National Post (National Edition)
BARRELLING FORTH
ALBERTA’S NEW STURGEON REFINERY IS EAGER TO PROVE THE DOUBTERS WRONG.
It’s been more than a dozen years since Ian MacGregor put in motion a plan to build a diesel refinery in Alberta, which he believes will demonstrate the benefits of producing high-value products at home rather than sending raw bitumen abroad.
But after years of delay, a price tag that surged to $9.5 billion (it was $4 billion in the very early days, then $5.7 billion, then $6.5 billion and then $8.6 billion), changes in government priorities and business conditions, and now some start-up pains, the Sturgeon refinery in Alberta’s Industrial Heartland is expected to produce the first diesel derived from synthetic crude oil at the end of the year, and the first diesel derived from bitumen in early 2018.
Sturgeon is the first brand new refinery to be built in Canada since 1984. It’s also the world’s first refinery to capture CO2 emissions from the get-go, making its barrels seven per cent less carbon intensive than the average crude.
Given Canada’s struggles with completing any new oil and gas projects, they are no small achievements. MacGregor hopes the refinery will inspire even more bitumen processing in Alberta, and alleviate some of the province’s big problems, namely the lack of economic diversification, carbon emissions and pipeline bottlenecks.
“It’s been almost like a sport in Alberta to make fun of this thing,” said MacGregor, 68, president and one of the largest shareholders of North West Refining Inc., which has an equal share in the project with Canadian Natural Resources Ltd.
MacGregor’s drive isn’t about money — he was wealthy before he started the project and has financial interests spanning oil services, real estate development and oil production — but something bigger.
“I came back to work after I retired, (because I believe) we need to do more of this in Alberta,” he said. “There is no reason we can’t have a million barrels a day in the Heartland (near Edmonton). We just have to prove that it works and get on the case and do it. And that protects the whole way of living not just of Alberta, but the whole goddam country.”
Yet many projects to upgrade more of Alberta’s large production of bitumen — in the province and elsewhere in Canada — are on hold or have been abandoned in recent years. They simply couldn’t compete with more economic and faster alternatives, such as buying, enlarging or re-tooling existing refineries, particularly in the U.S., that are closer to customers and where labour is cheaper.
Oil industry players have also had their own reasons for wanting to make the most of existing assets and value chains rather than building anew. Politicians have been reluctant to use incentives to fuel new processing plants in Alberta since past efforts to diversify the economy away from oil and gas production ended in costly failures. The latest challenge is that Ottawa is keener to build up renewable energy than new infrastructure in oil.
The result is that only 39 per cent of Alberta’s bitumen production is upgraded, and even less is refined, while the rest is processed in the United States, MacGregor said. Bitumen production was approximately 2.7 million barrels a day in 2016 and is expected to rise to four million barrels a day in 2030 as new projects ramp up, according to industry projections.
Nevertheless, the Sturgeon refinery, in no small measure due to MacGregor’s dogged determination to get it done, has pressed forward even though its doubters were almost just as dogged.
Concerns about the refinery surfaced again this summer following news that costs were continuing to climb, further exposing Alberta taxpayers since the project has received significant support from the provincial government. Opposition parties called for an investigation, which is ongoing, into the implications of the latest cost increases.
It didn’t help that some of North West Refining’s early investors were also looking for a way out. MacGregor, one of the largest shareholders, confirmed a sale process was initiated, but it is now on hold until the project is up and running.
MacGregor said he is not among the sellers, but some investors who bought into the company up to 15 years ago, when he raised $400 million in startup capital, thought it was time to cash out.
“There was lots of response,” said the engineer and avid collector of tools and machines (he has more than 10,000 pieces from all geographies and eras in his private underground Museum of Making at his ranch near Calgary). “But we are just so close to start-up, that we felt like, ‘Why are we doing this now? It’s going to be a lot more obvious once we have started and are running.’”
MacGregor adds it’s likely there will be shareholder changes, and it’s his job to produce the highest value he can for them.
One of the obvious buyers is partner Canadian Natural Resources Ltd. The company, which is digesting the acquisition of Royal Dutch Shell PLC’s oilsands business, wouldn’t say whether it’s interested in expanding its stake in the refinery.
But spokesperson Julie Woo said her company views the project as “value add to our shareholders by providing a competitive return and by providing demand for heavy barrels in close proximity to where the barrels are produced.”
Calgary-based AltaCorp Capital Inc. has a target value for NorthWest refining of $932 million, including equity, creep capacity and profit-sharing. The project also comes with tax pools that can be used to offset income of about $9 billion from the first phase.
In a Sept. 19 report to clients, AltaCorp said the sale process was slowed down due to “the state of the current energy capital markets combined with Phase I refinery start-up being so close at hand the company (wants) to demonstrate both facility and contractual performance.” It highlighted Northleaf Capital and Longbow Capital as key shareholders in addition to North West Refining.
MacGregor is confident the refinery’s business case is as strong as ever.
Once fully operational — 7,000 pieces of expensive equipment have to work properly together — it will process 50,000 barrels a day of bitumen, underpinned by an agreement that calls for the Alberta government to supply 37,500 b/d that it collects in royalty barrels for 30 years. (Canadian Natural Resources is providing the remaining 12,500 b/d in feedstock.)
Overall, the province receives 300,000 to 400,000 b/d from bitumen producers, the result of a policy adopted a decade ago to encourage diversification. The refinery is the first that uses Alberta’s royalty barrels.
The province also guaranteed some of the project’s debt, helping it get a high credit rating and, therefore, lower interest costs.
The project has two additional phases, which MacGregor expects will be less expensive to build because much of the pre-construction work has been done. If those go ahead, the refinery’s capacity will triple.
He said the capital cost of processing bitumen has declined to $16.50 a barrel from $17.03 when the contract with Alberta was signed. The decline is due to lower interest rates and because equity owners agreed to reduce their equity returns to five per cent from 10 per cent.
Taking operating costs into account, the plant’s total toll for processing bitumen is a bit more than $30 a barrel, which is what MacGregor promised in the early days.
That’s a bargain considering that diesel is worth a lot more than bitumen, which means higher returns for the upgraded product, he said.
Tim Pickering, chief investment officer at Auspice Capital Advisors, a commodities and alternative investment trading firm in Calgary, said building up refining capacity, just like building new export pipelines, is long overdue.
He said diesel this week was selling on average for US$153 a barrel worldwide, US$114 in the U.S. and US$142 in Canada, while bitumen was US$41 a barrel.
The refinery’s $9.5-billion price tag may be double its initial cost, but the discount applied to bitumen alone means Alberta is giving up around $10 billion a year in value, Pickering estimated. Shipping raw product rather than petroleum products leaves even more money on the table.
“Our economy is totally levered to bitumen — about 50 per cent of Alberta’s exports are bitumen,” MacGregor said. “And if bitumen is sick, we got trouble.”
Bitumen has three main problems, he said.
It’s sold at a discount because it’s the worst feedstock. It’s carbon intensive — 20-per-cent-more from well to wheels, according to the U.S. Department of Energy. And Canada is struggling to build new pipelines, so it’s better off shipping highervalued product in the pipelines it does have.
“You are essentially sending three-and-a-half times more money out of Alberta if you use those pipelines for diesel than if you use them for bitumen,” MacGregor said.
Besides, the price of its diesel is so high that it can also afford higher rail prices, he said.
The Conference Board of Canada, in a December, 2016, study evaluating the refinery’s business case, concluded it would be profitable across a broad range of prices for bitumen and its products.
IT’S BEEN ALMOST LIKE A SPORT … …TO MAKE FUN OF THIS THING
It also estimated the Alberta Petroleum Marketing Commission, as the agent for the Province of Alberta’s bitumen, would collect a minimum of $88 million a year from selling the diesel and other products produced by the refinery.
During construction, the refinery was expected to increase Canadian GDP by $7.9 billion, create 76,000 personyears of employment and generate $1.9 billion in government revenues, excluding royalties, the Conference Board said.
The project’s operations phase is expected to result in an average annual operating expenditure of $2.2 billion, which would increase Canadian GDP by an average of $2.3 billion, result in 6,658 jobs and generate $385 million in government revenues, excluding royalties.
Kevin Birn, executive director, North American crude oil markets, at global energy consultancy IHS Markit, said investing in heavy oil processing capacity, whether refining or upgrading, could work under certain conditions, but is not without risk.
Costs may have fallen during the oil price downturn, but Alberta is landlocked, which requires building many of the refinery’s pieces in the province, which is more expensive.
Meanwhile, an abundance of light tight oil will continue to put downward pressure on the value of light crude oil relative to heavy, reducing the margins and incentives to invest in incremental heavy oil processing in North America, said Birn, who is working on a new study on the economics of heavy oil upgrading in Alberta and elsewhere.
“Any new investments in refining capacity in Western Canada (whether it be Alberta or British Columbia) may face having to displace incumbents or, more likely, have to export exported offshore,” Birn said.
“This may complicate logistics and finding a party willing to commit to a mutually agreeable, long-term contract — likely an important factor in obtaining financing for a new export-oriented refining project.”
MacGregor argued there is a big market for diesel, pointing out the U.S. exports one million barrels a day, some of it to Canada. The refinery has contracts in place to serve markets in Alberta, B.C. and the western U.S. and can sell much further afield, particularly when the expansions kick in, he said.
The Sturgeon refinery also meets low carbon fuel standards without having to blend in costly biodiesel, making its diesel more desirable. The refinery’s low carbon footprint comes from the integration of carbon capture technology at the plant.
Alberta is establishing itself as a world leader in such technology, said Fatih Birol, the International Energy Agency’s executive director, at a conference in Winnipeg in mid-October.
Carbon capture will need to become globally widespread to meet the carbon reduction targets agreed to in Paris two years ago, he said.
Carbon capture at the Sturgeon refinery will start working about a year after it is in operation.
A related company, Enhance Energy Inc., plans to purchase the refinery’s carbon emissions and pipe them into depleted oilfields in Central Alberta to recover an additional one billion barrels of oil, resulting in further revenue for the project.
About $1 billion in financing is being put in place to build the Alberta Carbon Trunk Line this winter, MacGregor said.
But even though the project is close to the finish line, MacGregor acknowledges it is late and that costs are higher than anticipated, which he knows will keep fanning criticism.
“We are trying to make the future of the place, and every time something twitches, it’s like a big problem,” he said. But, he added, the refinery will prove to be a great piece of infrastructure once completed and “if I live long enough, that is what they will be saying about this thing.”
IF BITUMEN IS SICK WE GOT TROUBLE