High production case shows oil sands production exceeding 7 million (MM) b/d by 2038, over 5MM in reference case (currently 2.8MM b/d)
One of the most persistent myths perpetrated by the anti-oil sands brigade is that producing bitumen isn’t economic or profitable. A new study from the Canadian Energy Research Institute should put that myth to rest. In related news, a study from Drillinginfo shows just how close Alberta oil sands producers are to matching the best Permian Basin drillers on breakeven costs.
The study is CERI’s 12th annual, says Dinara Millington, director of research. One conclusion that should raise eyebrows in Alberta is that the rate of heavy crude oil production is predicted to almost double – from 2% to 3.75% – in the second half of the forecast period (2028 to 2038).
“The first 10 years are sort of an indication of lower prices than what they would be in the second part of the forecast period, but that also has to do with the projects that are currently under construction and then the ones that have been approved by the provincial regulator,” she said in an interview.
CERI expects West Texas Intermediate (WTI) to average $60/b USD for the next decade, rising to $80/b USD in the second decade, even though Saudi Arabia has said publicly its preferred price is $80 in order to prop up government revenues and the Saudi Aramco initial public offering expected in 2019.
But the real eye-opener in the CERI report is oil sands break even costs.
The plant gate supply costs (which exclude transportation and blending costs) are CDN$44.70/b for a greenfield SAGD (steam-assisted gravity drainage) project and CDN$28.66/b for a brownfield – or expansion phase – of SAGD. Greenfield costs have risen only one per cent since last year, according to the study.
The WTI equivalent supply costs at the Cushing, Oklahoma transportation hub are US$60.17/b for greenfield and US$51.59/bbl for brownfield projects. With WTI Cushing trading at $70.70/b Monday morning, Millington says even greenfield oil sands SAGD projects are economic.
“The relative position of oil sands projects against other crude oils is comparatively competitive, and as oil prices are expected to increase, so will the profitability of oil sands projects,” the study says, though “risk factors” such as market access and the currency exchange rate could affect project economics in the future.
Millington says that oil sands producers like Cenovus and Suncor will be focusing their attention on the costs they can control, lowering them to be “on par or lower than those of conventional wells.”
“The direction they want to make sure that the oil sands is not the marginal global barrel, that it does come within the cost profile of some of the other basins around the world,” she said.
A recent study on Permian Basin break even costs from Drillinginfo suggests the oil sands is more than competitive.
“The Permian holds some of the best break even economics in the US, but not all leases and holdings are created equal,” said Bernadette Johnson, VP of market intelligence in a press release.
“We’ve taken a look at all the companies operating here and ranked them by output and breakeven prices showcasing which operators are ‘in-the-money’ in today’s current price environment, as well as who can weather further price storms – and just as importantly, who cannot.”
Turns out there are a startling number of Permian producers who are not “in the money,” as Drillinginfo’s chart nicely illustrates.
Storm clouds are gathering for America’s most prolific basin that may delay profitability even longer.
“We also see takeaway capacity nearing its limits in the Permian and constraints could have consequences for some,” said Johnson. “Some will thrive while others will barely survive.”
Alberta oil sands producers also enjoy stable long-term production for two or three decades, the opposite of US shale production.
“The cost estimates of SAGD vs. tight oil projects are similar, but where oil sands has an advantage over tight oil is once the wells are drilled for a SAGD, production rate is constant without additional need to drill wells for a multidecade operations,” Millington said.
“In tight oil plays, drilling has to be happen continuously in order to maintain production.”
Asked if the low decline rate of SAGD production better positions it to weather price fluctuations, Millington replied that once up front capital costs are paid off, production costs are really only operating costs.
Harbir Chhina, VP of technology for Cenovus, told Energi News last year that his company’s cash operating costs were $7/b to $10/b and he expected them to drop a further 2o per cent over the next decade.
For that reason, “production even in low price environment will continue, despite it being sold at lower prices because it is harder to shut down an already operating SAGD project than a tight oil project,” said Millington.
The stacked column graphic and the bar graphic are basically unreadable at the size presented in the article.