Let’s be clear — it’s a refinery, not an upgrader
President touts carbon-capture virtues of Sturgeon County project
If Ian MacGregor could climb to the top of a hydrocracker reactor tower at the Sturgeon Refinery, he might first use his giant steel pulpit to shout out that the project isn’t an upgrader.
In the long list of what he sees as misconceptions about the project, that one might be the most obvious.
“I made the mistake when we first started that I called the company North West Upgrading rather than North West Refining,” MacGregor said in an interview.
“I’ve lived to regret that for the last 10 years.”
MacGregor is president, chief executive and board chairman at North West Upgrading Inc., which is building the $8.5-billion refinery in Sturgeon County, 45 kilometres northeast of Edmonton. Construction of the first phase, the first of three planned, is expected to be complete in 2017.
An upgrader would convert bitumen into synthetic crude for refining elsewhere. The Sturgeon Refinery will take 79,000 barrels of diluted bitumen per day — most of it supplied by the Alberta government — and make it into ultra low sulphur diesel fuel and other high-value products including diluent, a light hydrocarbon used to dilute bitumen for transport by pipeline, and low-sulphur vacuum gas oil.
“What we do is different than upgrading,” MacGregor said. “We make products that are finished, and they don’t need any intermediate processing. And those products are short in Western Canada. We don’t even supply enough to meet our own demand today, and that’s a situation that’s unlikely to change. And they are also products that are ... in demand by the world.”
The refinery, the first to be built in Canada in three decades, is also the first designed with an integrated system to capture carbon dioxide produced during the refining process. Efforts to capture CO2 instead of letting it escape into the atmosphere are increasingly important for Alberta’s energy industry given the global political pressure to combat climate change caused by green house gas emissions.
A gasification unit will take the heaviest, lowest-value portion of the feedstock bitumen and convert it into hydrogen and pure C02.
The refinery’s first phase will capture nearly 4,000 tonnes of CO2 each day — 1.3 million tonnes a year. It will be sold to Enhance Energy’s Alberta Carbon Trunk Line for use in enhanced oil recovery from depleted oilfields in central Alberta.
The hydrogen will go to the hydrocracker, which will use heat and pressure to break down complex petroleum molecules into diesel fuel that will be among the lowest-carbon petroleum fuels produced anywhere.
MacGregor said the refinery’s clean-burning diesel will meet the type of lowcarbon fuel standards seen in California and other jurisdictions.
“This is a really good CO2 story, and it would be a shame for people not to understand that,” he said. “There’s a chance, if we do it right, that we make low-CO2 products and we increase the value of our resources here significantly.
“And without putting the whole system together — without having the pipeline to take the CO2 away, combined with the process that we’ve chosen to make the diesel — you can’t do all that.
“People weren’t paying attention to it before, because they weren’t worried about CO2. But today we’ve got this tremendous competitive advantage — we can manage CO2 here and make our products the best ones, in terms of CO2, in the world, and that’s just got to be good for the future.”
The refinery will be owned and operated by the North West Redwater Partnership, an alliance between North West Upgrading and Canadian Natural Upgrading Ltd., a subsidiary of Canadian Natural Resources Ltd.
Under a 2011 agreement that covers the first of three potential refinery phases, each with similar capacity, the Alberta government will provide 75 per cent of the diluted bitumen feedstock. Canadian Natural will supply the remaining 25 per cent.
The Crown bitumen will be provided under Alberta’s bitumen royalty in kind (BRIK) program, which was designed to encourage in-province upgrading, refining and petrochemical development.
The facility has drawn plenty of political fire over its escalating cost. In June 2014, six months after the refinery’s cost estimate was bumped from $5.7 billion to $8.5 billion, Alberta’s then-Progressive Conservative government revealed processing fees would be an estimated $26 billion over the 30-year agreement, up from the previous estimate of $19 billion.
For years, the government had said that after processing fees were paid, the Crown could expect to make an extra $200 million to $700 million over the life of the deal by selling diesel rather than bitumen.
While nobody can predict where bitumen and diesel prices will go in the future, MacGregor considers the estimate too conservative.
Based on average prices in the last four years, he said, the government would have taken in an extra $200 million annually if the refinery had been operating. Even using the lowest oil prices seen in 2015 to date, he figures the government would have earned $150 million this year.
Using the same assumptions included in the $26-billion estimate for processing fees — in particular a two-per-cent annual inflation rate on selling prices of products —Mac Gregor says the Crown could make up to $13.5 billion over the life of the contract, based on prices and margins seen in the last four years.
This April, in a paper that had wide circulation in media and throughout political and business circles, former PC finance minister Ted Morton slammed the project’s economics, calling it “a multibillion dollar boondoggle with high risks for Alberta taxpayers.” He said that at $26 billion in processing fees, the government would be paying $63 per barrel to convert bitumen into diesel.
MacGregor is rankled by Morton’s arithmetic. The per-barrel processing cost will actually work out to less than $35, he says.
In thew eeks since the May 5 election that saw Alberta elect an NDP government, premier Rachel Notley has touted the economic benefits of doing more refining and upgrading within the province.
In the legislature on June 17, Alberta Party Leader Greg Clark asked Energy Minister Marg McCuaig-Boyd if the NDP government will “continue the North West upgrader boondoggle, a project which will cost Alberta taxpayers $26 billion?”
McCuaig-Boyd’s response was short on details: “As with all the projects, we are consulting with industry as we move forward and looking at the pros and cons of all of that,” she said. “Again, we’re in constant consultation with industry to look at those projects that will bring value and jobs to Alberta.”
MacGregor hasn’t yet spoken with McCuaig-Boyd or anyone else in the new government but expects to have discussions when the time is right.
“I’ve always believed we’re doing the right thing and I think that’s what they want,” he said, “so I don’t expect to be misaligned with them.”
He cautioned that if the government encourages more new refineries to be built, they will take years to get going. He’s been working on the Sturgeon Refinery for more than 10 years.
“These take an enormous amount of capital just to start. Before we had a permit we had spent $300 million. And so many people talk about it ... but there’s few people in the room when you start saying, ‘Well, have you got the $300 million you need to start?’”
The refinery’s first phase, meanwhile, is taking shape on a parcel of land in Alberta’s Industrial Heartland, Canada’s largest hydrocarbon processing region. About $3.5 billion has been spent on the project to date. Daily expenditures are in the $10-million range.
The hydrocracking reactor, 33 metres tall, is in place. Shipped from Japan in pieces, the parts alone took four years to produce at a cost of more than $100 million, MacGregor said.
The refinery construction is employing 2,400 workers on-site, with another 1,000 welders and other workers in modular shops around Edmonton.
About 1,000 engineers are still involved, and the partnership has 400 people on its own staff.
The on-site workforce will increase to 5,000 by mid2016 and remain at that level until construction wraps up in 2017.
The refinery’s first phase is expected to go into operation in the fall of 2017 with a workforce of about 400 people.
Production from the first phase will supply the western Canadian market for diesel fuel, while the expanded capacity of the second and third phases would help the refinery get its products to other markets in the U.S., China and India, MacGregor said.
The refinery will be a fixture in Alberta’s industrial landscape for a long time to come, he added.
“It’s a 30-year contract we have (with the government) but they have an option to renew at the end of 30 years.
“When I look around at refinery sites, as long as there’s plentiful feedstock, they last for 100 years, because you keep rebuilding them and improving them.
“I’m thinking this thing is still going to be here 100 years from now.”