12 trends for 2012

Oilsands developers gather momentum and mature in an increasingly complex business environment; this article appears in the January issue of Oilsands Review

It takes more than a global cardiac arrest to slow oilsands activity down for long. The sector has now entered what some are calling its “second boom.” The industry is feeling good as economics, supply and demand push bitumen expansion. Characteristically oilsands, the coming year promises to be laced with tests, trials, achievements, and advancement.

By Peter McKenzie-Brown and Deborah Jaremko
      With files from the Daily Oil Bulletin

Human resources: the cost of a labour shortage grows higher
The oilsands sector is moving into a full-blown labour shortage, and the associated cost implications for new projects will be on the rise in 2012.

“A number of indicators demonstrate that the labour market in Alberta is already tight,” says Chris Lee, a partner with Deloitte whose group recently prepared the report Gaining ground in the sands 2012: A deeper look at major trends and opportunities in the oil sands sector. “Last time around [in 2007-2008], this resulted in a labour shortage, with certain trades hit especially hard, and there was a significant switch of the risk to getting labour from engineering, procurement and construction to the owners. Oilsands projects will continue to be a talent drain.”

Lee says that particularly going into winter, when conventional oil and gas drilling heats up, those projects compete with the oilsands sector. And the challenge is not just in staffing for mining and upgrading “megaprojects.” The relatively smaller-scale steam assisted gravity drainage (SAGD) projects that are multiplying offer new complexities. Construction of these projects generally takes place in “bite-sized” increments replicated in stages.

“SAGD plants, steam generation, and so on require process-oriented skills more akin to refining, pulp and paper, and water handling,” says Lee. Not prevalent in the conventional oil and gas industry, “these skill sets may be harder to attract to places like Fort McMurray. This all adds up to increased labour costs in the next few years – especially when you get into periods of high investment there is a lot of competition for talent.”

The Petroleum Human Resources Council of Canada arrives at a similar conclusion although it begins at another place. According to that not-for-profit organization, the oilsands sector—which it estimates will have to hire up to 15,000 new workers between now and 2020--has challenges attracting qualified people because of its remote location, the competition for skilled labour when several large projects start at the same time, and the industry’s negative public image.

Non-labour cost inflation will stay relatively low
Labour may be the highest piece of oilsands project costs, but there are other inputs that can significantly alter the bottom line. Greg Stringham, vice-president of oilsands and markets with the Canadian Association of Petroleum Producers (CAPP), notes three of the major the indicators that forecast non-labour inflation in the oilsands: the price of steel, the price of natural gas, and the cost and availability of capital. Each of those three now reads better than it did before the global crash.

Steel is a globally priced commodity, and prices could spike rapidly (as they did in 2008) if there were sudden growth in some of the larger developing countries. At the moment, however, its price is roughly the same (US$600 per tonne) as it was in 2007. Natural gas, of course, is important as a fuel source. In 2007 natural gas was averaging between $5-$7 per gigajoule, but according to the Natural Gas Exchange, has averaged approximately $3 per gigajoule since January 2010. The price has dropped and it’s stable.

Stringham adds that, “In 2007 we had a problem with the availability of capital. That isn’t a problem anymore. There is much more East Asian interest in the oilsands, and even some coming from India.” For companies that are capital constrained, he says that, “We’ve seen many cases where the industry finds capital through another company or even overseas.” Also, of course, interest rates are near the bottom of the chart.

New business combinations and sales will help with expansions
Although it is difficult to predict merger and acquisition (M&A) activity, it is clear that in 2012 the oilsands sector will see at least a few important new transactions. Alan Tambosso, president of M&A leader Sayer Energy Advisors, for example, confirms that his company is brokering some raw oilsands properties but can’t comment until after the deals are done.

But there are at least a couple of transactions already in the works and out in the public domain, such as Connacher Oil and Gas Limited’s initiative to find a joint venture partner to enable its planned 24,000 barrel per day expansion of the Great Divide SAGD project, as well as Cenovus Energy Inc.’s efforts to execute a execute a transaction involving the proposed 90,000 barrel per day Telephone Lake SAGD project and some surrounding leases. At the end of the third quarter Connacher said it expected to receive bids by the end of 2011, while at the same time Cenovus said that interested parties were viewing transaction information.

There are also cases such as Oilsands Quest Inc. and Andora Energy Corporation. The future of Oilsands Quest, its assets and proposed SAGD project in northwest Saskatchewan, is now up in the air—the company has been under a strategic review for months, and recently entered into creditor protection. Andora Energy, a subsidiary of Pan Orient Energy Corp. holds oilsands leases in the Peace River region at Sawn Lake, and has plans for a SAGD demonstration. Its strategic review process was initiated in February 2011 and closure of this process has not been indicated.

And let’s not also forget the growing interest of international players in the oilsands industry and their penchant for M&A—that is unlikely to quit in 2012.

Deloitte notes that, “National oil companies with an expressed interest or current investment in Canadian oilsands will continue in 2012 to play an evolving, if somewhat unpredictable role in development of the resource.”

That said, as Tambosso points out, one generally doesn’t know what's in the M&A pipeline until the deal is done.

Learnings from other sectors help the oilsands move into the future
According to Deloitte, there are early signs that the oilsands industry is moving away from legacy “staunchly independent or even adversarial” oil and gas attitudes and toward strategies that borrow models from other sectors in order to address complex issues such as new technology development, and environmental and social sustainability.

“Ideas about municipal water treatment jump to my mind,” says CAPP vice-president Stringham, citing a 2010 initiative where CAPP worked with the Ontario and Alberta governments to organize a “clean and green” workshop in which people from many industries and sectors, including academia and researchers, discussed ideas the oilsands sector could use to clean up its act.

“We basically started with the concept, ‘Bring your good ideas for water treatment, for reclamation and for other kinds of environmental processes and let’s see if there’s anything we can apply,” Stringham says. “Some of the ideas were already being developed for the oil industry through existing partnerships but others were brand new.”

Deloitte argues that by using ideas from the automobile, high tech and other sectors, oilsands producers can take advantage of contemporary manufacturing approaches. “These can reduce cycle times, reduce operational costs and eliminate non-productive activity.”

Producers move closer to commercializing in situ frontiers
Two major frontiers for the in situ oilsands industry—bitumen carbonates and SAGD in the Grand Rapids formation—are coming closer to commerciality, and further progress is expected for 2012. This could mean the potential unlocking hundreds of billions of barrels of currently stranded resources.

Laricina Energy Inc. is operating in both of these resource plays, deploying SAGD at Saleski in the Grosmont carbonates, and at Germain in the Grand Rapids. The 1,800 barrel per day Saleski pilot, which produced first oil in March, saw cumulative sales as of Sept. 30 of 26,300 barrels of blended bitumen.

"We are in the very early stages of unlocking this vast reservoir and, given our progress to date, we consider the results positive," the company says. In an investment note, Peters &. Co. described the oil production as a "positive initial achievement" as the Saleski pilot is the first large-scale production test in the Grosmont since Unocal’s operations in the early 1980s, but it added that well rates need to improve to demonstrate commerciality.

Laricina says that, "Based on our work to date, we expect that in the second half of 2012 the SAGD performance curve will be at a stage in maturity allowing us to initiate solvent injection, thereby beginning the [solvent-cyclic] SAGD phase of our pilot plan."

Athabasca Oil Sands Corp. (AOSC) is also advancing piloting in the bitumen carbonates. Earlier this year the company began an electric-heat pilot in the Leduc formation which it said received favourable results including indications of uniform heating of the reservoir and fast ramp-up and wider well spacing. In October AOSC filed its application for a 6,000 barrel per day pilot of the technology, expecting to start construction in 2012 and production in 2014.

Both Cenovus Energy and BlackPearl Resources Inc. recently fired up SAGD pilots in the Grand Rapids formation. As of the end of the third quarter, BlackPearl said its single well pair BlackRod project was ramping up production, currently at about 200 barrels per day. During the first quarter of 2012 the company plans to file an application for a 40,000 barrel per day SAGD project on those leases.

The Cenovus Grand Rapids pilot is located on the company’s Pelican leases; it began producing in the third quarter of 2011. The company has filed for regulatory approval to expand the project up to 180,000 barrels per day. According to executive vice-president Harbir Chhina, the company’s original target at the pilot was to get “about 600 barrels per day at a steam to oil ratio of three on a cumulative basis, and so if we’re seeing that ratio on an instantaneous basis we’re feeling pretty good.” He adds, “We want to try other unique things that we’ve learned from the last nine months or so in that pilot.”

Laricina is currently building a 5,000 barrel per day demonstration project at Germain, and recently filed its application to increase capacity to 155,000 barrels per day.

Solvents continue to be all the rage for in situ producers
More and more in situ producers are piloting solvent-assisted SAGD projects. “Solvents are the next big thing in situ development,” says CAPP’s Stringham. “Almost every company is experimenting with it now.” Companies using solvents include Connacher Oil & Gas, Cenovus Energy, Japan Canada Oil Sands, Imperial Oil Ltd. and Suncor Energy Inc. “Not only is it an effective tool for production. It’s also more environmentally responsible” since it reduces the amount of heat needed to mobilize the bitumen.

Fortunately for the companies wanting to use solvents, a lot of natural gas exploration is being directed toward liquids-rich gas--especially in shale gas development--because those liquids are much more valuable than dry natural gas. And, the design for in situ oilsands projects adding solvents is to recover as much as possible for re-use. “For the most part once a company has its solvents,” says Stringham, “there isn’t much need for more of the stuff. There is an initial demand upfront and a certain need for makeup demand.”

Collaboration grows as key to managing environmental issues
In a recent interview, Suncor president and chief executive officer Rick George said the oilsands industry should “share anything to do with safety, the environment, environmental improvement, anything on reducing our air, land and water footprint.” Given that perspective, it isn’t surprising that Suncor is one of the founding members of the Oil Sands Leadership Initiative (OSLI)—a group of major producers that has agreed to share technologies and best practices in these important areas.

According to CAPP’s Stringham, “Collaboration is the big topic for improving environmental issues. It is a growing initiative. Environmental issues are not a competitive issue, but something that needs to be worked on collaboratively. The leading edge is the Oil Sands Tailings Consortium.”

Deloitte’s report notes that, “The associations being forged now will set in motion the expectations and rules of engagement that will carry forward when addressing even bigger picture issues requiring even greater universality and solidarity.” For this to happen, says the firm, the industry will need “a wider representation of both large and small operators…to truly push ahead.”

Legislation for a single regulator planned to be tabled
The administration of Alberta Premier Alison Redford plans to establish a one-stop regulator for oil and natural gas projects in 2012, Energy Minister Ted Morton said in early November.

Alberta's previous Progressive Conservative administration under Premier Ed Stelmach and Energy Minister Ron Liepert promised to establish a "one window" regulator for the upstream sector. For example, operators would presumably be able to file a single application instead separate applications with the province's environment and energy departments.

"That's something that we're going to continue to pursue. [Environment Minister Diana] McQueen and I will work on that together," Morton said. "And we have some draft regulation now that we hope to use as a discussion matter with industry over the next several months, and would hope to move to legislation sometime next year.”

Threats build close to home
University of Alberta economist Andrew Leach says the biggest threats to the oilsands sector right now are not in its carbon footprint. Rather, he zeroes in on two problems closer to home: issues from First Nations communities, and Canada’s endangered species legislation.

Leach acknowledges that oilsands development has created a surge of employment in First Nations communities in the oilsands areas. However, there is a great deal of hostility towards the industry in aboriginal communities where there are no obvious economic benefits, for example along the proposed Gateway Pipeline right-of-way. (Another hot button issue, of course, is the tanker traffic shopping “dirty oil” along the B.C. coast.) Those issues could stop the line.

Leach admits that he is no expert on land disruption and its effect on wildlife. But what he does know about are economics and the value people place on environmental damage, "... and if you're going to kill something with your industry what you do not want to kill is something that looks like Bambi, plain and simple…threats to woodland caribou could threaten the industry’s social license to development.”

Alberta’s first BRIK refinery likely to be sanctioned
After being delayed in 2008 due to strained economics, it looks like 2012 be the year that North West Upgrading Inc.’s Redwater bitumen refinery will be sanctioned, processing volumes both from partner Canadian Natural Resources Limited as well as the Alberta government through its bitumen royalty in kind program (BRIK). Detailed engineering for the first 50,000 barrel per day phase of the project began in the first quarter of 2011.

Canadian Natural says that, “project development is dependent upon completion of detailed engineering and final project sanction by the partnership and approval of the final resulting tolls. Board sanction is currently targeted for 2012.”

The $5 billion project would then be up and running by 2014, and although it is a new step for the province in deploying BRIK, it does not necessarily signal more Alberta-fed upgrading in the province.

During her recent leadership campaign, premier Redford said that “There should be more bitumen upgrading in the province, but only if the market can sustain it. The government should not generally play a role in this sector except in special cases such as the Northwest upgrader.”

Oil prices: West Texas Intermediate takes a bow as the main North American benchmark
“Where once we could look to West Texas Intermediate [WTI] for direction in pricing, the global stage has changed,” says Ralph Glass, a vice-president at AJM Deloitte. “Today, the UK’s Brent reference price is the benchmark. Brent prices have an impact on the North American market because internationally priced oil is imported into both the U.S. and Canada.”

Glass says several international factors could affect oil pricing: “These include uncertainty in respect to whether OPEC can increase production significantly if world demand rises. How much success will Libya have increasing its production levels? There are also issues related to political stability in the Middle East and to Europe’s financial crisis.”

The quest to reach the Gulf Coast and tidewater is far from over
If Canadian crude had significantly expanded access to tidewater for export, the prices it receives would compete with Brent rather than WTI.

The November 2011 decision by U.S. authorities to investigate new routes for TransCanada Corporation’s proposed Keystone XL pipeline expansion to the U.S. Gulf Coast, delaying a decision for at least a year, was a blow to the oilsands sector. There remains confidence, however, that more Canadian barrels will eventually reach the markets they need.

According to the University of Alberta’s Leach, “it’s important not to take this decision as an anti-oilsands measure. At least in part, it’s a reaction to high-profile oil spills in the United States by Canadian pipeline companies.” He also suggests that TransCanada may have been “a bit high-handed” when it planned the line.

The transportation sector is scrambling to fix the problem. TransCanada is working on selecting a new route. Enbridge Inc. hopes to increase Gulf Coast access through its Wrangler Pipeline using existing rights-of-way from Cushing, Ok. The plan is to have Wrangler in service in 2013. The company also recently paid $1.5 billion for a half interest in the underused Seaway Pipeline, with the idea of reversing the line so it can take oil south from Cushing. Closing of this transaction and regulatory approvals are anticipated in 2012.

This year will also be significant for Enbridge’s proposed Northern Gateway pipeline to Canada’s west coast, as public hearings begin in January. Approximately 4,000 people have registered to give oral statements.

According to Robin Mann, president of AJM Deloitte, “my sixth sense says Gateway will go ahead. [Prime Minister] Harper has his majority, and he understands the significance of the line. He’ll make it happen.” He adds that both Keystone and Gateway “are important, but I think Gateway is more critical” since it will open up Asian markets to Canadian oil.

The Big Five

Canada's top conventional heavy oil producers in profile. This article appears in the 2011 Heavy Oil and Oilsands Guidebook

By Peter McKenzie-Brown

The five largest conventional heavy oil fields are roughly synonymous with the names of towns and hamlets along Alberta’s border with Saskatchewan. In order, they are Provost, Suffield, Lloydminster, Wainwright and Hayter – no surprise there. However, when you list the five biggest conventional heavy producers a big surprise does surface. The companies are CNRL, Husky Energy, Cenovus, Baytex and…Northern Blizzard.

CNRL (121,000 barrels per day): The biggest Canadian oil company, Canadian Natural Resources is also Canada’s single biggest conventional heavy oil producer. Any one of its top 10 producing fields – two of them produce 14,000 barrels per day each; six produce 9,000 barrels per day each – would make most companies happy. As the company’s website explains, its “crude oil is produced from very distinct assets, using different recovery technologies that are tailored to fit each unique reservoir.” Like Husky, most of CNRL’s conventional heavy oil properties and production are centred on the border town of Lloydminster. The 10 largest of these properties, which individually produce from 4000 to 14,000 barrels per day, collectively contribute 80,000 daily barrels to Canadian Natural's production.

Those projects are being dwarfed, however, by the company's polymer flood operation at Pelican Lake/Britnell which, like the Cenovus property, began life as a cold production operation before converting to waterflood. The company expects production from this field to soon plateau at 80,000 barrels per day.

Husky: At 75,000 barrels per day, Husky Energy is just off the top of the conventional heavy oil hit parade. The pioneer in Canadian heavy oil production – the company has been involved in the area since the 1940s – nearly 80 percent of Husky’s heavy oil production uses primary “cold” production in the Lloydminster area, where the company has a land position of more than 8,000 square kilometres. The remaining 20 percent of Husky’s heavy oil production comes from thermal recovery projects – notably its Pikes Peak SAGD operation. Also located near Lloydminster, the Pikes Peak project is in Saskatchewan.

Cenovus (36,000 barrels per day): The middle company in the line-up is Cenovus. The company has two producing properties which between them account for all of the company’s heavy oil assets. One is at Suffield, which produces about 12,000 barrels per day through conventional methods. More interesting is the companies Pelican Lake property, which produces about 24,000 barrels per day using polymer flood.

Baytex Energy (29,000 barrels per day): Number four in the line-up is Baytex, which generates the bulk of its revenue from heavy oil. According to corporate publications, heavy oil accounts for more than 60% of production and more than 70% of oil-equivalent reserves.

In some ways, Baytex is the odd man out in its conventional heavy oil production. Like the other companies, it has important assets in the heavy oil belt along the Alberta/Saskatchewan border – Ardmore/Cold Lake and Lindbergh on the Alberta side; Carruthers, Tangleflags, and Celtic in Saskatchewan. According to company spokesman Brian Ector, “Development in these areas consists of mainly vertical and horizontal cold drilling, as well as waterflooding at Carruthers.”

However, Baytex also produces conventional heavy from a property in the Peace River Oil Sands. This is unusual. According to Ector, “we developed Seal (the Peace River property) through the use of multi-lateral horizontal wells, and production in the third quarter of last year averaged 10,100 barrels per day. In addition to cold primary development, this year we are embarking on our first commercial cyclic steam stimulation (CSS) project at Seal – a 10-well module scheduled for start-up late in the year.”

Production is approximately 11° API, and the oil flows through “mile-long multi-lateral horizontal wells” from the Bluesky formation at depths of 600-700 metres. Given where it’s located in Alberta, “technically, this is an oilsands lease,” he observes; “it therefore qualifies for the oilsands royalty regime,” which much more attractive to the producer, since it equalizes royalties across all wells.

Northern Blizzard (15,000 barrels per day): A private company, Northern Blizzard pierced the top ranks of heavy oil producers by acquiring assets belonging to Nexen Energy last summer. The price was $975 million; the properties have proved reserves of 39 million barrels of oil equivalent.

The company doesn’t use waterflood or other specialized techniques to produce. According to the company’s chairman, John Rooney, production consists entirely of “cold flow production” – mostly in the Lloydminster area, and mostly from Saskatchewan.

The Outlook
For much of last year, the differential between the prices of Canadian heavy oil and Edmonton par, Canada’s standard for light oil, was very narrow. Indeed, for a brief period last May heavy oil producers were actually able to sell their heavy oil for almost the same price as light oil. This was an extraordinary event – very profitable for producers –and it wasn’t likely to last. It didn’t. At the beginning of 2011, the average difference between light and heavy oil prices had expanded greatly, to about $23. This significantly changed the economic outlook for the sector.

A number of factors have contributed to the widening of the differential. Most importantly, Canadian heavy oil differentials respond to competition at a small number of specialized US refineries. Other heavy oil producers – think Venezuela – also compete in those markets, and competition has picked up in recent months.

Canadian competition has been hamstrung by transportation problems: expanding pipelines to American markets has been slow, and Enbridge’s problems in Michigan have resulted in pipeline shutdowns for maintenance. This is curtailing existing capacity. The rise of the Canadian dollar to parity with that of the US has also contributed to a change in outlook for the Canadian heavy oil producer. The bottom line is that these producers are unlikely to find their conventional heavy oil operations as rewarding in the first half as they were a year ago.

The Desirable Barrel

Why conventional heavy oil is a sizzling commodity in Alberta and Saskatchewan

By Peter McKenzie-Brown

As an oil producer, Saskatchewan seems to have it all. The Bakken light oil trend is a play of frenzied activity. So is Cenovus Energy’s carbon injection oil operation at Weyburn (the world’s largest carbon capture and storage facility). But the province’s meat and potatoes – conventional heavy oil production in the Lloydminster and Kindersley areas – are hidden behind these high-profile developments.

The province’s first 2010 land sale tells the story, but it’s only clear if you dig deeply into the numbers.

Out of nearly $40 million in bonus bids, about $26 million went for land in the Weyburn-Estevan – a reflection of the importance of Bakken and Weyburn. Dig a bit deeper into the numbers, though, and you will find that the highest price paid for a single parcel was $2.1 million for a 1,552-hectare exploration licence in the Lloydminster area. One operator, Baytex Energy, paid $6,512 per hectare for a 16-hectare parcel near Maidstone, also in the Lloydminster area – by far the highest bid per hectare.

Between them, the two heavy oil producing regions in Saskatchewan brought in nearly $10 million in bids – not bad for the Cinderella sister of light oil. The message is clear. The resource has been on production since 1946, but despite its longevity is an increasingly valuable asset. This reality applies to conventional heavy in Alberta as much as it does to production in Saskatchewan. In today’s market the commodity is sizzling. Although there was a blip due to low oil prices a year ago, today’s barrel of conventional heavy is almost as profitable as ever before.

Major changes in transportation to the US and modifications to US refineries have made the Canadian commodity extremely desirable. As a result, the differential paid for Canadian light compared to Canadian heavy is holding firm near historic lows. The differential has averaged about C$8 per barrel for the last year. To put that in perspective, as recently as late 2008 conventional heavy sold briefly for 45% less than Edmonton Par. That wasn’t a profitable environment.

By contrast, the market today is a bit like a winery selling this year’s plonk for 14% less than a vintage wine. Like plonk compared to fine wine, heavy oil is intrinsically less valuable than Edmonton Par, the Canadian standard for light oil. In most refineries, after all, heavy feedstock results in less high-value-added gasoline and more low-value-added asphalt.

But the big US refining complexes are changing that. “It’s a matter of adding vessels to the refinery,” according to Steven Paget; he is vice president for energy infrastructure at First Energy Capital. “Those longer-chain hydrocarbons need more work to break up, but new pipelines from Canada are accessing the refineries at Wood River (Illinois) and Cushing (Oklahoma).” Those refining complexes have the capacity to break heavy oil into lighter feedstock. “Therefore the (narrow) differential becomes minimal or close to equivalent to actual operating cost.”

The good news is that the two heavy oil provinces have a lot of plonk left to sell. According to the Canadian Association of Petroleum Producers (see chart), between them the two provinces have more than a billion barrels of established reserves left to produce. More importantly, each has estimated heavy oil in place many times the volume of reserves.

CAPP estimates that initial volumes of heavy oil in place (this includes both conventional and non-conventional heavy) were about 15 billion barrels in Alberta, and 20 billion barrels in Saskatchewan. Established reserves will thus continue to grow, just as new in-place volumes will continue to be found.

The Background
To understand the economics of conventional heavy, cast your eyes back to the industry’s beginnings.

There are three historical reasons for the growing strength of conventional heavy oil. First, since the 1980s operating costs for conventional heavy production have been in relative decline because of improving technology, higher prices and a better understanding of the reservoirs. Second, policies established since 1990 have lowered royalties for the stuff. Third, the volumes of heavy oil in the Alberta/Saskatchewan heavy oil belt are simply huge. Although the reservoirs tend to be thin, the output is large, and production lasts for many years.

Defined as oil below 20° API which can flow from its reservoirs like lighter oils, conventional heavy oil goes back a long way in Western Canada’s economy. The heavy oil belt is a series of thin sand reservoirs straddling the border of the two provinces. The oil is lighter in density (11-18° API) and of much lower viscosity than the bitumen in the oil sands deposits.

The buckle of the heavy oil belt is Lloydminster, the border town. The first conventional heavy discovery occurred in 1938, and modest development began when Husky Oil (now Husky Energy) moved into the area after World War II. Husky began producing heavy oil from local fields in 1946, and by the 1960s was easily the biggest regional producer. In 1963 the company undertook another in a series of expansions to the refinery (to 12,000 barrels per day). To take advantage of expanding markets for Canadian oil, it also began delivering heavy oil to national and export markets. These developments made conventional heavy more than a marginal resource. Within five years, area production had increased five-fold to 11,000 barrels per day. However, production volumes remained small until the 1990s.

The first of two important developments was the completion of two upgraders – the Co-op facility in Regina and Husky’s in Lloydminster. These upgraders, which were subsidized by government to reduce risk during a period of lousy oil prices, created a large local market for heavy oil. In the early 1990s, production from the heavy oil belt had risen to 300,000 barrels per day – one third of that production being upgraded and refined for local markets. Today Husky produces about 75,000 barrels per day of heavy oil – more than 10% of Canada’s total.

More importantly, in 1993 the Alberta government redefined conventional heavy as “third tier” oil, with highly favourable royalty rates. Once Saskatchewan’s New Democrats were removed from power, new governments in that province matched and then exceeded the Alberta initiative – after all, heavy oil is Saskatchewan’s single most important long-term hydrocarbon resource, so the province had good reason to kick-start development. Indeed, in a modification to the royalty system in 2002, Saskatchewan defined “fourth-tier” heavy oil, with very low initial royalties. All these new tier royalties were great kick-starters. However, as the CAPP data show in the chart below, conventional heavy oil production is now in decline despite growing reserves.

OPEC or Infrastructure?
Especially in a market of declining production, the question of whether differentials will remain narrow is critical. And on this score there is debate. Is the differential likely to narrow or to widen?

According to AJM Petroleum Consulting operations vice president Ralph Glass, the basic reason differentials are so low “is an increased demand for the heavier crude oils from US refineries. Over the last few years there has been a movement by US refineries to enhance their ability to handle the heavier crudes. With the downturn in US demand, OPEC cut their volumes. (The volumes cut were the heavier crudes and done to maximize returns from light crudes which receive higher prices). As a consequence, the US refineries found themselves short of heavier crudes to process, and are now paying a premium for Canadian heavier crudes to reduce the shortfall in their systems.”

He suggests that the demand for heavy oil to fill for new pipelines to the US – TransCanada’s Keystone pipeline into Patoka, Illinois and Enbridge’s Alberta Clipper line to Superior Wisconsin – may narrow the differential even more in the short term. However, the return of competition from OPEC will widen the differential, thus making heavy oil production less profitable.

First Energy’s Steven Paget has a more sanguine view. “The reason the differential has gone down is that we have more transportation infrastructure out of western Canada,” he says. “This allows nearly 90,000 barrels per day of crude to access the Gulf Coast refining complex.” Demand for fill for new lines will increase demand over the short term (narrowing the differential), but the more important factor in his eyes is that those new pipelines will provide increased access to markets, making conventional heavy more competitive in US markets. “The narrow margin is likely to continue.”

Ralph Glass takes the more cautious view. In 2011 and 2012, he says, the industry will experience “widening on implied concerns of heavy OPEC production coming online and increased Canadian heavy production.” If he’s right, and if production continues to decline, expect the sector’s salad days to wilt.

Shell's Take on Carbon Sequestration

This article appears in the November, 2008 issue of Oilsands Review. The generic graphic comes from here.

By Peter McKenzie-Brown

Is human activity influencing climate change or not? Indeed, is global warming even taking place? There is widespread disagreement within academia about the causes of increased global average air temperature, especially since the mid-20th century.

Some argue that the observed “trend” is a normal climatic fluctuation. Others claim it isn’t even happening. These issues are the source of rip-roaring arguments in Alberta. Perhaps because of the impact of geological thinking on a province with a petroleum-based economy, the arguments here are both heated and informed.

Geologists, who think in terms of Earth’s periods and epochs rather than its decades, are well aware that climate always changes. Perhaps they also have an innate scepticism about whether human behaviour can meaningfully alter the powerful natural forces continually changing our planet. While the debates rage, the scientific “consensus”, as it is delicately called, supports the idea that greenhouse gas emissions from human activity are increasing Earth’s temperatures and thus speeding up climate change.

For many environmental groups the problem seems critical, and they call for urgent action. Increasingly, so do many corporations. For example, Royal Dutch Shell’s position on climate change is unequivocal. According to Jeroen van der Veer, the corporation’s CEO, “For us, as a company, the scientific debate about climate change is over. The debate now is about what we can do about it. Businesses, like ours, should turn CO2 management into a business opportunity and lead the search for responsible ways to manage CO2, use energy more efficiently and provide the extra energy the world needs to grow. But that also requires concerted action by governments to create the long-term, market-based policies needed to make it worthwhile to invest in energy efficiency, CO2 mitigation and lower carbon fuels. With fossil fuel use and CO2 levels continuing to grow fast, there is no time to lose.”

Carbon Capture and Sequestration: So what’s a company to do? Over the last decade, global think tanks have increasingly focused on CCS – the common abbreviation for carbon dioxide capture and sequestration (more colloquially, “storage”) as a technologically simple way to remove CO2 at some large processing plants. The most prospective targets for this technology include coal-fired electricity generators and oil sands upgraders.

Problem is, such ventures are not profit-driven enterprises. They are climate-driven – initiated in response to concerns about climate change and related regulation. On its own, CCS doesn’t make sense. It requires government intervention. In that context, the CCS climate changed profoundly last July when Alberta premier Ed Stelmach announced that his government would provide $2 billion to advance these technologies in the province. That is the biggest sum available for CCS anywhere.

Often (unfairly) derided elsewhere in Canada as a Johnny-come-lately to the environmental table, Alberta’s involvement follows a gestation period of deep study. Last January a provincial policy paper observed that “Alberta has a unique opportunity to implement carbon capture and storage to substantially reduce our greenhouse gas emissions. CO2 emissions can be captured where they are produced, transported and stored in geological formations (such as depleted oil and gas reservoirs, coal beds, and deep saline aquifers) that may be located hundreds of kilometres away.... Ultimately, CO2 capture and storage technologies provide the province with the greatest potential to substantially reduce greenhouse gas emissions while, at the same time, retaining our ability to produce and provide energy to the rest of the world.” Alberta is counting on CCS to meet 70% of its long-term GHG reduction targets.

When the September deadline for submitting expressions of interest to the Alberta government arrived, the Department of the Environment received “more than a dozen” proposals, according to government representatives. The province is now narrowing those proposals down to the few with the greatest potential to be built quickly and significantly reduce greenhouse gases. The province hopes to reduce emissions by up to five million tonnes annually through this program.

The names of the contenders have not been publicly disclosed, although the rumour mill is speculating on the usual suspects – big players with interests in oilsands or enhanced oil recovery. Devon, Imperial, Syncrude, a Husky/BP partnership, ConocoPhillips, ARC, Petro-Canada, Enbridge and Total E&P come to mind. One player, however, has been quite public in its enthusiasm for CCS. Shell Canada has long been studying a CCS project connected to its Scotford Upgrader, and a story on that project accompanied a great deal of the coverage of Alberta’s CCS incentives.

Sequestration or Storage? The name of that project, Shell Quest, refers to the notion of sequestration. According to Rob Seeley, Shell’s general manager of sustainable development, the idea of sequestration is quite different from storage. “Sequestration implies permanence,” he said. “Storage seems temporary. (In a CCS project) the carbon would be sequestered, not stored. It will be there forever.” In his world, CCS refers to carbon capture and sequestration, not storage.

The venture manager for Quest, Seeley is upfront about the global warming issue. “We (at Shell) are seriously concerned about man-made CO2 emissions in the atmosphere. We know that global warming is a natural process that has been going on for 10,000 years, but we believe that man-made emissions could be accelerating the process. Whatever the science ultimately finds, we believe in the precautionary principle. We need to take action on reducing CO2 now.”

The Scotford Upgrader is part of a complex dating back to 1984, when Shell constructed there the first refinery to exclusively process synthetic crude from Alberta’s oil sands. Located northeast of Edmonton, Shell’s Scotford complex has often been expanded. It, and was augmented with an upgrader in 2003.

The upgrader receives bitumen from the Albian oil sands plant, and transforms it into two types of synthetic oil – Albian premium synthetic oil and Albian heavy synthetic oil. Synthetic oil is bitumen with the impurities removed and hydrogen added. Adding hydrogen yields upgraded oil that can more readily be refined into high-quality products like gasoline, diesel and other types of fuel. The Scotford plant processes 155,000 barrels per day of raw bitumen.

The upgrader is now undergoing a third expansion which, when completed in 2010, will include the commissioning of a third hydrogen plant. Hydrogen plants combine steam and natural gas (methane) to produce hydrogen for upgrading and by-product CO2 that is vented to the air.

The key to Shell Quest would be a facility that captured the CO2 from all three of the upgrader’s hydrogen plants. “We will use a patented Shell process that uses amine solvents to scrub H2S and CO2 from our gas stream,” Seeley said. Once the gas stream was cleaned up, compressors would prepare the CO2 for transport to underground storage sites. Compressing CO2 transforms it into a supercritical liquid – a form of matter which has the properties of gas and liquid simultaneously. Once liquefied, Shell would pipe the CO2 to field facilities, where it would be injected into deep, underground rock formations.

How it would work: CO2 will remain in supercritical form if stored more than 800 metres below ground. Shell is targeting structures 2,000 or more metres deep. The injection wells would use several casings of steel pipe to ensure the CO2 entered the deep rock formations alone, and would not enter shallower areas of the ground. This would prevent leakage to the surface or into drinking water aquifers.

Cap rocks would trap the CO2 underground. In addition, however, several technical down-hole traps would keep the CO2 permanently in the reservoir. For example, CO2 can eventually combine with chemicals within the reservoir to form carbonate rock – limestone, for example. These traps plus the cap rock mean there is little likelihood the CO2 would ever leave the injection sites.

According to Rob Seeley, “We believe CCS is an important piece of the toolkit to reduce CO2 emissions. We think it’s a great opportunity within an oilsands operation to reduce our greenhouse gas footprint.” He notes that capture, compression, transport and sequestration themselves require energy, and that these energy needs will partly offset the benefits of CCS. “If we capture and sequester 1.2 million tonnes of CO2 per year, the net result of putting that away would be roughly 1 million. It depends on where the energy comes from for the capture and sequestration processes and how effectively it’s integrated into the whole process.” All in all, though, “CCS is a great opportunity to reduce CO2 emissions and to help move us on the path to greater sustainability.”

The Role of Government: Seeley was unwilling to discuss the cost of these ventures, but suggested that Alberta’s $2 billion would be distributed among only five CCS projects, each of which would capture at least one million tonnes per year. The simple math says the projects would each receive a $400 million subsidy. Why should they?

“We believe governments should take action on regulation to control CO2 emissions,” Seeley said. “If they do that, it will create a level playing field in which big industrial polluters can innovate to reduce emissions.” Seeley thinks big: “If we can have regulation that is complementary from country to country then we have a better chance of reducing these emissions internationally.” Seeley noted that CCS faces numerous risks that will require government involvement. These projects “are sitting waiting for regulation. The rules for greenhouse gas regulation in Canada are still not certain. You have to settle regulatory issues such as Canada and Alberta harmonisation before those projects can go forward.”

In his view, “The beauty of (CCS) is that it can capture very large from industrial sources. However, prices of $80-100 per ton are well beyond the prices that have set for CO2 in the near time. If the price of carbon is $15-20 per ton, it will be cheaper for companies to pay into a government tech fund than to actually sequester CO2.” Thus, if governments see CO2 emissions as a problem, helping fund CCS is a way for them to this important CO2 mitigation opportunity started.

“Capital costs will be in the hundreds of millions of dollars, but operating costs will also be high. It could be that over the life of a project the operating costs (present value basis) would be about the same as the capital costs. There are also technological costs.” Although CO2 has long been used in enhanced oil recovery, Seeley observed that “EOR doesn’t save the day on this. Historically, for EOR you get paid maybe $20 per ton for CO2. With higher oil prices, maybe you will get $30 to $40 per tonne. This is still well short of the $100/tonne cost to capture, compress and transport CO2. Only higher carbon pricing (by government) or the market will make this viable.”

Six Pathways: He adds, “The price of this technology will come down, but first we need some demonstration projects. That’s what Quest is all about – a large-scale demonstration of fully integrated CCS. We need to build this first round of projects so that we can learn from them. As these projects go ahead we will go from using amines to capture the CO2, then move on to cryogenics and other approaches that are more sophisticated.”

The earnestness with which Rob Seeley describes the issue of GHG emissions seems to reflect corporate culture at Royal Dutch Shell. The corporation has identified “six pathways” toward reducing carbon emissions. For the record, here they are: Increase energy efficiency within the corporation. Create technologies that increase efficiency and reduce emissions. Develop low-carbon fuels. Help customers use less energy. Work with governments on effective regulation. Implement carbon capture and sequestration.

This seems like a map other oilsands producers should study.

A New World Order?

Hugo Chavez says Venezuela's way of doing things is the wave of the future. But is there a place for large international oil companies that are NOT government-controlled? This article appears in the September 2008 issue of Oilweek magazine.

By Peter McKenzie-Brown “Alberta became the Bolivarian province of Alberta when you decided to take more royalties from the oil companies,” Luis Vierma told a scowling crowd from Calgary’s petroleum community last June. “This made Venezuelans very happy.” The reference, of course, was to Simon Bolivar – the 19th century revolutionary whose leadership helped to liberate much of South America from the Spanish monarchy. The speaker was the E&P vice president of a national oil company – specifically, that of the Bolivarian Republic of Venezuela. Vierma’s cheeky comment garnered a few chuckles from his audience, but not many. This articulate man – he was educated and for some years worked in the United States – described a world order which at first blush doesn’t seem to suggest a happy future for western-style international oil companies. However, this commentary suggests that it may not be all that bad for private-sector oil companies, and that the changing world has huge implications for the oilsands. The United States is clearly worried about Venezuela. The CIA’s 2008 World Factbook, for example, offers a litany of indignant complaints about the South American nation. “Hugo Chavez, president since 1999, seeks to implement his ‘21st Century Socialism,’ which purports to alleviate social ills while at the same time attacking globalization and undermining regional stability. Current concerns include: a weakening of democratic institutions, political polarization, a politicized military, drug-related violence along the Colombian border, increasing internal drug consumption, overdependence on the petroleum industry with its price fluctuations, and irresponsible mining operations that are endangering the rain forest and indigenous peoples.” Vierma’s audience was also concerned, but their concerns were much narrower. They were well aware that Petróleos de Venezuela S.A. (PdVSA) was the beneficiary of Chavez’s large-scale nationalization of assets held by international oil companies. They were also aware that the company holds the keys to Venezuela’s Orinoco heavy oil belt. Named after the nearby Orinoco River, these deposits are roughly comparable in terms of in situ volumes to those in Alberta’s oilsands. On the global stage, they are the province’s only serious competitor. New World Order: This commentary explores Vierma’s suggestion that recent decades have seen the creation of a new world order that is now entrenched and becoming more pronounced. It is an idea that is getting ever-wider acceptance. “In the new international energy order, countries can be divided into energy surplus and energy-deficit nations,” writes Michael Klare, an American academic who specializes in the geopolitics of energy. “Deficit states like China, Japan and the United States are compelled to pay ever higher prices for imported fuels as they compete with one another for those materials the surplus states are prepared to supply. The surplus states, on the other hand, are sure to become richer as they parcel out their increasingly valuable commodities at whatever prices the markets will bear.” As Klare observes, national oil companies (NOCs) are increasingly dominating global oil supply. Of the 15 oil producers with the greatest reserves, only two are privately owned – Russia’s Lukoil (#9) and Chevron (#15.) Between them, they control 2% of the world’s proved conventional reserves – compared to 77% for the other 13 companies, combined. PdVSA’s Vierma – his company is the beneficiary of a highly contentious nationalization of the petroleum industry by the Venezuelan government – is a strong believer in the new world order. “The whole industry of the last century is completely different from the industry of today. In the 1970s, 85% of the (world’s) oil reserves were managed by international oil companies, the Seven Sisters. Today the situation is completely different. Most reserves are now managed by national oil companies, and everything now gravitates around (them). At the beginning of the 21st century, national oil companies turned into the principal actors in the petroleum sector.” Petroleum “is the backbone of the economy in Venezuela,” he added. And according to the vision of Venezuela’s socialist government, the country’s NOC has a responsibility “to ensure our shareholders get enough of our revenue, and we have 27 million shareholders, the Venezuelan people. We have a responsibility to develop our reserves to allow them to have a better life. This is the main difference between how the industry was managed in the past and how it will be managed in the future.” Being a national oil company brings a lot of responsibilities. Perhaps the most important of these are social responsibility and how we take care of the environment. Last year PdVSA invested $14 billion in social programs, and after paying taxes and royalties still made US$6.27 billion in profit. “This proves that we can be a profitable oil company with a lot of social responsibility.” This is the vision of the future, he said: “Oil companies around the world will do the same.” Competition and Cooperation: “We believe the work here will involve cooperation instead of competition,” he said. “Even though some competition will be there, but cooperation is an important issue to be considered.” By his analysis, national oil companies fall into three groupings. The first are those that can meet their own needs plus export – for example, Saudi Aramco, PdVSA and the National Iranian Oil Company. Another category includes national oil companies in consuming countries, like China’s CNPC and India’s ONGC. These companies can’t meet internal demand, and are looking for opportunities overseas. Finally, there are NOCs in countries that can satisfy internal demand and could, with development, become important exporters; these include Mexico’s Pemex and Brazil’s Petrobras. This latter group of countries, Vierma suggested, “are going to become important sources of primary energy” to the rest of the world. PdVSA has formed alliances with NOCs throughout the world, and owns a substantial American subsidiary – CITGO, an integrated oil company in its own right, and the vehicle through which PdVSA exports oil to the US. “All these companies are participating in projects with us either upstream or downstream,” said Vierma. “The magic word is how we can establish cooperation with their regimes so these companies can be successful and sustainable over time. We believe cooperation (not competition) is the key word to establish business relationships with these companies.” Oh, Canada: According to academic Michael Klare, PdVSA is number six among national oil companies, with control of 6.6% of the world’s proved reserves. However, that number does not take into account the vast potential of the Orinoco oil sands. When you factor in the oilsands, the numbers become staggering. Start adding the resource potential of bitumen and heavy oil from Canada and extra-heavy and heavy crudes from Venezuela and, Vierma said, “(between us,) Canada and Venezuela will have more than half of the oil reserves around the world.” How can Canada benefit by working in Venezuela? The country is looking for foreign partners to develop offshore properties that are prospective in terms of both oil and natural gas. In the oilsands, the two countries need to share oilsands technology. According to Vierma, “Venezuela now has 1.3 trillion barrels in situ. With 20% recovery we believe 235 billion barrels of heavy and extra-heavy crudes are now (technically) producible from (our oilsands area), and 17 NOCs are working with PdVSA in that area. By October 2009 we plan to certify those 235 billion barrels that are going to be recovered.” In a proposal that is unlikely to draw much interest from Canadian firms, PdVSA suggests using cooperation rather than competition to create global market efficiency. “In terms of heavy oil production and heavy oil markets we need to share our learning lessons, experiences and challenges with Canadian companies. Canada and Venezuela will share the same markets as well as the same challenges. Why not cooperate to make the markets more efficient?” He suggested, for example, that Canadians focus on developing markets in Asia, while Venezuela develops markets in the Atlantic basin. How else could Canada and Venezuela cooperate to develop those resources? PdVSA obviously wants access to Canada’s oilsands technologies. But the country’s conventional resources are also considerable – don’t forget that PdVSA controls 6.6% of the world’s oil reserves – and these resources also need to be developed in a hot global economy – hot, at least, in terms of petroleum exploration and development. Like other producers around the world, Venezuela needs infrastructure, including rigs for conventional oil and gas drilling, and that “provides tremendous business opportunities for Canadian companies.” The Human Factor: As he closed his presentation, Vierma made a plea for help in education and training. “We need human resources, skilled people, and we are here to tell you this is another area where there are opportunities for the people of Alberta,” he said. “We are aware that the level of education in this province is very good, and we want to retake the bridges that we have burned in the past.” The irony of this comment, of course, is that Venezuela’s 21st century socialism has helped reduce the talent available to Venezuela while increasing that in Canada. Last year both Exxon Mobil (the parent of Imperial Oil) and Petro-Canada fled Venezuela because of the shenanigans of Hugo Chavez. Both companies were investigating extra-heavy projects in Venezuela, and both transferred technical expertise and field workers to Alberta as a result. According to CEO Ron Brenneman of Petro-Canada, “We are finding that some pretty good technical people are coming available (directly) out of PDVSA as a consequence of what’s going on down there.” He adds, though, that “I don’t think this will affect (Alberta’s) labour pool to a large extent.” But what about the new world order? The argument that the world has fundamentally changed is very strong. NOCs are unquestionably dominant in the politically risky parts of the world, and that trend is unlikely to change. In addition, geopolitical considerations (including human rights issues, corruption and worries about Venezuelan-style nationalization of assets) are keeping international oil companies away from many of the regions that are left. Does this mean the future belongs to PdVSA and other NOCs, as Hugo Chavez and others have suggested? The answer is almost certainly no. Rather, international companies will increasingly focus on development in areas where risk is minimal and potential is large. Clearly, much of that activity will take place in Alberta’s oilsands. To use Shell as an example, its Canadian oilsands potential is in the 40-billion-barrel range – volumes that dwarf the rest of its oil assets world-wide. Remember that list of oil reserves of the world’s top 15 companies? Such a resource would place Shell in seventh place – ahead of the National Oil Company of Libya, behind PdVSA. This reality suggests another vision of the new world order. Increasingly, perhaps, international oil companies will need to retreat to low-risk, high-potential areas like Alberta in North America, Europe, Australia, India, parts of Southeast Asia and South America and other “safe” parts of the globe. In a future of declining conventional production, they will prosper by applying their considerable intellectual, technical and capital resources to oil sands and shale oil development, and to the production of gas from tight sands, shale and hydrates. The service sector could also do well in such a world order. Unconventional development requires a lot of support from service providers. Supplying expertise to inefficient national oil companies could offer (just as Vierma suggested) “tremendous business opportunities.” Indeed.

Pushing South

Notes on geopolitics as Canadian crude pushes toward the Gulf Coast This article appears in the June 2008 issue of Oilsands Review.

By Peter McKenzie-Brown 
“There certainly appear to be a lot of forces increasing the demand for Canadian heavy, particularly in the US,” says Steve Wuori. Enbridge’s executive vice president observes that right now only Venezuela and Mexico are seriously competing for the heavy oil market in the Gulf Coast, and “there are declines in Mexican supplies for geologic reasons, and Venezuelan declines for both economic and political reasons. So structurally it’s a very good time for Canadian heavy oil to secure that market."


Wuori’s comments reflect a sea change in Canada’s approach to selling the stuff. Early bitumen development in Alberta was slow and easy – regional producers supplying heavy oil to refineries in America’s northern tier states, with virtually no competition from overseas. Today, with surging supplies projected well into the future, Canadian producers, pipelines and marketers have had to become aggressive. Global forces are having a greater impact on the industry than ever before. This is a good news/bad news story. The good news is that there are chinks in the armour of our offshore competitors – lots of them. The bad news is that the chinks in Canada’s armour are costing the country dear. Consider the following.

• Already the world leaders in bitumen production and an important producer of conventional heavy, Canadians have roughly doubled their non-upgraded bitumen production in less than four years.
• American decision-makers would be delighted to replace politically volatile Venezuelan supply with low-risk Canadian product, and Venezuela’s present leadership would be equally happy to develop markets elsewhere.
• Mexico’s supergiant Cantarell heavy oil field is in steep decline, but Canada has the productive potential to offset the shortfalls.
• The isolation of the Canadian prairies from the world’s sea lanes and from America’s major refining centres means bitumen producers can’t freely compete in world markets. Consequently, they get lower prices.
• As price-takers in North American markets, Canada’s producers have to settle for lower profits, and the province has to settle for diminished royalty revenue.

All these matters have geopolitical overtones. One way or another, each calls for the economic fix of more fully integrated global markets. This article focuses on the importance to Canadian producers of integration into world markets, and some of the ideas in play to achieve it. Let’s begin with Alberta’s relative isolation.

The Economic Burden of Under-Priced Oil:Western Canada’s heavy oil sells for less than the price it would fetch on the open seas. “Alberta is not an island,” observes FirstEnergy’s Steven Pachet, with a somewhat understated taste for the obvious. “If it were, world market prices for heavy oil would be easier to obtain. Alberta is landlocked, and pipeline capacity to other markets is sometimes restricted. Mountains to the west make pipeline transportation to the Pacific difficult, while the bulk of North America stands between Alberta and the Atlantic and Gulf Coasts.”

While heavy oil and bitumen sell at a discount to light crude both in Alberta and around the world, sometimes the Alberta discount increases when heavy crude from Alberta cannot reach markets. Known as the heavy oil differential, it represents the difference between the prices of Alberta’s Lloyd blend heavy oil and Mexico’s Maya crude, adjusted for transportation costs.

Lack of transportation is the main reason for the differential. The refineries that are accessible to Alberta heavy crude and bitumen can only handle so much supply. Alberta producers have limited access to US markets because of pipeline constraints, and the refining and upgrading systems in Western Canada are not nearly large enough to handle all the new production. As available supplies rise, refiners lower the price they will pay for Alberta’s heavy and oil sands-based crude until it is below world prices: the greater the competition to sell that oil, the lower the market price and the greater the differential.

This market behaviour costs Alberta, big-time. To help put it in perspective, during the final quarter of last year the differential averaged US$17.94 per barrel – the largest discount ever for Canadian heavy.

Such discounts are an economic burden on both producers and government. By Paget’s calculations, in 2008 bitumen producers will forego $1.88 billion because of the differential. This estimate uses very specific assumptions about how oil prices will behave this year.

When he presents an estimate for the cost of the discount to the provincial government, however, Paget uses a range of assumptions for its impact on royalties. In his view, the discount could cost Alberta some $200-$500 million in foregone royalty income. Also, of course, foregone revenues mean foregone taxes at every level of government.

The size of the prize can be measured in billions, but the penalty for inaction could be greater still: growing surpluses leading to greater discounts and diminishing development. The simple logic of this situation is clear. The large sums in play mean a lot of incentive for change, and a lot of change is on the way.

According to Paget, “Oil sands producers have a choice. Upgrade the bitumen into synthetic crude for higher unit revenue, or sell the bitumen and let others invest the capital to refine it into lighter crude and petroleum products.” This fundamental choice can be resolved with three kinds of development: New and expanded upgrading systems; expanded pipelines for existing markets; the creation of new markets. All are under consideration, and all are needed to meet the growing heavy flow from Alberta.

Getting to the Gulf: Here is the problem in a nutshell. Access to the world gives you the best available prices for your heavy oil. Access to a crowded regional market gives you Western Canada’s heavy oil discount. That is why the marketing Shangri-la for the heavy oil sector is the Gulf of Mexico, and why it’s important at this point to discuss the labyrinthine world of pipelines.

Cushing, Oklahoma, is now the southernmost delivery point for Canadian oil, and the closest delivery point to the vast coastal refinery complexes in Texas (4 million barrels throughput per day) and Louisiana (3.3 million barrels per day). Cushing itself has more than half a million barrels per day of refining capacity, so you can see the importance of delivering oil to these key markets. However, Enbridge’s pipeline to land-locked Cushing now supplies only 120,000 barrels of oil per day – soon to be increased by more than half. Shipping capacity from Canada to Cushing will increase by another 155,000 barrels per day with the completion two years from now of TransCanada’s Keystone Oil Pipeline extension.

Steve Paget explains the inexorable implications of these expansions. “By late 2010, total Canadian shipping capacity to Cushing will increase to 345,000 barrels per day. This is 65 per cent of Oklahoma’s total refining capacity. Canadian producers will need access to new markets to avoid swamping Oklahoma refineries.” After all, swamped refineries mean lower oil prices because of greater competition.

At the moment, Canada has no direct access to the Gulf, although small amounts – in the order of 15,000 barrels per day – are transhipped there from Cushing. Both Enbridge and TransCanada are proposing further pipeline extensions to the Gulf Coast to avoid Canadian crude being stuck in Oklahoma. The American Gulf Coast has refining capacity for bitumen, and it also needs new sources of heavy crude.

Of course, heavy oil developments in Canada are creating the need for much greater pipeline access to the coast than the volumes Enbridge and TCPL will be providing to (and south from) Cushing. At this writing there are four other proposals to increase pipeline capacity to the Gulf.

• Enbridge’s Access Pipeline would expand existing pipe and extend the system from central Illinois to the Gulf. This would provide 445,000 barrels per day of capacity. ExxonMobil is a 50 per cent joint venture owner of the proposed pipeline and owns useful rights-of-way.
• TransCanada is also considering several possibilities – notably (with Conoco Phillips) the Keystone project, which will convert a segment of TCPL’s natural gas mainline for oil transportation.
• Another possible entrant is the Chinook system – a 300,000 barrel-per-day proposal by two American firms, which would use existing rights-of-way to ship.
• The Altex Pipeline – proposed by a private company – would use new technologies to ship 425,000 barrels of bitumen per day south.

Ironically, increased oil sands production in Alberta has greatly increased the province’s need to import condensate – the mix of light hydrocarbons used to dilute bitumen to enable it to flow through pipelines. That need, in turn, is leading to the construction of yet another pipeline. According to Steve Paget, “diluent (condensate) is being shipped into the province by railcar these days. There’s plenty of diluent in North America, but how much do we want to move in by train? It’s like the old Rockefeller days. The problem is getting it here at a reasonable price, and that problem is being resolved by construction of the Southern Light pipeline, which will move diluent from Chicago to Edmonton.”

As Canada develops greater access to Gulf Coast markets, Canada’s heavy oil differential should disappear. The reason is simple. Unfettered free-market oil prices reflect just two factors: transportation costs and crude oil quality. Canada’s competitors into the Gulf Coast region – notably Mexico and Venezuela – have the option to cheaply take their production by tanker, anywhere in the world, to the highest bidder. This means their prices are driven by competition for the world’s highest prices. By contrast, Western Canadian producers are competing in a small and crowded marketplace.

The Competition: Markets always face complicating factors, and the situation along the Gulf Coast is no different. As Steve Wuori points out, “The issues are increasing Canadian supply and possible political issues between Venezuela and the United States. Venezuela has gravitated toward China and possibly other customers. This has made it more feasible for Canadian oil to replace Venezuelan production in Chicago and south.” Because of political turmoil, employees at Petróleos de Venezuela struck some years ago, cutting deeply into production a few years ago. Also, of course, the country’s disputes with ExxonMobil and other multinational companies have made international headlines.

Closer to home, the vast Cantarell heavy oil field, which provides about half of Mexico’s oil production, is in rapid decline. According to the director-general of national oil company PEMEX, production from the offshore field declined by more than 13 per cent in 2006 alone. Cantarell’s production peaked at 2.1 million barrels per day barely four years ago, but is forecast to average only a million barrels per day by the end of this year.

According to FirstEnergy’s Steven Paget, “There’s a possibility of Mexico becoming a net oil importer if the decline at Pemex is not turned around, so it is for several reasons not wise to depend on those two countries for oil.” Enter Canada – a secure and reliable supplier with vast and growing supplies of heavy oil and eager to displace imports from Latin America to the Gulf Coast.

The geopolitical considerations do not end there, however. Venezuela’s Hugo Chavez is increasingly unpopular at home, the country’s economy is in disarray, its heavy oil resources rival Canada’s, its labour costs are low and its transportation costs to the US Gulf Coast are a fraction of Western Canada’s. It is possible to imagine a post-Chavez Venezuela developing those resources and becoming a resurgent competitor.

Don’t put all your eggs in one basket: such is the weakness in the Canadian strategy of focusing on markets in Texas and Louisiana. From the Gulf, Canada’s heavy oil producers would have tanker access to the whole world, but not before paying huge pipeline costs from Alberta. To help forestall such an eventuality, Enbridge has proposed a project named Gateway.

A Nearby, Open-water Port: "Usually to create a market you need producer push and refiner pull,” says Steven Paget. “We are definitely seeing (both) for Gulf coast markets,” but right now the producer push to reach Asian markets is pretty slim. However, Enbridge is planning just such a line.

Gateway is “a heavy oil pipeline from Edmonton to Kitimat (British Columbia) to carry oil to a different market than the southern US,” Steve Wuori explains. “It would carry oil to California and to Southeast Asia, by ship. The appeal to Canadian producers is that you would get another bid on the crude oil from somewhere other than the United States.” Also, of course, pipeline costs would be less.

“When (Enbridge) first started we were aiming for 2011,” Wuori says. “But now we are targeting 2012-2014” to get this line into production. Will Canada be able to supply all these markets with heavy? Wuori thinks so. “The production forecasts up to 2020 for the oil sands support that kind of growth potential, even if you risk it for economics and environmental concerns.” Indeed, Enbridge is even looking for ways to take Canadian heavy to refineries in Ohio and Kentucky “and even beyond that to the east coast of the US – to ensure that there is market for Canadian production.”

Canada’s bitumen production is the ultimate example of the blackening of the barrel in the petroleum world. For more than two decades there has been a shift in global production from light, sweet, high-quality oils to heavy, sour, poor-quality crude. This “blackening of the barrel” has been problematic for many refiners, since black barrels bring with them environmental drawbacks, require capital-intensive equipment, and refine into lower-value barrels of fuel and other products.

Most refiners prefer higher-quality oils, and producers prefer to sell those oils because they fetch a better price. So does the government of Alberta, because it wants to realize as much of the economic benefit from the oil sands as possible. What’s a province to do? FirstEnergy’s Paget has an idea that deserves sharing.


Upgrader Option: As resource owner, the government of Alberta receives its royalty share from bitumen and heavy oil production in kind – that is, it receives oil, which it then needs to turn around and sell. Most producers that upgrade their oil sands in Alberta into lighter crude or petroleum products pay royalties based on the bitumen price.

Therefore, any discount for Alberta oil sands bitumen results in decreased royalties and decreased Government of Alberta revenue, whether the crude is upgraded in Alberta or elsewhere. “Assume that bitumen royalties are 10 per cent” this year, says Paget, and that the oil sands produce 1.3 million barrels per day.” This would mean the province receives 130,000 barrels of bitumen each day in royalties – a volume forecast to grow into the foreseeable future.

“Why wouldn’t Alberta guarantee that amount as feedstock for a private-sector upgrader?” Paget asks. “If the government believes in upgrading in Alberta, then taking the oil which it in fact owns and dedicating it to Alberta upgrading is a good way to do it. It’s a good way to make policy without investing much money directly. A hundred and thirty thousand royalty barrels per day is easily enough to support one or two stand-alone upgraders.”

Paget weighs the possibilities. “The government of Alberta is faced with a dilemma. Investment is lost (whenever raw) bitumen is exported. How much investment might be lost if bitumen exports from the province increase by 500,000 barrels per day? With current pipeline constraints and artificially high differentials, royalty revenue is already being lost.”

The new pipelines under construction don’t present an obstacle to this proposal, since most of the oil pipelines from the province can ship both bitumen and other crudes, including synthetic oil. Indeed, this idea seems to be one that will benefit the province in many ways. Provincial royalties would increase, and so would producer profits.

Colin Campbell and the Cracks of Doom

By Peter McKenzie-Brown
For many peak oil believers, this is the scariest chart you can imagine. The blue lines show historical oil discoveries. The gold lines project discoveries into the future. The line that looks like a rising serpent shows annual production up to about 2005. The chart was created by peak oil guru Colin Campbell in 2004 for a deliciously ironic article titled "The Heart of the Matter". The chart looks like a road map to the Cracks of Doom, and it has been quite influential.

In this column I have frequently provided arguments in favour of peak oil theory, and I am an unabashed admirer of Campbell and his work. However, I believe this chart, though directionally accurate, is simplistic and alarmist. It needs to be nuanced. We can do that in three ways.

• First, note that the blue lines essentially track the world’s new-field discoveries of light and medium oil. The chart suggests that these volumes are the world’s oil reserves. It doesn’t nearly reflect the reserves additions that come through infill drilling, enhanced oil recovery and other standard oilfield practices. By applying simple math to the chart (subtracting production from discoveries), you will come up with world oil reserves far short of the roughly 1.2 trillion barrels that the Energy Information Agency and other authorities have booked.

As they are developed, most discoveries prove to be much bigger than the estimates at time of discovery. This is partly because reserves are a function of economics. When you find a new field you calculate its reserves based on present conditions and price forecasts – say, in 1970, $2.50 per barrel into the foreseeable future. As prices rise relative to costs, you will get more oil out of that field – of that you can be sure.

The thinking by which M. King Hubbert forecast the year of peak oil production in the United States was incredibly successful. What is rarely discussed, though, is that Hubbert underestimated by about 50 per cent the amount of oil that would be available in the US after it reached the peak. To a large extent this was because new reserves became available through changing technologies and more favourable petroleum economics.

• Second, give heavy oil, bitumen and oil shale the credit they deserve. Because of the nature of the beast, these unconventional resources are not booked as reserves until they become economically and technically producible.

Alberta’s huge oil sands are a classic example. In 2005 America’s Energy Information Agency booked Canadian oil reserves as second in the world (after Saudi Arabia) because of the impact of higher prices and improved technologies on the oil sands. If that amount of oil – 174 billion barrels (174 gigabarrels) – were added to the gold-coloured reserves lines on Campbell’s chart, it would require a line that would tower over the rest of the chart by a factor of three. Campbell’s methodology does not account for this kind of event. And in all likelihood, much more of the oilsands will eventually be booked as reserves.

That point takes me to this chart (click to enlarge), which is also from Campbell’s article. The black wedge – characterized as “Heavy, etc.” in the legend – is his estimate of the contribution of heavy oil to the global energy liquids picture. Eyeballing suggests that he expected these unconventional resources to be about 4.5 million barrels per day by now, world-wide.

Heavy oil, synthetic oil and non-upgraded bitumen represent about two million barrels of production per day in Canada alone, and Venezuela and Mexico are also big producers. What’s more, Canada’s oil industry is working hard to develop export markets for heavy oil, because there is a great deal more production yet to develop. Indeed, Canadian producers are selling their heavy oil at a discount because they cannot get it to world markets.

According to one excellent and credible report, seven years from now Alberta alone will be producing about three million barrels per day of “Heavy, etc.” That estimate risks production for economic and environmental obstacles, so it is probably low.

• Third – and this is my main point – let’s acknowledge that the serpent-like production line in Campbell’s chart, while it is not a happy sign, is not the spectre of doom it appears. The world’s unconventional resources will greatly blunt the blow – relative to the steep declines described in Campbell’s chart, in any event.

One amazing feature of the oil sands is their incredible energy density. Imperial Oil’s Cold Lake bitumen plant, for example, is a tiny dot on the map of Alberta, yet it produces 6 per cent of Canada’s oil. The resource density of these unconventional resources is immense, and that density is what makes it such an important resource. The world is heading toward capital-intensive, technology-intensive, pollution-intensive and energy-intensive energy - bitumen from Cold Lake, for example.

The greater the capital intensity, though, the lower the geopolitical risk must be. Keep that in mind when you consider development prospects for Venezuela’s Orinoco heavy oil belt, which is so huge it rivals the resources of Canada. The geopolitical risks in that country are enormous, so the likelihood is small that new Venezuelan supplies will soon hit world markets.

Strongman Hugo Chavez is increasingly unpopular in his own country, however, and the economy is in disarray. Oil production is in decline even though the the country has the largest conventional reserves in this hemisphere. Given that situation, it is possible to imagine a post-Chavez Venezuela which will develop those resources and become a resurgent supplier to the world. If that happened, it would lead to another super spike in booked reserves.

I share the view that a global Hubbert’s peak is nigh. The world is facing serious energy supply problems, and they are related to peak oil. To too great a degree, however, the discussion has failed to recognize the immensity and importance of the world’s unconventional sources of oil. Those vital resources will radically change the shape of the chart as they are plotted into it.