Northwest Upgrader still on track, chairman says

Ian MacGregor says he’s close to realizing his value added dream

November 07, 2012

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The North West Redwater Partnership’s refinery is still on the drawing board …
Illustration Anthony Tremmaglia

In hindsight, Ian MacGregor thinks it was an error tacking the word “upgrader” on to the name of the company he helped found in 2004. “We should have called ourselves North West Refining,” he says over the phone from his ranch outside of Calgary. “We’re building a refinery. We’re not building an upgrader.”

MacGregor has good reason to regret that decision. Upgraders – once a cornerstone of the Alberta government’s drive to squeeze more value-added products from its oil sands motherlode – aren’t exactly popular in industry circles.

Blueprints to build the multibillion-dollar mega-plants that process raw bitumen into synthetic crude oil have been shelved en masse by sector players. They consider them very risky investments because profits depend on the volatile difference between the price of bitumen and light synthetic crude oil. Instead, companies with new oil sands projects, and no upgraders built already, have opted to ship the bitumen out by pipeline to the United States and have it refined there.

This brings us back to MacGregor and his refinery, now going by the name of the North West Redwater Partnership. For seven years the oil patch veteran has toiled away at getting a state-of-the-art 150,000-barrel-per-day (bpd) complex built in Sturgeon County that will take bitumen and turn it into low sulfur diesel.

If it happens, and that’s still a big if as the partners – the private North West Upgrading Inc. and Canadian Natural Resources Ltd. – have yet to sanction it, MacGregor will have succeeded where many have failed. “Bitumen is hard to move. There are all kinds of shipping constraints. Our thinking was, why not make that into diesel here?”

 

While a decision is expected to be made before the end of 2012, in Alberta’s Industrial Heartland there are few signs that MacGregor’s refinery dream is poised to become a reality. At the future site of the facility, which got regulatory approval in 2007 and is located 45 kilometers northwest of Edmonton across the road from an Agrium Inc. fertilizer plant, a lonely sign bearing the green, gold and blue-colored insignia of the North West Redwater Partnership is the only indication this patch of farmland could be the site of a bitumen refinery.

MacGregor says plenty of work is being done behind the scenes. He says North West partnership has had about a thousand employees working on the project design, acquiring materials and developing a comprehensive plan that will allow the partners to build the complex as efficiently as possible. “We’ve spent significant amounts of money on it now, probably north of $700 million,” MacGregor says of the partners. “There are lots of horror stories in Alberta where people tried to start too quick and weren’t as organized as they should have been. We aren’t going to do that.”

MacGregor has emerged as the public face of the project for North West even though Douglas Quinn – who as an engineer with Shell Canada worked on the firm’s Scotford refinery in nearby Fort Saskatchewan – is the company’s president and CEO. The 63-year-old MacGregor serves as the chair of the company’s board of directors.

MacGregor’s résumé and status as a lifelong Albertan makes him a credible proponent of the refinery scheme. During his 30-plus year career, he’s founded or co-founded businesses in the oilfield services, exploration and productionand financial investment sectors.

That hasn’t stopped doubters from saying the project could never be done. But for MacGregor, the concept of building a refinery to process bitumen into liquid fuels always made sense. It’s a fossil fuel-driven world, and with 169 billion barrels of oil sands reserves in Alberta, MacGregor knew people were going to figure out ways to get as much of the stuff out of the ground as possible. He also noticed shipping bitumen through pipelines was encountering all kinds of public resistance. The solution: refine it in Alberta and turn it into a more valuable product – in this case low-sulfur diesel.

“You can’t burn bitumen in your truck. You’ve got to make it into something,” MacGregor says. “Bitumen is hard to move. There are all kinds of shipping constraints and we’re seeing that every day. Our thinking was, why not make that into diesel here? It’s a lot easier to ship it and export it. It’s fungible and it can go anywhere.”

Without the bitumen supply, no diesel can be made, and the North West refinery will get 37,500 barrels to feed into the first 50,000 bpd phase of the project from the Alberta government (CNRL will supply the remaining 12,500 barrels). The supply comes from the province’s bitumen royalty-in-kind, or BRIK, program. Alberta’s royalty framework gives the province the option to take its royalty share of bitumen in kind rather than cash. The rationale for developing the BRIK program was the government’s supply of bitumen could be used to strategically supply upgraders and refineries in Alberta, keeping the jobs these facilities would create in Alberta and generating additional revenue from the products they would make.

In February 2011, the Alberta government announced it had closed a deal with the North West Redwater Partnership to supply it with 37,500 barrels of bitumen. The government pays North West a processing fee to refine the bitumen. In turn, the government will receive the revenue from the diesel that will – hopefully – sell for a higher price on the market than the bitumen would. MacGregor says most of the diesel will be sold in Alberta, but there are potential markets elsewhere. “We are really interested in trying to develop alternative markets wherever we can,” he says. “We can meet carbon specs in California. We can send it to Europe. This is high-quality diesel.”

 

You don’t have to go too far to find evidence of Alberta’s value-added dream gone bad, however. Just a 15-minute drive east of the North West site lies the unfinished $5-billion, 260,000-barrel-per-day bitumen upgrader once proposed by BA Energy. Construction was halted in 2008 at the height of a global economic meltdown when the price of oil dropped to the $40-per-barrel range and available credit dried up.

The company quietly shut down construction that year and then filed for bankruptcy on the eve of 2009. Today, there is little sign of life at the fenced-in site, where a large tower reaches toward the sky and rusting fabricated equipment lies scattered about the weed-filled yard like skeletal remains.

The BA Energy experience – and deferred projects like Statoil Canada Ltd.’s $14.4- billion 240,000-barrel-per-day bitumen upgrader – show just how tricky the business of building upgraders and refineries is. Another notable example is Suncor Energy Inc.’s Voyageur upgrader slated for the Industrial Heartland’s Sturgeon County. This joint venture between Total E&P Canada and Suncor didn’t receive much of an endorsement from new Suncor CEO Steve Williams during a second quarter earnings call.

When quizzed about whether sanctioning Voyageur was imminent, Williams said a decision on Voyageur, as well as the Fort Hills and Joslyn mines, wouldn’t be made until the middle of 2013, at the earliest. “Indications are some of these projects are moving backwards, not forwards,” Williams said during the July earnings call. “I’m not worried about them going back and the review date potentially slipping as long as we are seeing cost improvements and quality improvements, which lead to better returns to shareholders.”

Given the view of large oil sands players like Suncor that upgrading and refining might not make economic sense in Alberta, is the North West project destined to be a multibillion-dollar white elephant? Hardly, says Satya Das, founder and principal of Edmonton-based consultancy firm Cambridge Strategies Inc.

A longtime value-added advocate, Das points to Shell Canada and its Scotford upgrader, where the company recently sanctioned the Quest carbon capture and storage (CCS) project that will take carbon dioxide produced at Scotford and store it underground as an example that value-added projects can work in Alberta. “Obviously Shell has deep pockets, but if it’s market viable for Shell to take this position, how can [other companies] take the default position that it’s not economical to upgrade bitumen here?”

MacGregor says since the project was approved by the Alberta Energy and Utilities Board in 2007, the economics of the refinery have only improved. Five years ago there was spare capacity in U.S. refineries. But the explosion of production from tight oil plays like North Dakota’s Bakken and the Eagle Ford in Texas, along with growing production from the oil sands, has obliterated any spare refinery capacity that existed in the U.S. Price discounts for Western Canadian crude have worsened, and MacGregor says that means it makes even more sense to refine the bitumen in Alberta and get a better price for a more valuable product.

Susan Cole thinks the North West project is a winner as well. The president of Enhance Energy may be a bit biased, as the refinery will provide CO2 – 1.2 million tonnes per year – for her company’s 240-kilometer-long Alberta Carbon Trunk Line. The ACTL will take CO2 and send it to south-central Alberta, where it will be used for enhanced oil recovery in aging oilfields before being stored underground.

Cole says anybody who doubts the North West project will be a success is underestimating the company’s management, particularly MacGregor. “I think Ian’s always a step ahead of everybody else,” Cole says. “He’s got a track record of a lot of things he envisioned coming to pass.”

It’s worth noting that the North West refinery will produce more than just diesel and CO2. Coveted liquids like diluent, naphtha, vacuum gas oil, butane, propane and ethane will also be produced, adding to the value chain. The venture now has a competitor, though, after the Canadian arm of South African-based Sasol Ltd. announced in September it was building an $8-billion facility in Fort Saskatchewan that will turn natural gas into 48,000 bpd of liquids. About 36,000 bpd of that will be diesel, the company says.

MacGregor doesn’t sound worried about the Sasol venture, however. “People tend to make decisions on a very short-term basis. What we are building will last 50 to 100 years,” MacGregor says. “You have to look at the long-term underlying economic forces when you are making these kinds of decisions. I think the future is bright – if you make the right things.”

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