Technology to capture Alberta's greenhouse gases from the oil sands could not only reduce the industry's carbon footprint, but also generate billions in additional royalties every year, according to a new study.
The independent report drafted for the government sheds new light on the huge effort - and cost - needed to dramatically reduce emissions in a province that generates most of its electricity from coal, and produces most of its crude from oil sands. But it also outlines the potential benefits.
It will likely take a joint federal-provincial commitment of $1-billion to $3-billion a year for a decade to make the technology work on a commercial level in Alberta, according to the Alberta Carbon Capture and Storage Development Council.
That prospect drew criticism from the provincial NDP, which called it a "boondoggle" that could trigger "staggering tax hikes."
The council, chaired by former Syncrude president Jim Carter, found that the cost of extracting carbon out of some exhaust streams - in particular, those at in situ oil sands operations that use steam to extract bitumen - could reach over $250 a tonne. That's equivalent to $11 a barrel, a massive additional cost that government would have to help shoulder.
But if Alberta invests the money into cheaper carbon-capture alternatives, such as coal-fired power plants and, later, the upgraders that transform bitumen into a refinery-ready light crude, the province could actually find itself with a new oil bonanza on its hands, the report finds.
The reason: All of that captured gas could be pumped into exhausted old oil wells, and help bring them back to life.
It's a process called "enhanced oil recovery," and the report calculates that at oil prices of $75, such projects could increase the province's reserves of conventional - or non-oil sands - crude by about 50 per cent. That would generate an impressive $11- to $25-billion in extra taxes and royalties for the province - enough to potentially pay off the government's carbon capture investment.
If oil prices rise to $125 a barrel, the government take from new production could rise as high as $81-billion.
"I like to categorize it as similar to oil sands development, and even the offshore Hibernia project," said Mr. Carter, the council chairman. "We wouldn't have had those if we hadn't had government and private enterprise working together. And today all of those things are significant vehicles for the Canadian economy."
The report is the first to make such an explicit link between the cost of meeting Alberta's greenhouse gas target - which would reduce emissions by 20 million to 25 million tonnes a year by 2020 - and the potential benefits.
"This is an investment. It's not a subsidy or cash dump," said Mike Long, a spokesman for Alberta electricity provider Capital Power Corp., which has long been a proponent of that very idea. "If you look at the royalty return on this, it's an investment and will pay off more so in the end."
Capital Power is behind one of three projects that the Alberta government has made eligible for funding to build a pilot carbon project. The $2-billion carbon-capture fund aims to have projects running by 2015. Additional funding of up to $3-billion a year would be needed between then and 2025 as work progresses to bring down the cost of the technology, Mr. Carter said.
Still, others are skeptical of how well anyone can predict the costs and benefits of capture technology the reports itself calls "embryonic."
"There's still a lot of open discussion about how much CO{-2} can be taken to enhanced oil recovery," said Wishart Robson, the climate-change adviser to Nexen Inc. chief executive officer Marvin Romanow.
But, Mr. Robson said, there is no doubt Alberta has a chance to use carbon capture to help generate additional money, an opportunity he called "unique."
"I can't think of many other jurisdictions in the world that actually have that kind of integrated opportunity to bring these forward at the same time."
Nathan VanderKlippe