Imagine it’s 2050 and bitumen can be sold for many times the price it commands today. But not as fuel to burn: its molecules will be transformed into carbon fibres, graphenes and other carbon-derived products to make electric cars, green buildings and flexible high-tech screens. Bolstered by this industry, Alberta’s economy is strong and steady.
Such future prosperity might be hard to imagine today. The global glut of oil has deeply cut prices and production. This year, ExxonMobil slashed 3.5 billion barrels of oil sands crude from its proven reserves because it estimated the cost to produce it would be higher than its potential sale price. Oil giants Royal Dutch Shell and ConocoPhillips both sold most of their Alberta assets; Norway’s Statoil ASA sold all.
Bloomberg predicts global oil demand could fall by two million barrels a day by 2028 or earlier, largely due to more people buying electric vehicles. Meanwhile, the Paris Agreement—the first universal climate accord, which Canada signed in December 2015—commits us to lower greenhouse gas emissions. To meet this goal, Alberta’s NDP government has capped greenhouse gas emissions from the oil sands at 100 megatonnes per year.
The low prices have hammered the province’s finances. Alberta’s non-renewable resource revenues in 2015/16 were $2.8-billion—down from an average of $9.3-billion over the previous five years. The provincial deficit for 2016 was $10.8-billion. Accounting firm Deloitte sees “no clear indication as to when the deficits will cease.”
It has become accepted wisdom that the province needs to diversify its economy. But how? Enter the Energy Diversification Advisory Committee (EDAC), created by the government in October 2016. Its members see challenges ahead. “If things stay status quo, we’re going to lose people, the smartest ones first,” says Leo de Bever, the former CEO of the Alberta Investment Management Corporation and now a member of EDAC. “In the short term, we have to exploit oil and gas in the most responsible manner that we can. In the long term, we have to ask: What do we do with that stuff when we no longer burn it? We’re not spending enough time thinking about where we’re going. Our central goal should be: What’s an alternative use of carbon?”
One solution is to shift from simple, low-value extraction to value-added processing. Adding value—essentially processing the raw product more, or a lot more—means turning raw oil and gas into fuels and petrochemicals, the latter used as building blocks for industrial and consumer products. Processing, in the words of one industry expert, could move Alberta further along the oil and gas value chain and transform us from fossil fuel “lumberjacks” to “furniture makers.” The multibillion-dollar question, though, is: Will industry do it if government isn’t involved?
Further processing could transform us from fossil fuel “lumberjacks” to “furniture makers.”
Processing oil and gas in Alberta has long been a matter of hot debate. The argument has ping-ponged between calls to “leave it to the market” and assertions that government “must encourage” value-added processing within the province. The latter view has often prevailed.
In the 1970s Peter Lougheed’s Progressive Conservative government wanted to bolster the petrochemical sector by using the province’s massive and easily accessed supplies of ethane. The substance can be isolated from natural gas to make ethylene—used to manufacture plastics and detergents. Industry, however, showed little enthusiasm for the idea.
So—the story goes—a civil servant under then Energy Minister Don Getty started to hide gas pipeline permit requests in a drawer rather than process them. Facing the threat of a freeze in development, the gas companies perked up. The PCs then sweetened things with royalty credits for companies that committed to build ethane plants. And it worked. Four of Canada’s six ethane cracker plants were built in Alberta, and ethylene is now the largest input into Alberta’s plastic resins and plastic products industry. In 2015 the industry’s revenues were $6.3-billion, nearly half the total petrochemical sector revenues of $14-billion.
Another Lougheed-era idea was the Alberta Oil Sands Technology and Research Authority (AOSTRA), established in 1974 as a Crown corporation with a $100-million budget. AOSTRA supported basic and applied research—at universities and through sharing the costs of projects on private company leases—to turn Alberta’s vast bitumen deposits into a commercial oil sands industry. Steam-assisted gravity drainage (SAGD) technology, which allows for the extraction of underground, or “in situ,” bitumen resources, emerged from AOSTRA research.
Yet industry refused to put money into the development of SAGD. In a 2013 interview with Alberta Oil magazine, Clement Bowman, the agency’s first chairperson, recalled, “[SAGD] was funded 100 per cent by AOSTRA and this dramatically changed the industry. Developing in situ oil sands resources would have been much, much slower if not for AOSTRA.” Today 21 of Alberta’s 27 active oil sands projects use SAGD.
The province’s investment in value-added continued in 2007 with premier Ed Stelmach’s Bitumen Royalty-in-Kind (BRIK) program, where the province agreed to accept bitumen in lieu of cash royalties and send it to Alberta upgraders and refineries to—ideally—generate higher revenues. Eight new upgraders were proposed and hundreds of billions of dollars slated for investment. Alberta had a forecasted upgrading capacity of 3.4 million barrels per day at that time. Today? Total upgrading capacity is just 1.3 million barrels.
Andrew Leach says the biggest “value add” is taking oil sands ore and turning it into bitumen.
Most of those projects were abandoned. Suncor and Total E&P Canada’s Voyageur upgrader, for example, was scrapped in 2012—because margins between the cost of bitumen and upgraded oil were shrinking. A partially built concrete ruin near Fort McMurray is the only reminder of the $3.5-billion invested in the project. Yet the BRIK program persists.
The Sturgeon Refinery was built, despite the weaker-than-expected numbers, and it serves as an interesting case study. Sturgeon is a three-phase joint project between Canadian Natural Resources and North West Refining that will receive 75 per cent of its bitumen feedstock from the BRIK program. The refinery in Alberta’s Industrial Heartland, northeast of Edmonton by Fort Saskatchewan, will produce low-sulphur diesel, diluent and vacuum oil. Uniquely, the project will also capture nearly 4,000 tonnes of CO2 a day to inject into depleted oil fields. It’s the first refinery constructed in Canada since 1984, and its first phase could cost $9.3-billion—more than double the initial planning estimate of $4-billion. Loan payments for capital costs are “effectively guaranteed” by a contract with Alberta’s government.
Sturgeon’s cost overruns are a “boondoggle” according to former PC finance minister Ted Morton. To ensure the refinery got built, the PC government retained ownership of the bitumen and committed to pay the company a fee, or “toll,” to process it—a cost that adds up to $26-billion over the 30-year life of the contract. It is “almost impossible for the investment to break even,” Morton said in a 2015 interview with the Calgary Herald. “I would be surprised if there is a way out.”
Some still see value in the project. A December 2016 Conference Board of Canada report, “Is There Value in Adding Value?”, estimated Sturgeon will generate $385-million per year in direct and indirect tax revenues for government in addition to royalties on the sale of the refined fuel and products. It is also expected to create about 500 permanent jobs. Ian MacGregor, president and CEO of North West Refining, says such benefits are why government should subsidize the next phases of the project. “The government committed the barrels that they collect through the royalty system and we need them to do that again,” he told an industry publication, JWN, in April 2017. “We have to keep progressing down that [value] chain. …It’s an emergency now.”
Andrew Leach, a professor of energy policy at the University of Alberta, challenges that assumption. He says we’re already adding the biggest value by extracting “oil sands ore” buried under boreal forest and turning it into bitumen. “You convert [the ore] to something that is worth $30 or $40 or $50 a barrel, depending on the time. The margins—the value add—at that stage are much higher than going from bitumen to synthetic crude, or from synthetic crude to refined product.”
Subsidizing big upgraders and refineries, Leach says, can amount to a transfer of wealth to refinery owners and some Alberta workers rather than a benefit to all Albertans. “How do you prioritize government spending?” he says. “I wouldn’t say you spend the money either on refining or on schools and hospitals. It’s just a question of: Does this make sense as a government investment? Historically there hasn’t been a strong argument.”
Today, oil revenues in Alberta are still mostly linked to extraction. Five upgraders and four refineries are operating in the province, with the Sturgeon Refinery expected to be fully operational in early 2018. The refineries produce gasoline, diesel, oil lubricants and asphalt, but processed less than 20 per cent of Alberta’s total crude production in 2015. Most of the value-added crude production in the province comes from upgrading heavy oil and raw bitumen. The tar-like bitumen is mixed with diluent to flow through pipelines, or upgraded to synthetic crude oil, mostly for export to the US. In 2015 just 45 per cent of raw bitumen was upgraded in Alberta. That’s less than the 58 per cent in 2010—a move backward.
How has Alberta fared with revenues from processing, then? Today we are “Canada’s leading producer of petrochemicals,” with abundant supplies of methane and ethane, according to Alberta Energy. But the petrochemical sector—which adds value by using natural gas to produce petrochemicals for goods such as plastics, antifreeze and fertilizer—is still a relatively small part of our hydrocarbon industry. Natural gas and byproducts contributed $493-million to provincial revenues in 2015/16, or less than one-fifth of Alberta’s annual non-renewable resource revenues.
So, back to the ping-pong match between market and government. In a final report Alberta’s 2015 Royalty Review Advisory Panel said: “Alberta has never purely ‘left it to the market’ to determine the destiny of our resources.” The public interest question for government—now as in the past—is how to influence that destiny. In a December 2016 interview with The Tyee, Premier Rachel Notley said industry will pull all the bitumen it can out of the ground under the emissions cap: “It’s just a question of whether we get the maximum value for it as the owners of the resource.”
The answer, unsurprisingly, is unclear. In October 2016 Alberta’s Minister of Energy, Margaret McCuaig-Boyd, convened the EDAC to advise the government on this specific question: “What additional steps can Alberta take to build a more diversified and resilient energy economy that works with industry and communities to create jobs, moves the energy industry up the value chain, and diversifies the energy industry into new end products?”
EDAC has two co-chairs, Gil McGowan, president of the Alberta Federation of Labour, and Jeanette Patell from GE Canada, along with five other members, including economist Leo de Bever. The government formed the group after the royalty review panel recommended it support value-added opportunities for bitumen—through partial upgrading—and for natural gas, particularly propane, which is so abundant in Alberta that companies have paid to get rid of it.
The NDP government’s initial step was the Petrochemicals Diversification Program. In December 2016 it awarded $300-million in royalty credits to Pembina Pipeline Corp. and $200-million in credits to Inter Pipeline Ltd., to help each company build petrochemical plants—using propane as a feedstock—in the Heartland industrial zone. “Alberta is a tougher place to build,” said McCuaig-Boyd. Subsidies, she said, help to “overcome construction challenges and level the playing field with places like Louisiana.”
The NDP hopes to kick-start a propane-into-plastic-pellets program similar to the PC government’s 1970s-era ethane-to-ethylene project. Petrochemical companies, which don’t pay royalties, are awarded credits once a plant is operating. These credits can be traded to natural gas suppliers, which subtract the credits from what they would have paid the government in royalties. Inter Pipeline expects to make a final investment decision on a $1.85-billion propylene plant—and a separate, $1.3-billion polypropylene plant—late this year. Pembina says it will decide on a $4.2-billion propane-to-propylene-to-polypropylene plant by “mid-2018.” Propylene is used in products such as resins and aircraft de-icing fluids; polypropylene is a plastic found in everything from bottle caps to Canada’s new polymer dollar bills.
According to the province, the publicly subsidized projects would create at least 3,700 construction jobs and 345 permanent jobs. But profit is not guaranteed; petrochemical clusters in the US, the Middle East and China are already turning a surplus of propane into plastic pellets, potentially driving prices down. Some fear the Alberta initiative will be late to the market.
Subsidies can transfer wealth to owners and some workers rather than benefit all Albertans.
The most transformative proposal for the future is “bitumen beyond combustion” (BBC). Engineer Ed Brost, one of those who came up with the BBC concept, says we need to re-envision the resource. “The world is heading toward electrification of transport,” he says. “If we stop burning oil, the resource is useless unless we come up with other uses.” BBC would create premium asphalt, carbon fibre and other high-value products from bitumen, with little or no greenhouse gas emissions. Alberta Innovates, a provincially funded research corporation, is collaborating with the Bowman Centre in Ontario to establish a pilot project near Sarnia using bitumen piped from Alberta. AOSTRA’s Clement Bowman is an adviser. The project is in the lab research phase as proponents seek to build a business case.
If commercially feasible, a larger plant could be built near Fort Saskatchewan, says Brost. While there have been partnership talks with oil companies, “nobody’s come up with a cheque yet,” he says. “We’re creating a massive environmental [liability] in northern Alberta. If we’re going to do that, let’s at least maximize the benefits; we want to create wealth and jobs in Canada.”
In the short term “the economics have not been kind” to value-added within Alberta, the 2015 royalty review panel noted in its final report. But “partial upgrading of bitumen,” the panel argued, “offers a potential opportunity to diversify our product range.” Partial upgrading refers to processing bitumen so it will flow through a pipeline with minimal diluent. Raw bitumen typically needs about 30 per cent diluent, usually natural gas condensate, to flow through a pipeline. Eliminate the diluent, and 30 per cent more crude can be transported, which could mean less push from industry to build new export pipelines.
For companies extracting “that lovely, gooey bitumen”—as Wildrose energy critic Leela Aheer called it in the Legislature on December 12, 2016—partial upgrading is the “technological Holy Grail for the oil sands industry.” Partial upgrading “does not upgrade bitumen to a light crude, but to something resembling more of a medium or heavy crude, and at a lower cost per barrel than full upgrading,” according to a 2017 report from the University of Calgary’s School of Public Policy. Despite competition from an increasing abundance of US light crude, “gaps in several North American refineries could be filled by this partially upgraded Alberta oil.”
More than 10 different partial upgrading technologies are being developed for use in Alberta. None of them are commercialized. But several companies are close, including Calgary-based Nsolv, which has patented a technology in which a warm, purified solvent—usually butane or propane—is injected underground through horizontal wells, warming the bitumen until it flows into a production well. The process uses no water and lowers GHG emissions by up to 80 per cent compared to current SAGD processes.
Chemical engineer John Nenniger founded the company in 2003, building on his father Emil Nenniger’s research, which was started in the 1970s. In 2014 the company built a pilot plant on a Suncor lease near Fort McKay and produced 125,000 barrels of partially upgraded crude that needed no diluent to flow through a pipe. Now the company wants to build a commercial plant to prove the technology at industrial scale. It received technical endorsement and a $13-million grant from Sustainable Development Technology Canada (SDTC) in 2016, but that isn’t enough—a commercial plant could cost more than $100-million, and no energy major has put up the money. Nsolv CEO Joe Kuhach says government funding or incentives are likely needed to get over the hump. “We’re stuck in the valley of death,” he says.
Leah Lawrence, president and CEO of SDTC, says Nsolv’s situation is typical. “Death valley” is where most new energy technologies falter, she says. It’s the funding gap where majors won’t pay to be the “first adopter” of a new technology, and government won’t cover the costs of scaling up to commercialization. As in Nsolv’s case, the gap is surprisingly wide. A 2015 study by McKinsey & Co. found that in the energy sector it typically takes 31 years to go “from idea to 75 per cent market penetration”—admittedly a high sales volume—compared to 12 years for medicine and eight years for a good consumer product idea.
As Alberta contemplates becoming the furniture builder of the fossil fuel world, the debate will only intensify. “There’s no shortage of good ideas, but there’s a shortage of capital to try out ideas,” says de Bever. “My personal advice is we need another AOSTRA, a fund to support innovation. It should be independent of government, with clear principles, and it should be able to fund at scale and cut losses quickly if a project doesn’t work out.”
But investing public money for a long-term payoff is difficult for government in a four-year election cycle. Alberta’s royalty review panel said that for partial upgrading alone, the amount of government money needed to “move the needle” is about “$300-million.” The costs are even greater for other new technologies. Still, the public appetite to transition to new sources of clean energy grows. And Alberta’s economy remains stagnant. So what’s a government to do? The likely cost of doing nothing is decline.
“We must try new things,” says de Bever. “We’re in dire straits. A lack of imagination and a lack of openness to change is probably our biggest problem in Alberta.”
Tadzio Richards is an associate editor at Alberta Views.
