Getting More for Less

Making a buck in North America’s most expensive gas basin. This article appears in the February 2009 issue of Oilweek.

By Peter McKenzie-Brown
North America’s natural gas business is going through fundamental change, but Alberta’s conventional gas sector isn’t well positioned to compete. As Canadian Natural Resources' president Steve Laut told a conference call when he was discussing his company’s deep cuts in capital spending for 2009. “We are drilling (for gas) in B.C. but cutting back in Alberta.

The oilsands can withstand (Alberta’s) higher royalties, and on the oil side, the government got it right, but they missed it on gas. Alberta is the worst place for gas development in North America, and likely the world.” Why are things so bad? Part of the problem is the province’s much-maligned new royalty regime, which sapped the industry’s motivation to invest in the province’s traditional source of supply, conventional gas. In November the province gave explorers the option to pay royalties at the old rate for four years, provided the wells were more than 1,000 metres deep and spudded after the New Year.

This eleventh-hour tinkering “will have an improvement on activity levels in the province,” according to Tristone Capital vice president Cristina Lopez, “but it will not improve the cash flow outlook for companies that are going into a difficult commodity-price environment.” That’s a major reason for the decline in conventional exploration and development. “There’s been a tendency to assume that as long as we have gas opportunities in Alberta, people will come here to invest their money to get it out,” said Dave Russum, who is head of geosciences at AJM Petroleum Consulting. “We should not automatically assume that will be the case. When you change the royalty system and make other such changes, then investors will go to other opportunities where they have other advantages – closer to markets, or where there’s a better royalty regime or a lower cost structure.”

He notes that until this year there has been an absolute correlation between wells drilled and gas prices: When prices went up, so did the number of wells. This year, prices went up but drilling in Alberta went down. Was this an unintended consequence of Alberta’s new royalty regime? Probably, but other economic factors are also at play. Geological targets are changing; costs and prices are fluctuating for reasons that have nothing to do with natural gas activity levels (think oilsands); new technologies are fundamentally changing the economics of development; and issues related to environmentally responsive, full-cost accounting are playing an increasingly important role in project approvals.

A Fourth Amigo...Again
Three Western countries – Norway, Canada and the Netherlands – are now self-sufficient in natural gas (the UK was among them until four years ago). Soon, another country could join that small but lucky band. If you were to hazard a guess, which country do you think might join that group? That country, whose conventional gas production peaked in 1972, began focusing on unconventional natural gas in the 1980s.

Today, the Lower 48 states are producing gas at rates near their 1972 peak. Increasing supplies from unconventional gas fields and coal-bed methane are outstripping by far the decline from conventional sources, and LNG production from Alaska is possible. A number of commentators have suggested that these factors could soon make the United States again self-sufficient. An obvious implication is that Canada must develop alternative markets to help create price security.

According to Russum, only six percent of the sedimentary rock in the Western Canada Basin is prospective for conventional natural gas. However, the bulk of the other rocks are prospective for biogenic gas, tight gas, fractured gas or shale gas. Coal bed methane represents a tiny additional wedge on his pie. This gas-prone basin, where conventional gas production is in decline, still hosts huge volumes of undeveloped hydrocarbons.That’s a point worth remembering.

The cost of developing and delivering Western Canada’s gas varies greatly from region to region, but the WCSB is still one of the world’s most expensive onshore basins to develop. A recently released National Energy Board map illustrated the geographical diversity in cost related to developing and producing these gas supplies. The average cost of gas supplies ranges from $11.18 per thousand cubic feet in the BC Foothills to $6.58 per thousand in the adjacent Alberta Deep Basin. For gas producers and analysts, the critical factor in the NEB analysis was that gas prices need to average $7.88 per thousand cubic feet for producers to generate a risked after-tax rate of return of 15% in this basin.

 Given an average Alberta spot price for natural gas around $6 during 2007, the report intoned, “the average economics for new gas development in western Canada were marginal.... These results are consistent with the general impressions expressed by industry players about the tight economics of new gas....”

 Costs and Prices
If the economics are as bad as this NEB report suggests, why is a fair amount of gas exploration even taking place? According to University of Calgary economics professor Robert Mansell, “It depends on your outlook on prices. If you look into the future and you see average prices in the future at $12, say, then you want to establish a position in that play. Even if you think gas prices will never go above $8, you may want to establish reserves at today’s costs. You could sell them to people who have expectations of higher prices.” It’s all about price and cost.

 Even though unconventional gas is more expensive to develop than conventional production, that’s where about 60% of natural gas activity is going. Like the US, which made great progress developing unconventional gas during an era of lower prices, Western Canada is developing these resources in a period of price/cost disequilibrium – that is, lower prices and higher costs.

This is counterintuitive. In classical economics, adversity in the gas industry – the lower margins and riskier business environment of the last few years, for example – would force the industry to drive down costs and increase efficiency. The U of C’s Mansell squelched that assumption, first zeroing in on the dynamic relationship between price and cost. “Costs drive prices,” he said, “but prices also drive costs.” Supply costs go up and down depending on activity levels, rig and services availability, materials, labour, technology, changes in well productivity, changing drilling targets, and changing fiscal and tax regimes.

Crown land prices go up and down as well. The main way the recent downturn would force the gas industry to become more efficient, said Mansell, would be through consolidation. “In this environment, there’s likely to be much more rationalization.” As smaller companies combine into larger ones, they generally become more efficient.

Technology
While companies employ cost-cutting measures (shutting in higher-cost gas supplies during tough times, for example), Mansell makes the case that real efficiencies are more likely to arise in periods of relative prosperity than in periods of economic adversity. “In a tight margin environment, would companies put more R&D and technology into increasing efficiency? It’s not clear. They actually have more free cash to play with in a higher price environment (and are therefore in a better position to increase efficiency). However, if a company is financially healthy, it can even increase profits in a low-cost environment by applying new technologies.” In other words, greater efficiency in the petroleum sector comes mostly from technology –improved drilling, seismic and other technologies used in exploration and development – along with the obvious benefits of such capital infrastructure as plant and pipeline.

According to Mansell, “It’s a dynamic environment. Mostly because of better know-how, over longer periods of time the industry is getting 1.5% to 2% more output per unit of input each year.” How is that happening? AJM’s Dave Russum puts a technical slant on things. “Per well costs are higher than in the past, that’s true. However, we now understand that in certain kinds of gas resources we can greatly increase productivity by increasing drilling density in lower-quality gas reserves. You need to be able to fracture the maximum amount of the reservoir.” So important has this trend become that it is contributing directly to the reduced number of wells being drilled in Canada. This year, nearly 40% of the wells drilled in Canada will involve horizontal or directional drilling – twice the level of ten years ago.

For the first time, First Energy Capital said in a recent research note, the number of horizontal wells will match the number directionally drilled, and more and more of well costs are in completion technology. Fracturing consists of injecting a fluid into a well to cracks or fractures already present in the formation and create new ones. Russum is especially keen on combining and the use of multi-stage fracturing techniques prior to completion of horizontal wells. “Between the heel and the toe of a horizontal well,” he says, “you can isolate an interval close to the toe, frack that region, then move back towards the heel, isolate another interval and do another frack. This breaks up a lot of rock, and makes a lot more gas available. These new technologies are enabling us to access a whole lot more low-permeability rock than you would ever be able to reach with a vertical well.”

As the U of C’s Mansell points out, “Current costs may not reflect future costs. As you learn more about the resource, costs could come down substantially – not only the cost of production, but also the cost of finding new reserves.” Recent innovations in fracking wells illustrate how this can happen. Companies have made great strides in increasing the number of fracks they can make in a single horizontal well. Horizontal wells drilled into shale reservoirs now average eight fracks each – an astonishing improvement from only ten years ago, but one that is causing potential bottlenecks in the system.

According to Kevin Lo of FirstEnergy Capital, to fracture just one of the Horn River shale gas wells in north-eastern BC, you need a fracturing crew equipped with more than 30,000 horsepower of compression. To put that in perspective, in Western Canada perhaps 800,000 horsepower is available. “We do not believe that there will be sufficient capacity to perform all of the jobs necessary, should (BC’s Horn River and Montney shale gas) plays grow,” he said in a research note. He also worried about the logistics of bringing in enough propping agent: fracturing a single horizontal well in these reservoirs can require up to two thousand tonnes of sand.

Stewardship
Another area where big changes are happening, of course, is in environmental practice and policy. Take the case of EnCana’s application to drill in the Suffield National Wildlife Area, where a hearing began last September. The gas at Suffield is shallow, biogenically-derived gas in mixed sand and shale sequences. Since it is not generated in the same temperature and pressure systems that create conventional hydrocarbons, shallow biogenic gas is an unconventional variety. The Milk River and Medicine Hat sands of south-eastern Alberta and south-western Saskatchewan are classic examples of this type of unconventional gas. This was the first gas produced in western Canada. It is continuously gas-producing, and it is the largest gas-producing region in the WCSB.

For efficient production of biogenic gas in this area you need close well spacing, and you generally can’t use horizontal drilling because the wells are so shallow. Developing production in these fields is almost like assembly-line manufacturing. You haul in a small rig on a system that causes minimal surface disturbance, drill and complete the well in a day. You can use nitrogen and CO2 fracks, which reduce environmental damage in really shallow wells. Then other crews come along, install the wellhead and tie production in to a pipeline.

Sounds pretty green, doesn’t it? Not according to the Alberta Wilderness Association’s Joyce Hildebrand. “Extracting resources is only one of the mandates of the government, whether at the provincial or federal level,” she says. “Another mandate given to the government by citizens of Canada and Alberta is to set aside environmentally significant areas so that they are off-limits to human activities, such as oil and gas exploration, that may compromise their natural values; to preserve species that have been designated as endangered, threatened or otherwise at risk, and to preserve the habitat that those species depend on.”

She adds, “The evidence is overwhelming that doubling the number of wells, and constructing the necessary associated infrastructure such as pipelines and roads, in the Suffield NWA will seriously compromise the habitat of (species at risk). If the habitat goes, the species go. So as a society, we need to decide whether we want to sacrifice the conservation of that endangered prairie ecosystem for the acceleration of the resources under the ground. Those two choices are incompatible – it’s one or the other. There is no possibility here of ‘balancing’ the two….The sooner we begin to work on a macroeconomic policy that is based on something other than the well-funded rhetoric that economic growth and conservation of wilderness is compatible, the better. The situation at Suffield is one example where that needs to be challenged.”

The issues are complex, and the ERCB has a long history of listening carefully to all sides and dealing with these situations fairly. However, this is only right. As the U of C’s Mansell explains, economic theory supports the environmentalists’ point of view. “In theory,” he says, “you want to be as close as possible to full-cost and-full benefit accounting from a social point of view. Policy decisions should incorporate all incremental benefits and the incremental costs – including costs and benefits that don’t necessarily show up in the market. How you estimate that isn’t an easy question to answer, but your accounting should be based on a benefit-cost analysis.”

Since a poll by the provincial government found that only 16% of Albertans believe the province does a good job of looking after the environment, this story has legs. So there you have it. Alberta may be “the worst place for gas development in North America.” However, the WCSB remains an important gas basin, and activity throughout the region is helping illustrate gathering industrial trends. On the policy side, issues related to full-cost accounting will likely take years to iron out – but at least they are being heard.

The Case against Dirty Oil

This article appears in the February 2009 issue of Oilsands Review; graphic taken from here.

By Peter McKenzie-Brown

“Two wars, a planet in peril, the worst financial crisis in a century.” In his victory speech in November, with those words Barack Obama summed up the challenges his new administration would face.

The phrase “a planet in peril” was, of course, shorthand for climate change and other environmental troubles. For those in the oilsands industry, it seemed to threaten lost market share. After all, during the campaign Senator Obama promised to ban imports of dirty oil – that is, oil that releases a great deal of CO2 during production and upgrading. At present, the United States is the only market for Alberta’s bitumen and upgraded oil.

This article suggests that the US market for oilsands producers may not be as secure as Canadian producers may hope. Canada can compete in the market, but it may increasingly be at the expense of other global oil producers as this continent’s energy mix changes. There are a lot of caveats to that theme – not least of which is that the drive to greener bitumen production is now an almost unstoppable force. In Canada’s traditional export market, the greenest producers may become the most successful players.

American legislators have already begun to target it as an easy way to reduce emissions without hurting American voters. For example, Congress has already passed a law banning federal government agencies from directly promoting energy projects that will emit greater greenhouse-gas emissions over their entire life cycle than conventional oil. A section of the US Energy Independence and Security Act of 2007 prevents federal agencies such as the military from entering into fuel contracts that directly encourage unconventional energy development. This could include the oilsands.

For its part, California has passed regulations requiring fuel suppliers to reduce the emissions from the fuel they sell – and to account for those emissions right back to the original source of production.

Energy calculus of this kind is unprecedented, and if followed to its logical conclusion could be devastating for Canada. The world’s largest per capita consumers of energy, Canadians are also the world’s largest per capita producers of CO2. Regulations that limit the carbon quotient in other imported goods could shut a variety of Canadian products out of American markets. Whether or not such rules will ever apply to other commodities, for oilsands producers these developments are immediate matters of deep concern.

Will President Obama, who often used green rhetoric on the campaign trail, continue down that road? “No”, according to Murray Smith – a one-time provincial energy minister who until recently served as Alberta’s representative in Washington, D.C.

“(Obama) was trained in the very tough political environment of Chicago. In order to operate inside today’s political conditions,” Smith said, he “must govern from the centre. From November 4th to the 5th, his move from the political spectrum of the left to the political spectrum of the middle was virtually instantaneous. So presidential candidate oratory that mentioned the oil and gas sector as a target for higher taxes, promises to increase environmental efficiency and to take other measures for energy efficiency measures are either already law or just promises.”

Smith added that the president is a “former senator from an important coal-producing state, a state that relies almost exclusively on coal for electricity generation. In fact, he sponsored an important coal-to-liquids bill” – albeit one that didn’t make it out of the Democratic caucus. In Smith’s view, “energy and environment will drop to tertiary issues as the USA digs itself out of the economic hole that the mortgage and housing crises dug.”

As if in support of this view of the world, in one of his first radio addresses after his win the president-elect put his energy program in the context of infrastructure projects. “We’ll put people back to work...building wind farms and solar panels; fuel-efficient cars and the alternative energy technologies that can free us from our dependence on foreign oil and keep our economy competitive in the years ahead.”

Unwilling to take a chance, the day after the election prime minister Stephen Harper proposed a joint US-Canada pact on climate change which would exempt production from Alberta’s oilsands from import controls on the grounds that it could contribute to Obama’s goal of making the US independent of Middle East sources of supply.

The Tar Sands Controversy: In Canada, the dirty oil question became a high-profile public issue with the publication of a rambling, ideologically incoherent and highly inaccurate book on the oilsands. Author Andrew Nikiforuk and his publisher promoted the book well, and environmental issues surrounding oilsands production got a great deal of play in the media. This touched raw environmental nerves across the continent.

Consider some of his statements, however. “Many tar sand projects puff out nearly a million tons of carbon dioxide a year.... A million tons – a megaton – is enough lethal carbon dioxide to fill one million two-storey, three-bedroom homes and suffocate every occupant.” Where do you start with such a statement? CO2 is no more lethal than water, and far less likely to become a disagreeable or life-threatening localized pollutant. Like water, it is essential for life.

Nikiforuk’s sloppiness is extraordinary. For example, his diatribe on carbon capture and storage (CCS) stumbles from technical blunder to unsubstantiated claim and shows no comprehension of the economics of the concept. Then, astonishingly, he pronounces the whole idea – a demonstrably safe (though expensive) system of pollution reduction already being used around the world – to be “morally bankrupt.” This seems an absurd term to apply to technologies that remove pollutants.

Straightening out the endless errors in this book would be a thankless and time-consuming job, but let the following illustrate Nikiforuk’s efforts to, apparently, deliberately mislead. “The average Canadian burns twenty-five barrels of oil a year,” he claims. “The average Albertan burns sixty barrels, due to an above-average use of fossil fuel toys such as ATVs, trucks and SUVs.”

In fact, Alberta’s energy use is higher than the national average because its industry is heavily focused on the energy-intensive businesses of producing and processing energy – including growing volumes of unconventional oil and gas, which are especially energy intensive. Consumer toys have almost nothing to do with it. The author of a book on the oilsands would surely know this.

The Princeton Wedges: At one end of the climate change spectrum are demagogues like Nikiforuk. At the other are those who say the issues are imaginary or, since they are unsolvable, irrelevant. A more pragmatic part of this latter group are those who, like St. Augustine 1500 years ago, ask to be granted “chastity and continence, but not yet.” Although concerned about the challenge, they hope CO2 emissions will be rendered “tertiary issues” because of the world’s financial meltdown or lack of political will, so they can postpone the cost of action.

In the centre are those concerned about the scientific consensus on climate change and global warming, and they are the group who will ensure the issue does not go away. Dirty oil became a campaign issue in Obama’s dignified presidential campaign because it is now a mainstream concern. That is unlikely to change.

A few years ago, physicist Robert Socolow and ecologist Stephen Pacala from Princeton University wrote that “Humanity already possesses the fundamental scientific, technical, and industrial know-how to solve the carbon and climate problem for the next half-century…. Although no element is a credible candidate for doing the entire job (or even half the job) by itself, the portfolio as a whole is large enough that not every element has to be used.” The world of environmental politics took note, and the concept of stabilization wedges – commonly called the “Princeton wedges” – was born. The wedges represent emissions that can be taken out of the world’s growing volumes of pollution by different techniques. In many quarters, they revolutionized thinking about greenhouse gas emissions.

Socolow and Pacala identified 15 strategies that could reduce business-as-usual increases in emissions by 25 billion tonnes of emissions over a 50-year period. They include using more efficient vehicles, developing more efficient buildings, and using natural gas instead of coal. Each stabilization wedge would lower the angle of the line representing carbon-emissions growth; together, they would reduce CO2 emissions enough to stabilize its concentration in the atmosphere. To put the magnitude of the problem in perspective, human activity is now adding 7 billion tonnes into the atmosphere annually. Unchecked, that figure will double in the next half century.

Each Princeton wedge is a steel-jacketed bullet in the struggle against CO2 pollution. For the issue of CO2 pollution as a whole, there are no silver bullets – especially since 85 per cent or more of CO2 emissions from oil come out of the consumer’s tailpipe.

For the oilsands industry, however, one bullet is at least a silver alloy. The province is counting on CCS to meet 70 per cent of its long-term GHG reduction targets. Compared to a “business-as-usual” case, the province’s climate change strategy has targeted annual reductions of 200 million tonnes of CO2 per year by 2050 – compared to that slippery “business-as-usual” case, a 14 per cent reduction from 2005 levels. Of total reductions, 139 million tonnes would come from CCS. Not bad for a morally bankrupt strategy.

Back to the Future: However, the real risk to the oilsands market may not arise directly from environmental issues. Perhaps the new American administration will take action to back out crude oil demand by frog-marching a shift to electric and natural-gas fuelled vehicles. Such a development would have mixed implications for the petroleum sector.

In a recent presentation to the Canadian Society for Unconventional Gas, ARC Energy’s Peter Tertzakian proposed that rapid change in the transportation fuel mix could represent opportunity for gas producers. “We are in a period that is very 1973-ish,” he said. “Things have to change. About 60 per cent of our energy comes from coal and oil, and they are disadvantaged fuels” for several reasons. Both commodities present serious environmental problems. Oil prices in general are volatile, and Middle Eastern oil also carries a lot of geopolitical baggage. In the US there is a strong sense that the country has to stop importing oil from Persian Gulf suppliers.

According to Tertzakian, “There are policies coming at us,” and they will lead to fundamental changes to North America’s energy mix. “The two opportunists are renewables and natural gas, and I’m here to tell you that renewables are winning.”

To prosper in the changing environment, he said, the gas industry needs to think strategically. “Gas is a clean fuel. It’s plentiful and scalable. It’s time this industry took control and said this fuel is the fuel of the future. If we don’t, we’ll remain hostage to a situation in which all we do to market our (natural gas) production is to sit around the table waiting for the weather report.”

For the oilsands sector, strategic thinking needs to take different forms. By year-end 2009, supply from the oilsands is likely to increase by 150,000 barrels per day, and that supply is going to be competing in a recessionary market. Looking to the longer term, the new US administration and state governments will likely find additional ways to discourage the consumption of oil and the shift to other fuels.

A pipeline to the Pacific is in order, and Enbridge has already begun to develop its Gateway project. One appeal of this line is that Canadian producers would get bids on their crude oil from other markets than the United States. Also, of course, pipeline costs would be less. The downside is that it may come too late to avert a near-term supply glut.

If crude oil demand is going to continually shrink in North America, suppliers to the diminishing market will have to compete on geopolitical, economic and environmental terms. This will involve the continuation of advertising campaigns like those of PetroCanada, Husky Energy, Shell, BP and other integrated firms, which paint the corporation green. More importantly, it will require measures which, like carbon capture and storage, directly reduce emissions.

To win the battle for hearts and minds, both industry and government will need to fight the perception that oilsands production is “dirty oil.” At present, 20 companies – including oilsands players Canadian Natural Resources, ConocoPhillips, Shell and Petro-Canada and coal-fuelled electricity producers Epcor and TransAlta – are vying for a $2 billion pot the province has made available to kick-start CCS within Alberta. As those projects go into operation, Alberta will become a global leader in this technology. The province has also put aside $2 billion to promote public transit.

To make the province’s oilsands production more marketable, provincial strategy is clearly to build a greener image. A three-year, $25 million public relations initiative to improve Alberta’s image is a tiny part of a much larger package.

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.”