Alberta Premier Rachel Notley took to a podium again this week to discuss economic diversification in the province, and then announced a $1-billion commitment for the province’s oil industry.
Call it diversification, Alberta-style.
Small ironies aside, the province’s new plan to develop “partial upgrading” technology is at least a ray of sunshine for Alberta’s wounded oilpatch.
The idea may not sound sexy, but if the sector can pull off the engineering feat, it could save the industry billions of dollars and help keep stifling pipeline bottlenecks at bay.
“Partial upgrading technology is a game changer, potentially,” says Ben Brunnen of the Canadian Association of Petroleum Producers (CAPP).
But questions remain: who will invest, how long will it take to develop and what are the risk to taxpayers?
“There is a defensible case for providing public support,” says Trevor Tombe, an economist at the University of Calgary.
“The risk though is this may link the government to a… facility that, in the event of cost overruns, the government may feel compelled to offer additional support.”
Gooey and hard to move
Alberta’s oilsands are a vast resource, but moving its thick, gooey bitumen through a pipeline is like trying to blow chunky peanut butter through a straw.
For bitumen to pass through pipelines, producers add a light hydrocarbon, called diluent, that helps it flow better. But it’s not a cheap process. Oilsands companies spent $13 billion on diluent in 2016.
There are also a limited number of refineries capable of processing it.
The double-whammy dealt by a small market and higher transportation costs means Alberta producers sell their product at a steep discount.
But if the bitumen were partly refined into something less heavy and sticky, there would be less need for pricey diluent to help it flow — and more could flow in existing pipelines.
Partial upgrading, which could turn bitumen into a crude product better suited for refineries, is a potential solution with “significant merit,” says researcher Kent Fellows at the University of Calgary’s School of Public Policy.
“It’s a longer timeline but that doesn’t mean that we shouldn’t move now.” – Kent Fellows, University of Calgary’s School of Public Policy
Fellows and three colleagues examined the technology’s potential. Their report, issued last year, found that while full upgraders are uneconomical without major subsidies, partial upgrading offers an economic middle ground.
In addition to the diluent savings, partial upgrading would mean 30 per cent more oil could be carried in existing pipelines, the report said. It could also add an average of $505 million annually to Alberta’s GDP.
And there was one other important finding: partial upgrading could create thousands of jobs from construction through operation — surely a point that would appeal to blue-collar workers and play well for the NDP.
Cracking the nut
“Partial upgrading” is a term unfamiliar to most people, but Ed Veith, a petroleum engineer, has been involved with companies trying to crack that nut since the early 2000s.
He can now see the finish line.
“We’re excited,” says Veith, president of Fractal Systems.
There are roughly 10 partial upgrading technologies in various stages of development in Alberta.
Fractal released results of year-long tests last month, announcing its technology succeeded in reducing the need for diluent by up to 53 per cent while also improving oil quality.
Veith says a Fractal facility built at an oilsands project would cost about $275 million.
It would result in savings from lower transportation and diluent costs of about $7.50 per barrel, based on average prices in 2017. A standalone hub facility would cost about $500 million.
“Contrast it to [the cost of] a full upgrader and… we’re on the opposite end of the spectrum,” he says, pointing out how much less expensive a partial upgrader would be compared to a full upgrader.
If Alberta could begin partial upgrading tomorrow, it wouldn’t be soon enough for some.
But even in the best-case scenario, a full-scale facility is still likely years away. One challenge is the pace of the regulatory process, another is getting investors to bet on a technology still in the development phase.
“We don’t know exactly where it [the product] is going to be priced; we don’t know exactly who’s going to want it,” says Fellows.
“At this stage, the money is about trying to get these field units at the commercial scale and seeing what that market looks like.”
Commercialization of the technology comes with risk, says Brunnen, when balance sheets in the oil sector are stretched.
The province hopes it’s dangling a carrot.
Alberta will provide roughly $800 million in loan guarantees and $200 million in direct grants over eight years to private-sector firms pursuing partial upgrading.
The goal is for it to spur $5 billion in private sector investment, funding construction of two to five partial upgrading facilities.
But with few other details available, the outcome isn’t yet clear.
“It’s a little bit early to determine whether this is going to move the needle,” says Brunnen of CAPP.
Money well spent?
During Monday’s announcement in Edmonton, Notley said there’s a place for the government in fostering energy innovation.
“We don’t need to sit on the sideline and watch places like Louisiana eat our lunch,” she says.
Not everyone will agree.
Investing in upgrading has been proven costly for Alberta governments in the past, perhaps none more painful than the Bi-Provincial Upgrader in the 1980s and 1990s.
The province’s commitment to the North West Redwater Partnership refinery project also invited scrutiny over the potential risk to taxpayers due to cost estimates that ballooned to $9.3 billion in 2017 from $6.5 billion in 2011.
Last month, Alberta’s auditor general said in his latest report that the Alberta Petroleum Marketing Commission (APMC) isn’t able to prove it is managing the risks presented by the refinery..
The anticipated cost of building a partial upgrading facility is expected to be a fraction of that of a full upgrader.
But in the wake of Monday’s announcement, University of Alberta energy economist Andrew Leach was among those to question how far the government was prepared to go to ensure the project succeeded once it had committed to it.
Tombe from the University of Calgary said no one wants to see good money thrown after bad.
But, generally speaking, he thinks there appears to be limited taxpayer exposure in the strategy that’s aimed at advancing a technology that holds much promise.
“It is not the government trying to push something that doesn’t have the business case behind it,” he says.
And with the commitment, Fellows from the University of Calgary believes full-scale commercialization of the technology is a matter of when, not if.
“In terms of how far out we are, you’re probably measuring this certainly in years not months, because you need time to get regulatory approvals in line,” he says.
“It’s a longer timeline but that doesn’t mean that we shouldn’t move now.”