Upgraders on the Backburner

Has Alberta priced itself out of the market? This article appears in the January 2009 issue of Oilsands Review

By Peter McKenzie-Brown The fall of 2000 was extraordinary. The global financial crisis suddenly went into warp speed. Nations desperate to soften the blow began an offense against collapsing capital markets but, their efforts notwithstanding, credit became scarce and more expensive. The business and political atmosphere quickly took on a sense of urgency, alarm and panic which will certainly take many months and possibly years to resolve.

The Fort Hills Energy Limited Partnership (led by Petro-Canada) dropped a bomb into that painful environment. The joint venture’s preliminary engineering and design work had found that estimated costs for the oilsands project had risen “considerably.” Petro-Canada said that. “Initial indications suggest that the estimated capital costs for the Project, as currently conceived, have increased in the range of 50%.” That would put the cost of Fort Hills – which will include an integrated oilsands mine and bitumen extraction plant near Syncrude and an upgrader near Fort Saskatchewan – at $23.8 billion. There was a great deal of consternation on the news. This combined with a general meltdown in equity markets, and there was blood on the streets.

Petro-Canada’s stock rapidly lost six years’ worth of share-price growth. A few days after Petro-Canada made its gloomy announcement – and still during this period of freefall – EnCana and partner ConocoPhillips announced that they had begun construction of new upgrading equipment at their Wood River, Illinois, refinery. The $3.6 billion project would add a 65,000 barrels per day coker to help process growing supplies of heavy crude oil; increase total crude oil refining capacity by 50,000 barrels per day to 356,000 barrels per day; more than double heavy crude oil refining capacity to 240,000 barrels per day; increase clean product yield by 10 percent to 89 percent; and eliminate 40,000 barrels per day of low-value asphalt production. The two companies had already begun expansions at their Foster Creek and Christina Lake SAGD joint ventures, where EnCana expects bitumen production to increase from 70,000 barrels per day at present to about 180,000 barrels per day in 2012.

 Out of the market? In response to these parallel announcements, financial analyst William Lacey of FirstEnergy Capital came out with a particularly thoughtful analysis in which he asked the question, “Has Alberta priced itself out of the market?”

At the risk of oversimplification, Lacey makes two points. First, economically speaking it makes far more sense for companies to develop SAGD (steam-assisted gravity drainage) projects to produce bitumen than to develop new Syncrude-style mines. Second, it makes economic sense to have that resource upgraded at US refineries. Following the logic of these ideas, he suggests that the best way to develop Canada’s oilsands would be to modify North America’s pipelines and refineries in such a way that more bitumen can be taken out of Alberta for upgrading and refining. Again at the risk of oversimplification, two numbers show the stark contrast between Fort Hills and the EnCana joint venture. The cost of producing a daily flowing barrel of oil through the Fort Hills project is in the US$180,000 range. The price EnCana/ConocoPhillips will pay to reach the same goal is about US$60,000 – consisting of $22,000 for bitumen production and $28,000 for refinery modifications. SAGD projects also have the advantage of a very small environmental footprint.

According to EnCana’s Alan Boras, the Christina Lake SAGD project “all in is a quarter section – the size of what traditionally was a small mixed farm. You can concentrate (steam-generating and other producing) facilities and have multiple wells from a single pad. Your fingertips are underground, although they stretch out in all directions. They aren’t visible from the surface.”

 In an interview, FirstEnergy’s William Lacey also acknowledged the importance of the system’s small environmental footprint. He added, “The joy of SAGD is its scalability. You can develop it over time, and you can use cash flow to help lever into the next phase.” “SAGD has its risks,” he acknowledged “– water treatment, reservoir quality, technical completions. There’s a lot more risk there than there is in mining. Mines, however, are all-or-nothing. You don’t produce your first barrel until you weld the last vessel in place. Capital cost inflation of (mining projects) means they have priced themselves out of the market. If you can just get this stuff (bitumen) down to the US Gulf coast, with some minor modifications to existing refineries there you could inexpensively upgrade the stuff.” He added, “There’s a finite amount of this you can do, of course, because of the need for diluent to ship the bitumen.”

Integration: In a sense, Lacey’s commentary only offers another economic argument for the trend toward continental integration that has been developing for decades. A recent study by consulting firm Wood Mackenzie argues that this movement is already well underway. According to the firm’s Lindsay Sword, “supply of Canadian oilsands products (to the Gulf) will increase by 2 million barrels per day between 2007 and 2015; half of this growth will be in Canadian heavy crude blends.” She added, “Refinery projects targeting Canadian heavy blends that we expect to proceed are aligned with our forecast of additional supply: Canadian heavy blends supply will increase by 1 million barrel per day by 2015, and projects that are planning on processing heavy blends will increase by 1.1 million barrels per day.”

In practice, this means the continental petroleum industry is on track to realize efficiencies by having greater volumes of bitumen upgraded in huge, American refinery complexes, as in the case of the Wood River project. However, Lacey acknowledges that the opportunities to realize such great efficiencies as those at the EnCana/ConocoPhillips project “are fairly limited.” “While there may not be any more opportunities to bring on upgraded oilsands product capacity at around $60,000 per barrel per day (as the EnCana project is doing), the latest data points reinforce our opinion that … modifications to North American refineries and expanded pipeline routes to handle bitumen provides significantly better returns on investment than building upgraders in Alberta, while adding barrels through a new SAGD project appears less expensive than from a new mine.”

This notion is not popular with Alberta, of course. Alberta Energy spokesman Jason Chance pointed out that the government is quite interested in keeping value-added processes in the province. Over 60 per cent of Alberta’s raw bitumen is upgraded in Alberta, and provincial energy strategy aims to increase those volumes. Chance acknowledges that Alberta is a high-cost environment, and that there are “labour and supply challenges,” but says the province is nonetheless committed to increasing the amount of bitumen upgraded in the province. One approach is the province’s “royalty-in-kind initiative.”

The province is evaluating expressions of interest from players who would like to upgrade Alberta’s royalty bitumen within the province. Royalty bitumen – bitumen the province will one day accept in lieu of royalty payments – would become a secure source of supply for the successful refiner or upgrader. Taking on this supply would eliminate their need to produce the stuff, but the successful company would have to upgrade it within Alberta’s borders.

Perfect Storm: At the time of the interview with Lacey, the business news was all-crisis, all the time. Oil prices were half their all-time highs, and energy stocks were hovering near multi-year lows. A discussion of the credit crunch was inevitable. Lacey began with this salvo: “The cost of capital is such an important part of (share-value) evaluation, and in this environment risk has therefore gone up.”

Think about it. The cost of developing an upgraded flowing barrel per day at Fort Hills costs $180,000. What can you compare that to in the open market? Based on stock market evaluations on the day Lacey was interviewed, if you decided instead to buy a public oilsands company, you could buy Canadian Oil Sands Trust – the major shareholder in Syncrude – for $100,000 per flowing barrel. You could buy Suncor for $90,000 or Imperial Oil for $80,000. As these numbers show, stock markets driven by panic are not efficient.

“We’re going through some short-term gyrations in oil prices and there are some global recessionary issues,” said Lacey, “but we will work our way through that. Last time I checked, (the global petroleum industry was) having some difficulty in replacing barrels, and this slow-down is making that problem even worse. We’re going to be in an even worse position coming out of it.” Looking into the longer-term, that will make production from Canada’s oilsands even more valuable. In the meantime, Canada’s petroleum industry may soon be in play.

In the case of EnCana, that risk is greatly reduced. “The EnCana split (into separate oil and natural gas companies) didn’t make any sense because it put assets into this market at such depressed values just opens yourself up for potential acquisition,” Lacey argued. “I’m not a protectionist, but I do want to make sure that companies that are sold are recognized for their value.” However, “this is a perfect storm for some of the very large-cap companies to use their balance sheets to buy up assets.”

One potential acquisitor is China, with more than $1 trillion in foreign currency reserves and an express desire to buy energy and other resource assets around the world. “They’re not stupid,” said Lacey, “they’re opportunistic. How opportunistic (they can be) is the question. (Western) governments are aware of their intentions. Will they allow them the opportunity to buy core petroleum assets? I would argue ‘No.’” He points instead to super-majors like Exxon Mobil as potential predators. The world’s top five publically traded oil companies finished 2008’s third quarter with $62-billion in cash and annual cash flow of $232-billion.

Compare that cash on hand to the depressed market capitalization of Canada’s premier energy companies at the beginning of December: EnCana ($39 billion); Husky Energy ($26 billion); Canadian Natural Resources ($24 billion); Imperial Oil ($33 billion); Suncor ($22 billion); Petro-Canada ($14 billion); Talisman Energy ($10 billion); and Nexen ($11 billion). The credit crisis into which Petro-Canada and EnCana made such dramatically different announcements has already become a yeasty period of adjustment – not only for the oilsands business, but for the industry as a whole.

For example, one sunny day in late October, PetroCanada announced that it would delay the Fort Hills upgrader, constructing the mine instead. That same day, Suncor announced that cuts to its capital spending would delay completion of the Voyageur upgrader by a year. Other large projects – Lacey suggests Imperial’s Kearl oil sands project as a real possibility – may be placed on the backburner.

The shift from mines to thermal projects will probably take on new importance. Perhaps more upgrading will be farmed out to US refiners at the expense of an expanded upgrading sector within Alberta. Questions of corporate survival and consolidation will arise and need to be answered. Some companies will cease to exist, and new or merged entities will take on leadership roles. For however long it lasts, the global credit crisis is likely to coincide with a period of rapid change for Canada’s petroleum industry.

Perhaps the aftermath of the 1986 oil price shock – when prices suddenly dropped by more than two-thirds and interest rates were in double digits – is the most recent analogue for what to expect. In those days, capital shortages changed everything, quickly. Because of high costs, primitive technology and relatively plentiful conventional oil prospects, in the post-collapse ‘80s the first projects to go were in situ oilsands developments. Because they now offer relatively inexpensive, predictable, long-term flows, this time they might be the ones most likely to stay in prospect. “I would speculate that (companies like ExxonMobil are) less fussed about where their share price is today,” said William Lacey. “They are more fussed about long-term prospects for replacing reserves in their portfolios....This is a huge opportunity time, but it requires people who have longer-term vision.”