Canadian oil primed for modest recovery
Reversal of crude curtailments and improved capex spending are encouraging signs for the country’s principal producers
The Canadian oil and gas industry should experience a slight rebound this year. Cash-rich oil sands producers are planning to spend more to boost production, while the Alberta government is now allowing companies to exceed provincially imposed output caps if they ship extra barrels by incremental rail capacity.
Conversely, smaller oil and gas producers—most of whom have not had their crude production curtailed—are largely planning to cut back their capex and drilling programmes, yet again due to relatively low heavy crude and natural gas prices.
Canada’s top five oil and gas producers—all but Husky Energy holding major oil sands mining assets—are planning to boost their Canadian upstream capex by 9pc to C$13.53bn ($10.3bn) in 2020, whereas 16 of the smallest producers are planning to cut spending by 8pc to C$6.80bn (see Figure 1). This translates to an overall 2pc increase to C$20.33bn, likely representing almost two-thirds of total Canadian upstream capex this year.
Until last year, the Canadian oil and gas industry had not only reinvested excess cash in new capex over the past decade, but also increased spending capacity by taking on additional debt and issuing more shares. But this strategy was thrown into reverse last year, especially in western Canada. A lack of oil pipeline and rail capacity from the region tanked regional crude prices at the end of 2018, leading the Alberta provincial government to curtail the amount of oil companies could produce in the province to revive prices and revenues.
A lack of oil pipeline and rail capacity from the region tanked regional crude prices at the end of 2018
At the same time, western Canadian natural gas has been losing market share to US production since the shale revolution took off south of the border, and especially since rapid development of the Marcellus formation began in the US northeast early last decade. As a result, gas prices at the Alberta AECO hub have averaged below C$2/mn ft³ most months since the middle of 2017, and have even traded in negative territory.
In a nutshell, why invest and add crude oil or natural gas capacity if you cannot produce it or it is not economic. According to Ontario-based ARC Financial, Canadian oil and gas capex—including downstream spending—was C$33bn in 2019, roughly C$17bn less than cash flow. This free cash flow (FCF) has gone towards higher dividends, share buybacks and debt repayment. Capital spending peaked at C$81bn in 2014 and has fallen every year since.
All of the top five Canadian oil and gas producers are expecting solid output growth in 2020, ranging between 4-7pc (see Figure 2), despite highly divergent capital spending plans for the year. Cenovus is leading the capex pack with a 37pc hike—albeit from a low base—Imperial Oil is at the rear with an 11pc cut, while Canadian Natural Resources Limited (CNRL), Husky and Suncor Energy are planning to increase spending between 7-12pc.
Cenovus has done well out of the Alberta government’s crude curtailment programme, with buoyant profits allowing it to pay down a large amount of debt in 2019—a concern after buying ConocoPhillip’s oil sands assets for C$17.7bn in May 2017, followed by six consecutive quarters of losses totaling C$3.76bn, culminating in a C$1.35bn loss in the fourth quarter of last year as regional crude prices cratered—and is now well positioned to move to full crude production.
2pc – Canadian capex increase 2020
The expansion of the company’s crude-by-rail facility in Edmonton to 100,000bl/d by the end of this year will allow it to take full advantage of the Alberta government’s special production allowances for crude moved by incremental rail capacity. Roughly 300,000bl/d of western Canadian oil was shipped by rail over the autumn, and it is believed the system may be able to handle between 500,000bl/d and 600,000bl/d by the end of this year.
To increase production by 7pc to 483,000bl/d oe in 2020, Cenovus is increasing upstream capex by over a third to C$1.03bn, and ramping up the 50,000bl/d Christina Lake Phase G thermal bitumen project, delayed by Alberta’s mandated production cuts.
End of curtailment?
Management at Suncor are less optimistic about the end of crude curtailment in 2020, whether by the special production allowances or midstreamer Enbridge’s 370,000bl/d Line 3 Replacement pipeline project coming online. The lower end of the company’s production guidance assumes volumes remain constrained through the year, whereas the upper end reflects an uncurtailed environment.
At the same time, much of the 12pc increase in Suncor’s upstream capex to C$4.75bn appears to be directed towards meeting its environmental objectives, not increasing productive capacity. This includes the company’s C$1.4bn spend over four years to replace coke-fired boilers at its oilsands Base Plant with an 800MW gas-fired cogeneration power plant. Suncor is projecting production to increase by only 4pc to 820,000bl/d oe, the slowest rate of growth of the top five producers.
It should be noted that Suncor has been hit disproportionately hard by Alberta’s mandated cuts, because neither the Fort Hills nor Syncrude oil sands mining projects were running at full capacity in 2018 when curtailment levels were set.
CNRL has also been boosted by the crude curtailment programme, with buoyant profits allowing it to add productive capacity through the C$2.8bn purchase of US independent Devon Energy’s Canadian assets in May, rather than the drill bit or power shovel. CNRL is planning to increase production by 5pc to 1.18mn bl/d oe in 2020, partly supported by a 7pc increase in upstream capex to C$4.05bn and the curtailment-delayed 40,000bl/d Kirby North thermal project coming online. CNRL indicated crude oil production could be 10,000-25,000bl/d higher this year, if not for Alberta’s mandatory curbs.
The focus of Husky’s Canadian upstream capex is much more diverse than the other top five producers, fairly equally divided between western and Atlantic Canada. The company is planning to increase spending by 9pc to C$2.38bn this year, and is projecting production to increase by 5pc to 260,000bl/d oe. The West White Rose project offshore Newfoundland and Labrador is about 55pc complete, with first oil planned by the end of 2022.
The management of Imperial Oil has been the curtailment programme’s harshest critics among Canada’s integrated oil companies—Suncor and Husky being the others—given these companies were well positioned to benefit from low cost oil. The ill will left by the programme appears to have negatively impacted Imperial’s upstream spending plans for Canada, with the company cutting capex by 11pc to C$1.32bn.
Imperial Oil had made a positive FID on the C$2.6bn Aspen thermal project in November 2018, but suspended the 70,000bl/d project in March 2019 after the Alberta government mandated production curbs. Adding insult to injury, crude-by-rail volumes shipped from its 210,000bl/d Edmonton facility collapsed along with the West Texas Intermediate (WTI)—Western Canadian Select (WCS) differential, making rail temporarily uneconomic.
Despite its capex cut, Imperial is still predicting a 6pc increase in production to 425,000bl/d oe in 2020.
Since the focus of the top five producers tends to be the oil sands, and mining in particular for all but Husky, the smaller producers are a major driver of drilling activity in Canada. The projected cut in upstream capex by these companies is expected to lead to another underwhelming year for Canadian drilling.
The Petroleum Services Association of Canada (PSAC) is forecasting a mere 4,500 wells to be drilled in Canada in 2020. The estimated total for 2019 was 5,000 wells, 2,000 less than originally forecast. Drilling activity has not been this low since 2016, when WTI averaged only $42/bl and industry cash flow was less than half current levels, based on ARC Financial data.
PSAC’s 2020 drilling forecast assumes $58/bl for WTI at Cushing, AECO natural gas at C$1.60/mn ft3, and the Canadian dollar averaging $0.76. The WTI-WCS differential recently shot to around $23/bn, almost $10 more than it averaged in 2019.
The IEA is forecasting Canadian oil—including NGLs—production to increase by 2.9pc, or 160,000bl/d, to 5.68mn bl/d in 2020, with a moderate gain for oil sands output but a decline in conventional—including tight rock—production. This appears a plausible outlook given previously constrained oil sands production from Alberta returning to the market, countered by a decline in conventional output given further declines in drilling activity.