with high costs even before oil markets collapsed three years ago. But doubts about the viability of the world’s third- largest proven oil reserve have grown increasingly acute in recent years, spurring sev- eral major internationals to sell their oilsands positions in favour of plays offering faster returns.
The remaining Canadian operators, including Suncor, Canadian Natural and Cenovus have continued to invest in the oilsands, despite commissioning highly capitalintensive projects just before oil prices crashed.
“Despite a recent slowdown in project additions, some remarkable trends are happening on the ground in ... Alberta that point to continued, if subdued, growth,” Peter Findlay, a Calgarybased energy analyst, wrote in a recent report for the Oxford Institute for Energy Studies.
The challenge for oilsands firms is partly one of perception, as they are viewed as being inherently costly, Findlay said, while U.S. shale projects are more likely to be judged on the merits of individual projects or operators.
“Sometimes the oilsands gets branded as a bit of a monolith more so than shale projects do,” Findlay said in an interview.
But some observers may have been too quick to write off the oilsands. Recent improvements in operating costs and break- even prices suggest a deep structural shift is underway, offering a crack of sunlight for producers. While major new oilsands developments are on the whole more costly than competitors, recent expansions are coming online at a fraction of the cost from just a few years ago.
The l atest 80,000- bpd expansion of Canadian Natural’s Horizon development will require a West Texas Intermediate price as low as the low-to-mid US$20 range, according to GMP FirstEnergy estimates.
The Syncrude Canada project operated by Suncor, and Canadian Natural’s Athabasca Oil Sands Project, which it recently purchased from Royal Dutch Shell PLC, are both reducing costs rapidly and are viable around the low US$ 30- perbarrel range, according to GMP FirstEnergy. The best wells in U. S. shale basins, by comparison, typically require US$ 30 to US$ 35 WTI prices.
GMP’s Dunn says t he improvements are partly a result of improved well- pad designs and other efficiencies, which have begun to trickle down into companies’ earnings reports.
Companies have al s o taken an axe to slash their running costs. Operating costs at Cenovus’s Christina Lake venture averaged $7.04 per barrel in the second quarter of 2017, according to Wood Mackenzie research. MEG’s nearby steam- driven project, also called Christina Lake, averaged $7.42 per barrel.
Meanwhile, Suncor’s Williams is pushing his company to reach the “ambitious target” of reducing operating costs across its operations to below $ 20 per barrel in the medium-to- long-term, compared to $28.28 at its Millenium and North Steepbank mines in the second quarter of 2017, according to Wood Mackenzie research.
“We’re still working toward it, but I can see us getting there,” Williams said on a recent conference call with analysts.
Even so, operating costs are only part of the picture. Cost overruns during the oil boom left oilsands companies with enormous capital investments that will take years to pay down, and analysts are careful not to overstate the shift.
New developments now coming online were commissioned when oil prices were around the US$ 100 mark, and would never be approved in today’s environment. Many proposed oilsands expansions remain on hold, while companies instead focus on repairing damaged balance sheets.
Much of the recent cost reductions were also achieved through avenues that are now exhausted, such as downsized workforces or cheaper contractor rates. Producers have also been aided by a weak Canadian dollar and the higher price for heavy oil relative to U. S. crude benchmarks, both of which seem unlikely to last.
Canadian Natural’s giant Horizon complex was $ 1.9 billion over budget in its original phase of construction. Capital costs at Imperial Oil’s Kearl Lake mine ballooned from its initial estimate of $ 7.9 billion to $ 12.9 billion, due to snags in the shipment of materials to site.
That hasn’t stopped major domestic operators from doubling down on northern Alberta’s bitumen deposits and snapping up around $30 billion in assets since the beginning of the 2017.
“Such counter- cyclical investments, though difficult to stomach at the time, have historically proven fruitful,” Findlay wrote in the Oxford Institute report, noting that despite numerous headwinds for the industry, “oilsands producers and investors have a number of reasons to feel sanguine.”