Selling Canada?

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As Asian efforts to secure Canadian energy supplies intensify, can nationalist forces be silent much longer? This article appears in the November issue of Oilweek.

 By Peter McKenzie-Brown
In Canada, economic nationalism fell into a slumber twenty years ago. Is it likely to begin stirring again? According to Dr. Robert Mansell of the University of Calgary, “I could imagine a new period of nationalism. After all, public attitudes tend to go through regular cycles.”

An economist, Mansell is academic director of the university’s School of Public Policy and the founding director of the Institute for Sustainable Energy, Environment and Economy. Although he recognizes the possibility, Mansell puts a lot of caveats on the prospect of a nationalistic surge. “We’re still in a period with a high level of globalization, so I would be surprised if we said ‘No more foreign ownership.’ The markets are too big now (for Canada) to finance a lot of (the petroleum industry’s) activities, so you have to go into international markets for large amounts of money. We don’t have a lot of fiscal surpluses to finance many of these projects. This limits our options.”

However, he notes that political conflict with China, say, could lead to public concern about Chinese investments in Canada’s oil industry. In the United States, an outright political row wasn’t even required five years ago. That’s when a public outcry put an end to an $18.5 billion hostile bid by state-controlled China National Offshore Oil Corporation for UNOCAL, an American major. Chevron-Texaco acquired Unocal later that year.

Asian Investments
This has become an issue of interest because the sources of overseas funding for North America’s energy industry are undergoing a fundamental shift. “The axis of investment capital is rotating from a north-south flow over the 49th parallel to an east-west current across the longitude of the Pacific Ocean,” says author and analyst Peter Tertzakian of ARC Financial. “A recent swell of Asian money coming into the Canadian oil patch represents one of the biggest megatrends in the business.” Tertzakian does not mention a sub-feature of this shift of Asian funds: much of the money is coming from national oil companies
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By no means is this trend limited to Canada. Increasingly, developing countries with financial reserves are investing those funds in countries with large oil and gas resources. “Relative growth in energy demand has shifted quite dramatically toward Asia,” says Robert Mansell. “As demand shifts, one would expect (Asian) interest to shift to Alberta, especially since the number of countries which are attractive for petroleum investment is shrinking. There has been an expansion of interest in national oil companies for a variety of reasons, one of which is to achieve security of supply. Energy security (in Asia) is an even bigger issue than it is North America.”

Peter Tertzakian puts the issue starkly. “Since world war two there has been a symbiotic, bi-directional flow of capital and energy resources between Canada and the US. Now a new dynamic is emerging…. Growth economies like China look very similar to the United States in the 1950s and 60s – capital rich and hungry for energy.” In a series of charts and tables, he sums up the shift in funding.

“Big foreign companies like India’s Reliance Industries, China National Petroleum Corporation and Mitsui have been teaming up with domestic independents that hold large land positions in shale gas plays, mostly in the US” he says. “Under twelve joint venture agreements these foreign entities have committed $17.2 billion of funding to obtain carried interest in new wells being drilled by independent natural gas producers like Chesapeake, EnCana, Pioneer, Atlas and Carrizo.” The charts illustrate the recent flow of money from overseas economic powers into North America’s shale gas business.

Within Canada, some funds have flowed to shale gas, but more has gone to the oil sands. The table of foreign investments in the last 12 months illustrates that Asian investment in Canada has focused more on the oil sands more than shale gas. The table does not include another notable 2009 investment: Sinopec’s acquisition of Addax Petroleum for $8.27 billion.

Of the new Asian partners, four are national oil companies headquartered in China or Korea. However, the acquisition of Harvest Energy by an agency of the Korean government deserves special note. Harvest was an intermediate-sized Canadian energy trust. From a standing start, in ten years president and CEO John Zahary created an entity he was able to sell for more than $4 billion. That’s a lot of money, but relatively small potatoes in the context of Canada’s hundreds of billions of dollars’ worth of total oil and gas assets. Outside the industry, people paid scant attention
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Harvesting Energy Companies
Of course, Korea isn’t China, and Harvest Energy isn’t Unocal. Even so, the deal stoked concern that, after watching parts of the oil patch go to other state-owned companies, the Canadian government will eventually step in to block transactions.

According to John Zahary, though, the South Korean company’s commitment to boost spending is the only thing that’s relevant. “We see this as an opportunity for increased jobs in the country, increased capital investment in (Harvest’s) assets,” he said. “KNOC (the Korean National Oil Company) now owns 100% of the equity in the company – that’s true. But I believe that even under the new ownership Harvest is still a Canadian company. The management is here, the employees are here, the resources are here and the resource owner is here. We now have a board of directors of eight people: five are Canadians and three are Korean nationals.” To make the deal happen, Zahary negotiated a 47% premium to the company’s then-current price. He now expects to see Harvest continue to grow.

“Why did they want to invest here?” he asks rhetorically. “We have a resource that is relatively underdeveloped, a people base and a technology base. We have relatively stable fiscal and regulatory systems and a history of openness to foreign investment, and that differentiates us from other countries. Canada is an excellent place to invest. I look at foreign investment (in this country as part of the) maturing of the nation.” The University of Calgary’s Mansell agrees. “….In this global environment even companies that you think are purely Canadian are likely to have most shares held outside the country. The key issue is their local presence. The control is local. There are a lot of regulations in Alberta,” for example. “Whether foreign or local, companies have to follow the rules that we make. They can’t avoid them.”

Another rhetorical question: Why did Zahary want to sell Harvest Energy Trust? Partly because Ottawa’s Halloween Massacre in 2007 made energy trusts so much less attractive. Prior to the sale, Harvest’s unit price had cratered since its pre-massacre high – down about 80%. This, of course, illustrates government’s power.

The case for economic nationalism
Perhaps the most unlikely supporter of government regulation is Richard Haskayne. Known universally within business circles as Dick, he has served as the chair of six large Canadian companies: Interhome Energy Inc., TransCanada Corporation, Fording Inc., NOVA Corporation, TransAlta Corporation and MacMillan Bloedel.

“My philosophy is that Canada needs regulation to protect strategic sectors,” he says. “This is not a new hobby horse for me. A few years ago I wrote an article promoting the idea behind Canada’s Bank Act, and I got a lot of flak about it. But recent events have demonstrated that it worked really well for Canada. The reason (I support that kind of government control) is that banking is so strategic for Canada.”

He supports government regulation of energy and mining ownership because they, too, are strategic. “That’s our strength. Of the ten top stocks in Canada there are four banks, three energy companies and three mining companies. Seventy percent of the stocks on the TSX are in those industries.”

“I’m not opposed to foreign ownership as such,” he says “– only when someone takes over 100% of a classic Canadian company like Potash Corp. Look at Vancouver without McMillan Bloedel. Look at the Windsor waterfront now that Hiram Walker is no longer there. Head offices are critical to the operation of Canada and to our decision-making.”

Haskayne sees Canada’s Bank Act as a good model for bank regulation. The act prevents any individual from owning more than 10% of the shares of top tier banks, and says the aggregate holdings of non-residents and their associates may not exceed 25%. In addition, their head offices must stay in Canada and their boards must consist mostly of Canadians. Deeply concerned about what he calls the “hollowing out” of head offices from Canada, he’d like to see similar provisions applied to Canada’s biggest energy and mining companies. “It’s the concentration of shares that’s the critical part.”

An irony of Haskayne’s position is that as chairman he sold Nova’s controlling interest in Husky to Li Ka-shing. “I admit I sold that company to Hong Kong interests,” he says, “but in those days Husky was in terrible shape. It was almost broke. The banks were on their tail. We tried to sell it. I went to David O’Brien at PanCanadian and tried to get him to buy. I said, ‘It’s a hell of a deal for you. It’s got so much heavy oil and it’s got refining interests….’ David turned to me and said, ‘Haskayne, get out of my office. I don’t want that sick dog [Husky] in my kennel.’ You can’t get much more of a refusal than that. So we sold our share (to Hong Kong interests) for $375 million. Well, today that interest is probably worth $15 billion, so they made a hell of a deal. I apologise for that, in a way. However, there wasn’t much we could do. Li Ka-shing’s group was holding the golden shares, and that made it hard to sell” the company to anyone else. Husky is now one of Canada’s biggest energy companies.

Asia’s energy security
Canada’s last round of economic nationalism began in the 1970s, when nationalization of the petroleum sector within OPEC inspired Canadian governments to set up their own oil companies. The idea was to Canadianize a vital resource sector. The last vestiges of those experiments disappeared a year ago, when Suncor absorbed Petro-Canada.

Are Asia’s efforts to find energy security with the aid of national oil companies (NOCs) also doomed to fail? “For the foreseeable future,” says the University of Calgary’s Robert Mansell, “Asian countries are not likely to be getting any Canadian product directly. But they can still do swaps and so on, taking oil that would otherwise have gone to the United States, diverting production. Markets enable you to move that oil around. Different market arrangements will allow you to increase security.”

He cautions against thinking of all NOCs as being the same, however. “There are quite different NOCs. For example, Statoil is really not much different from what we think of as a privately owned company. Some of the other companies are a different animal, though – they are just an extension of the state. There are quite different variations when you start looking at national oil companies.”

Although he sees economic nationalism as a possibility, Mansell is sceptical about its staying power. “A serious political conflict between, say, China and Canada could create a public reaction, and it’s quite easy to imagine” a public outcry against Chinese ownership of Canadian resources. “However, in the long run it seems to me that most Canadians appreciate that we as a country benefit from global investment.”

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Pipeline Politics

The fate of two key oilsands projects is anything but certain. In red, above, Keystone.

This article appears in the September issue of Oilweek.

By Peter McKenzie-Brown

A web of oilsands pipelines is spreading from Canada’s oil hub at Hardisty, Alberta into American markets. At the beginning of summer, TransCanada’s Keystone Pipeline began delivering 435,000 barrels of oil to refining centres in Illinois. This fall, Enbridge’s Alberta Clipper will begin delivering an additional 450,000 barrels per day to Superior, Wisconsin.

That’s just the beginning, though. The Alberta government believes US imports from the oilsands will increase from today’s level of about 1.5 million barrels daily to nearly 4.3 million barrels daily in 2030, and there is plenty of potential to expand production beyond those numbers. So much expansion calls for a lot of pipelines. Will they reach primarily into the US, or will East Asia also become a key market?

The answer lies with the fate of two great pipeline proposals – TransCanada’s Keystone expansion and Enbridge’s Northern Gateway lines – which are both before the regulators. Although they reflect fundamentally different approaches to the market, TransCanada’s Keystone Expansion and Enbridge’s Gateway line represent vitally important industrial links from Alberta to the outside world. In different ways, the two proposals are embroiled in a conflict of old issues pitted against the new.

The old issues are technical and economic. The barrel of oil is blackening everywhere as supplies of light, sweet oil decline, and global demand is rising. Oilsands production is increasingly available and needs markets. The world’s big refining centres need feedstock and have the capacity to refine bitumen; pipelines are efficient and safe. The proposed pipelines are mega-projects which will provide jobs and economic stimulus. Oil-importing countries around the world want to develop secure, longer-term supplies.

The new issues are soft and ecological. Some environmental groups are aggressive against hydrocarbons, especially bitumen; they have successfully painted the oilsands black and want to further punish Canada’s merchants of dirty oil. Citizens wanting a greener world worry that the pipelines may lead to industrial accidents which spoil the environment. Politicians respond by supporting green measures that are sometimes ill-considered. Regulatory hearings drag on for months or years, and court challenges add to the delay.
In different ways, these are the issues facing Keystone and Gateway. Taken together, they are a fascinating study in pipeline politics.

Keystone
The Keystone Pipeline focuses entirely on delivering oilsands oil to US markets. The first phase of Keystone line began deliveries to the US Midwest in June.

About 3,500 kilometres in length, the pipeline transports oil from Hardisty, Alberta to US refineries in Wood River and Patoka, Illinois. The Alberta section involved construction of some 375 kilometres of pipeline, pump stations and terminal facilities from Hardisty. The next section involved the conversion to oil of nearly 900 kilometres of TransCanada’s natural gas mainline in Saskatchewan and Manitoba. The American section, to Illinois, is about 2,200 kilometres in length.

That was only the beginning, however. Phase II will involve a 480-kilometre extension from Nebraska to the marketing/refining and pipeline hub in Cushing, Oklahoma. Then comes the $7-billion Keystone Gulf Coast Expansion Project – approximately 2,700 kilometres in length, 36 inches in diameter, with completion planned for 2013. If constructed, this line would extend the system to 5,150 kilometres of total length: from Cushing it would be extended to Port Arthur, Texas and possibly also to Houston.

Keystone already has capacity of 435,000 barrels per day, and that will increase to 591,000 barrels per day with completion of the Cushing leg at the end of this year. With the completion of the expansion, the project would be able to deliver 1,100,000 barrels per day. Completion would run the total tab for the Keystone project up to US$12.2 billion.

War of Words
The day after TransCanada Corp.’s outgoing chief executive officer Hal Kvisle went to Wood River to ceremonially turn on the Keystone tap, Alberta premier Ed Stelmach published a half-page ad in the Friday edition of The Washington Post. His letter was partly a response to a letter to Secretary of State Hillary Clinton from 49 Democratic representatives. The letter urged her to halt the Keystone expansion on grounds the bitumen represents damaged environments in northern Alberta and higher carbon dioxide emissions in North America. For construction to proceed, the project needs approval from Clinton’s State Department.

Hoping to face down these congressmen, Stelmach argued that the oilsands are a reliable source of energy, and that the province is reducing pollution. His hottest zinger: “A good neighbour lends you a cup of sugar. A great neighbour supplies you with 1.4 million barrels of oil per day.” The response? Heavy-hitting U.S. Congressman Henry Waxman sent yet another letter hostile to the oilsands to the Secretary of State.

Consistently using the pejorative term “tar sands,” he described the Keystone expansion as “a multibillion-dollar investment to expand our reliance on the dirtiest source of transportation fuel currently available.”

The Keystone expansion, he added, “is a $7 billion pipeline that would transport up to 900,000 barrels/day of tar sands crude oil almost 2,000 miles from Alberta to refineries in the Gulf Coast. This pipeline would roughly double the quantity of tar sands fuel currently being imported, and in conjunction with two previously permitted tar sands pipelines that are not yet in full operation – Keystone and Alberta Clipper – would more than triple the quantity of tar sands fuel imported to the United States. The cumulative effect of the three tar sands pipelines would be to increase tar sands imports to over 3 million barrels per day. To process this large increase in tar sands imports, U.S. refineries will invest billions of dollars more in refinery upgrades.”

Outside the American Congress of course, there are many proponents of oilsands imports. According to lobbyist Tom Corcoran, executive director of the Washington-based Center for North American Energy Security, “ensuring access to affordable, reliable energy from our North American allies…should be a national priority. Projects such as the Keystone pipeline ensure increased domestic energy security, stable prices for consumers (and) minimal environmental impacts.” He added that “any evaluation of the indirect (greenhouse gas) emissions (such as from oil sands production or the transportation sector) would be purely speculative.” In all likelihood the energy security argument will prevail in Washington, and Secretary of State Clinton will issue a Presidential Permit allowing the Keystone Expansion to proceed.

Northern Gateway
But with so much resistance to bitumen imports from America’s environmental camp, why not just export the stuff to other countries? That’s the concept behind the other big pipeline project, Enbridge’s Northern Gateway Pipelines. This project is also being jeopardized by environmental concerns, but of quite a different kind.

The $5.5 billion Northern Gateway project would take oil from the Edmonton area to the nearest deepwater port – at Kitimat, on a British Columbia inlet.

To export the stuff would involve building a marine terminal with two ship berths, condensate tanks and 11 petroleum tanks. Only modern, double-hulled tankers could use the terminal, and escort tugs would be in charge of moving them in and out of risky waters. The Enbridge proposal also calls for third-party tanker inspections. The terminal would have a radar monitoring station and first response capabilities in the event of safety incidents or spills.

The 1,172 kilometre dual pipeline project would have a 36-inch pipe able to carry about 525,000 barrels of upgraded bitumen and bitumen blends into export markets every day. For the first time, Canadian oil would have significant access to overseas markets, primarily in East Asia. Northern Gateway would have a parallel 20-inch pipeline for flow of imported condensate from Kitimat to Alberta.

Condensate is the low-density (63o API) mixture of hydrocarbon liquids used as diluent to enable bitumen to flow, and this line would carry 193,000 barrels per day. Domestic supply is very short and there is little potential for internal growth because of declining gas production. To make up for shortfalls, for years the industry has been shipping condensate into Alberta by railway.

This line would thus assist the oilsands industry by opening up overseas markets, but also by bringing in the thinning solution needed to take the product to port. Enbridge wins both ways, but so does the oilsands sector.

Northern Gateway’s condensate pipeline is part of a two-pronged effort by Enbridge to bring diluent to the oilsands and heavy oil sectors. The company’s Southern Lights project from Chicago to the Edmonton area has already begun to fill, and will begin delivering 180,000 barrels per day of condensate this fall. The Southern Lights project runs roughly parallel to Enbridge’s Alberta Clipper line, but in this case the hydrocarbons are coming into Canada for use by oilsands producers.

Looming Engagement
As described earlier, the Keystone expansion is already dealing with political opposition, and its proponents have joined battle with its political and ENGO opponents. By contrast, Northern Gateway has barely begun the struggle. However, the company has employed armies of public relations and public consultation teams to do battle.

Armies they will need, because public opinion on the West Coast seems to be strongly against the project.

According to a poll commissioned by Forest Ethics, an ENGO, 80 percent of British Columbians support a crude oil tanker ban for BC’s coastal waters, while 15 percent think tanker traffic should be allowed. Significantly more British Columbians oppose the Enbridge Northern Gateway pipeline (51 percent) than support it (34 percent). And British Columbians who strongly oppose Enbridge’s pipeline (31.7 percent) outnumber four-to-one strong supporters (8.1 percent).

The basic issues are two: transporting oil across aboriginal territory, and using tankers to transport oil along the B.C. coast. Both of these are greatly complicated, however, by the perception that oil from the oilsands is dirty.

Enbridge needs to secure rights-of-way to construct the line through the lands of 48 Aboriginal communities located along the pipeline route – half of them in B.C. To prepare for hearings in this area, Enbridge commissioned studies on the project’s potential cultural, social and economic effects; its impact on traditional land and resources use; and its potential effects on heritage and archaeological resources. However, in March nine coastal First Nations declared a ban under their traditional laws on the transport of oilsands oil through their territories, and announced at a news conference that they would take whatever steps were necessary to stop the project.

Getting approval for tankers to carry oil through the passage from Kitimat to the Pacific, and thence within Hecate Strait, to the east of the Queen Charlotte Islands, is becoming a political football. In 1972 the Liberal government of Pierre Trudeau imposed an informal ban on oil tanker traffic in this area. At the beginning of summer, Liberal Leader Michael Ignatieff announced that the federal Liberals would formalize a moratorium on crude oil tanker traffic in British Columbia’s northern coastal waters. He was clearly playing to public opinion in the province. Oil tankers have been moving through southern coastal waters for half a century, carrying oil from a Kinder Morgan pipeline terminal in Burnaby at Burrard Inlet without a major spill.

“It’s been (our) vision...to find another market for Western Canadian oil,” Enbridge’s engineering manager Raymond Doering told the Caledonia Courier, which is published in the town of Fort St. James. Gateway has “been described as the largest private infrastructure investment in B.C.” He added that the company has established positive working relationships with 24 First Nations communities in Alberta and 18 of the 24 affected First Nations in B.C. So far, so good. Then he added that there is a small, vocal minority of First Nations people opposed to the project
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“A small group of (First Nations) people object to the dirty oil pipeline?” an infuriated reader wrote in response. “There are thousands of BC people opposed to the dirty oil tankers in our pristine coastal waters....When (an oil spill) happens, the beautiful Orca and Humpback whales, and all the marine life will perish. I don't give a dam (sic) if the dirty tankers have 10 hulls, those are dangerous seas, and hard to navigate. There is still oil collecting on the rocks from the Valdez spill, 21 years ago....”

Struggles
As we said at the beginning, after the engineering and the economics come soft issues which can be hard to deal with. America’s Department of State will make the final decision for the Keystone Expansion – probably buying the energy security argument.

In Canada, the National Energy Board will make the final decision for Gateway. The NEB has appointed a joint review panel to examine the project’s environmental effects, look for ways to mitigate negative effects, hold public hearings and consider comments from the public and Aboriginal peoples, and submit an environmental assessment report with reasons and recommendations about the project to the federal government. Gateway’s fate is far less assured than Keystone’s.

For the oilsands sector, which needs expanding export markets to continue to grow, the pipeline struggles are vital. Watch them closely.

He Rocks

 Former "coker rat" Byron Lutes plays the guitar, rides a longboard and - oh, yeah - is leading a serious oilsands contender

This article appears in the August issue of Oilweek.

By Peter McKenzie-Brown
I didn’t expect the answer Byron Lutes gave me when I asked what kinds of books he reads. “I read a lot,” he said. “Just last night I finished When Giants Walked the Earth, by Mick Wall. It’s a biography of Led Zeppelin. It was great.” The choice surprised me. As we talked, however, the title seemed increasingly fitting. Surely if there’s an industry dominated by giants it’s the oilsands, yet here’s a guy leading a small company who wants to become a leader in the game.

Lutes has a ready smile and a lot of confidence in what he’s doing – turning the two-bit shell of a VSX (Venture Stock Exchange) company into a serious oilsands contender.

A chemical engineer by background, the athletic president and chief executive officer of Southern Pacific Resource Corp. graduated from the University of Calgary in mid-1986, just as oil prices collapsed from $30 per barrel to $10 and layoffs within the industry became the order of the day. “Only two of about 50 graduates in my chemical class got jobs after graduation.” Byron Lutes was one of them. As a student he’d worked at Suncor during previous summers, and the company wanted to keep him on.

Instead of getting the typical new hire’s tour of the company, though, he found himself working for Suncor just as it became immersed in labour strife. Employees at the oilsands plant had gone on strike, and he was shipped off to Fort McMurray to help operate the upgrader. “I was a coker rat,” he says. “I was swinging valves and cutting coke. It was a dirty job – all-night shifts – but I loved it because I got to learn a lot coming right out of school. I spent eight years at Suncor, doing various things. I did reservoir engineering and a year and a half stint in marketing. It was a terrific company to work for, and I got a lot of great experience.”

When he was 30, Lutes’ romance with junior oils was about to begin. “One of my former bosses, Sid Dykstra, had set up a company called Newport Energy and he asked me to join him. The company was making about 2,200 barrels of oil a day. Over the next seven years we grew it to about 30,000 and then sold out to Hunt Oil.” He stayed with Hunt for the next three years, running their Canadian operations. “That was a complete change, going from a grassroots, publically traded Canadian company to a private, very large American one. I knew I wasn’t going to stay.”

In 2002 he went to work for ManCal Energy, a privately-held company owned by Calgary’s Mannix family. “We were always growing stuff, developing it and selling it to take a profit. That was part of our game plan. We didn’t want to build up the staff complement, which was about 20 people. ManCal was another really good company to work for.”
 
Food chain
After five years with ManCal, Dave Antony – the chair of Southern Pacific Resource Corp – approached Lutes “out of the blue” to run the company. “It’s been quite a ride. (The company) had a bunch of land in the oilsands and some exploration programs, and they needed someone to come in and lead it.”

Though the oilsands are an area where giants generally do walk the earth, Lutes sees a lot of opportunity for junior oilsands companies. “Smaller companies can move their projects forward faster, from a regulatory, financial, and execution standpoint,” he says. “They can exploit areas that a larger company may have overlooked. They (can) attract and retain top entrepreneurial expertise. There will always be room for different sizes, as in any industry, and the food chain will also likely always be there.”

The story of the resurrection of Southern Pacific illustrates two quite different business models that are part of the industry’s food chain. The company, which has an undistinguished pedigree, was first traded on the old Vancouver Stock Exchange as New Wellington Mines Limited, in 1953. According to Lutes, “Dave (Antony) and his associates find shell companies, clean them up, recapitalize them and put in a management team.” That’s one part of the food chain.

A private company known as Bounty Developments Ltd. illustrates another. Bounty’s “modus operandi is to get land positions and turn them over to another company, keeping an override on the land. They’ve been very successful with that. We made a deal with them, met some work commitments and acquired 219 square miles of land (sections) in the oilsands, most of it raw acreage. We earned an 80 per cent interest in the property.” Southern Pacific has since expanded its oilsands acreage, and now has an average 81 per cent working interest in 301 sections.

To play in the oilsands you need lots of money, and institutional investors in particular won’t touch a company listed on the Venture Exchange – too much risk. Southern Pacific needed to move to the Toronto Stock Exchange, and that required cash flow.

To get there, the company issued equity and took on debt to acquire Senlac, a Saskatchewan heavy oil property producing 5,000 barrels per day. The price was $90 million. “As soon as we had that we were a going concern, and it enabled us to advance to the TSX. That means more due diligence, but a lot more investors now will put their money into the company.” The company began trading on the TSX in June.

SAGD-able
To look to the company’s future, you need to first look a bit deeper into its recent past. When Lutes took on the president’s role at the beginning of 2008, the boom was still around, although it had been soured by Premier Stelmach’s ill-considered and now largely defunct “fair share” royalty revisions.

“When I first joined we were getting ready to start up a major winter drilling program. The company had in the neighbourhood of $60 million in the bank, and we had a lot of core holes to drill but the market was getting choppy. So we were lucky enough – and (chairman) Dave (Antony) was smart enough – to realize it may not be easy to raise equity in the market, so we really conserved our cash.” Lutes pulls out a map. “We cut back on our drilling program but were lucky enough to find in this McKay block a significant resource that we thought could support a good SAGD project. We focused and drilled into this area and found ourselves a project.”

The company’s first oilsands production will come from two pieces of land separated by the McKay River. Especially when he talks about the first of these properties, Lutes gets visibly excited. “It’s a great property to sink our teeth into as our first green-field Athabasca bitumen SAGD project. The reservoir has all the properties you need to make SAGD work, no complications like top gas or bottom water or shale compartments, and this one can use a proven technology.”

He stresses that you shouldn’t “risk the company by using unproven technology. Let the big guys figure that stuff out. We know that SAGD will work. Reservoir thickness ranges from 15 metres to about 30 metres. It’s definitely SAGD-able.” Oil saturation in the reservoir ranges from 70-80 per cent with an average of 75 per cent, he says. The reservoir “is not as thick as some properties further south” like Suncor’s Firebag project. “However, it’s a great property.”

At the low point in the financial crisis, last year Lutes’ team prepared a SAGD proposal for submission to the ERCB. “We designed a 12,000 barrel per day project for two reasons. From a regulatory perspective, it’s the fastest way to get onstream. If you make a proposal for more than 12,600 barrels (2,000 cubic metres) per day, approval takes another year. That’s the first reason. The second is that if you develop a smaller project, you can use standard equipment. Other companies are using the same pots and pans as we’ll be using. That gives us better control of our capital costs, since that equipment is made locally. We don’t have to go to international manufacturers.”

As for expansion and timing, Lutes is characteristically optimistic. “We think we’ve got enough resource to expand. We have contingent resources, and we think we can grow our capacity up to the 36,000 barrel per day range” within two years of construction of the first project. “Our first project is going to be steaming up at the end of 2011, and on full production by 2013. We think we can expand to the east side of the McKay River and also expand the original project on the west side. We hope to have applications in by the middle of 2011. Based on our recent experience, the applications take about 14 months to process.”

The cost of the initial project will be about $428 million. For Phases 2 and 3, Lutes estimates $380 million. “The difference is that infrastructure costs for the next phases will be lower once we are in the area.” Southern Pacific will use cash flow from Senlac in Saskatchewan and from McKay to fund growth in other oilsands leases.

Longboarding
Outside the office, Lutes is both musical and athletic. He’s had an interest in rock music since he and some friends started up a rock band in high school: “I played bass and sang.” The guitar playing is something his three sons – Cory, 19, who is studying engineering at UBC; 11-year-old Kyle; 9-year-old Dylan – have all taken up.
His wife Kathy and he are heavily involved with soccer with the younger boys. Formerly an accountant with TransCanada, she is now a full-time mum and treasurer of her kids’ soccer club. I ask about hockey. “We absolutely love hockey. We watch it religiously but we don’t play it. The reason is that we have a genetic problem,” he deadpans. “We can’t turn right on skates.”

He can turn right on the longboard, however. Essentially a surfboard with wheels, these long skateboards can measure 1.5 metres in length, and good riders can perform complex tricks on them. “I took up longboarding this summer,” he says. “Longboards really cruise. My kids have them, and they are a lot of fun. I figure if the kids want to use them, I might as well go boarding with them. I play basketball with them, too.”

How do you sum up Byron Lutes? A guitar-playing businessman, a longboarding engineer, an executive hooked on rock concerts. Too bad he can’t turn right on his ice skates.

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Unconventional Challenges

There's nothing unconventional about shale gas in western Canada, but the technology to get at it? Now that's a different story

Photo: Rig for coil tubing. This article appears in the June Unconventional Gas Guide

By Peter McKenzie-Brown

In a recent presentation to the Petroleum History Society, Dave Russum – geosciences vice-president for AJM Petroleum Consulting – recounted the development of unconventional gas in Western Canada. According to Russum, evolving technology is making unconventional gas – what he says should correctly be called “conventional gas from unconventional reservoirs” – a commercially viable commodity. Despite the lower-price environment for natural gas, rapid innovation in down-hole technologies has made shale reservoirs viable sources of gas production.

The most important of these is horizontal drilling. Since the technology became widespread in the late 1980s, horizontal drilling has been enhanced by increased drilling efficiency. Much longer horizontal legs are now possible: many are two and three kilometres in length. This is possible because of improvements in bit design, the increasingly effective use of coil tubing and better down-hole motors.

Geo-steering is another increasingly critical down-hole technology. In recent years it has been given a lift by high-impact measurement-while-drilling (MWD) tools and techniques.

Another contributor to the shale-gas revolution is multi-lateral horizontal drilling – the ability to drill several laterals from a single well. As one example, last year Trident Exploration drilled a 2,400-metre vertical well into the Montney formation near Dawson Creek. At depth, the company drilled two 1,000-metre horizontal laterals. This achievement illustrates the revolution taking place in horizontal drilling – although 1,000-metre laterals are puny by the standards of some drilling programs.

Two other technologies are more directly related to reservoir production. The industry can now isolate many completion zones in horizontal wellbores. This makes reservoir fracturing possible over long distances. What’s more, microseismic technologies now enable geo-engineers to improve reservoir development and productivity by monitoring fracture efficiency within reservoirs.

Although these technologies are increasing in sophistication and declining in relative cost, they have led to a fundamental change in gas-field economics. The petroleum sector’s spending patterns are shifting, with a much bigger portion of the development pie now being invested underground. For the first time, the industry is investing more down-hole than in gathering lines and other surface facilities.

Microseismic
Microseismic has made great strides in the last decade. One of the leaders in this area is Houston-based Microseismic Inc. The company was founded in 2006 by Peter Duncan, who originally hales from New Brunswick, got his Ph. D. in geophysics from the University of Toronto, and cut his teeth in resource development in Alberta and offshore Nova Scotia working for Shell Canada. He stresses that the technology in itself is not new. It is well established academically and within government organizations – for use in earthquake location, for example. Applying the technology to producing reservoirs, however, is a new and rapidly developing field.

Duncan explains microseismic with vivid analogies. “Regular oil and gas seismic is like an X-ray,” he says. “Microseismic is more like a stethoscope. You can ‘hear’ the sound of fluids underground.” This is an area of rapid technological growth.

According to Duncan, “We can cement geophones on the surface and underground to enable people to better produce these gas shales, and monitor production for the life of the field. With the developments we are making today, these arrays are like a big-dish microphone. (Using a computer) you can essentially beam-steer that array around the reservoir to find out what’s going on where. The cost-effective way to do this is to set up a permanent array of phones to monitor the fraccing of every well during the development of the field.” For shale gas production, a key feature of this technology is that it can tell you where well fraccing has been effective, and where it hasn’t.

“With this system, you can monitor other subsurface phenomena – for example, the injection of water or other production fluids into the reservoir. An important application has been the use of these systems to monitor cyclic steam injection in the oilsands.” Both Shell and Esso have been doing this, although using different microseismic suppliers.

What’s the cost? Microseismic is more expensive in the Montney formation than it is in the Barnett shales of northern Texas, for example. However, a technical paper from EnCana has suggested that the incremental cost of monitoring a frac stage with one of these permanent arrays is relatively small – fully amortized, about $10,000 per frac stage. If that monitoring enables geo-engineers to increase ultimate gas production by correcting fracturing inefficiencies, it’s a small price to pay for what could be much greater cash flow.

Coil Tubing
The workhorse of underground technologies is coil (“coiled”) tubing – a tool that began to make big inroads into industry operations around 1990, and has since transformed many aspects of underground drilling and workover operations. It refers to metal piping spooled on a large reel and used for interventions in wells and sometimes as production tubing in depleted gas wells. Coiled tubing is often used to carry out operations previously done by wirelining. The main benefit of coil tubing over wireline is that you can pump chemicals through the coil. With coil tubing you are able to push tools and chemicals into the hole; wirelining relies on gravity.

The tool string at the bottom of the coil can range from something as simple as a jetting nozzle, for jobs involving pumping chemicals or cement through the coil, to a larger string of logging tools, depending on the operations. Coil tubing is also used for relatively inexpensive work-over operations. It is used to perform open-hole drilling operations.

Of particular importance in the context of shale gas production, coil tubing can be used to fracture the well – a process where fluid is pressurized to thousands of psi on a specific point in a well. This blasts the rock into rubble, thereby permitting the flow of hydrocarbons to the well-bore.

Fractious
The move to more intensive down-hole spending is shifting the industry away from its traditional ways of doing business, and even the seasonal patterns it follows. Consider fraccing.

Fraccing is a stimulation technique which improves production from geological formations where natural flow is restricted. Hydraulic fracturing pumps a mix of water, sand and some soluble chemicals into the well at high pressure, thus fracturing the formation and holding the fractures open so hydrocarbons can flow more freely into the wellbore.

Dave Russum takes the story from this simple explanation to the use of multi-stage fracturing techniques on horizontal wells. “Between the heel and the toe of a horizontal well,” he says, “you isolate an interval close to the toe and frac that region. Then you move back towards the heel, isolate another interval and do another frac. This breaks up a lot of rock, making 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.”

In the days of vertical drilling, producers generally fracced just one or two zones per well. With today’s technology, it is possible to frac a single well up to 17 times – although a well that required so much work would likely have a horizontal reach of 3,000 metres or more.

To fracture just one of EnCana’s Horn River shale gas wells in north-eastern BC, you need a fracturing crew equipped with perhaps 45,000 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,” said Kevin Lo of FirstEnergy Capital 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.

Dale Dusterhoft, a senior vice president at Trican Well Service, paints an even grimmer picture. “Some of the Horn River wells require up to 45,000 horsepower of compression,” he says, “and with 10 holes per pad you may have 40,000 horsepower tied up for 10 weeks.” He adds, “There will be shortages of equipment when we get up to full development of the shales” – a plus for service companies like his own, which will then charge premium day rates, but a worry for the big players in the region.

Although environmentalists have voiced concern that fraccing chemicals may contaminate groundwater, Dusterhoft argues that before wells are fracced the formations are securely sealed away from potential fresh-water reservoirs. And anyway, he says, in the unconventional wells in north-eastern BC “we only use a polymer as a friction reducer, and maybe something to stabilize the clays. Mostly we just run water and sand.” When fraccing is completely successful, he says, “All the fractures connect up with each other, so we can get maximum production. We like to say we can ‘farm’ the reservoir.”

Huge fraccing jobs like those in north-eastern BC require a great deal of logistical support. Each hole can require 2,000 to 3,000 tonnes of fine-grained sand as a propping agent. Imagine the parade of trucks bringing such a harvest of ancient beach sand up the road to north-eastern BC – often from quarries in Saskatchewan. To take on such a project may require a 40-member crew and 20 or more hydraulic compression systems mounted on huge fraccing trucks.

Because so much water is required, a typical job requires a large water storage pit in addition to a string of high-volume steel tanks. The amount of water being used in these jobs has actually led to a seasonal shift in the fraccing business. According to Dusterhoft, “Now (the industry is) drilling during winter freeze-up, as we always have, but fraccing in the summer. All the bigger operators are trending in that direction.” The reason is that the water is easier to deal with in warmer weather. In the longer term this will require upgrading to all weather-roads to Horn River and Montney. Until those upgrades are completed, service companies are leaving equipment in the area during freeze-up.

The shift to unconventional gas production occurred much more quickly than anyone expected, Dusterhoft said, and it has important implications. For one thing, it is contributing directly to the reduced number of wells being drilled in Western Canada. There are now about as many horizontal wells being drilled as those being directionally drilled.

To put that in perspective, drilling costs at Horn River are in the $5-7 million range per well, while they are maybe $4-5 million each at Montney. Add to that the cost of fraccing – say, $2-3 million per well – and it’s clear that the industry is putting a lot of money in the ground. But the production profiles for these wells make it worth the cost. These wells may produce 7.5 million cubic feet of gas per day for the first year. Production declines rapidly in the early stages but the optimists believe they may level off at, say, 2 million cubic feet per day and maintain those production levels for years.

Challenging to Extract
AJM’s Russum disputes this. “Each reservoir is different,” he says. “We don’t fully understand the science of shale gas reservoirs. I certainly don’t think we can apply a one-size-fits-all model to their production profiles. Some wells may simply stop producing in only a year or two.”

In wrapping up this commentary, it may be useful to return to Dave Russum’s assertion that there is no unconventional gas – only “conventional gas from unconventional reservoirs.” Russum stressed that shale gas plays are only one part of this important new resource, and that they have all benefitted from advancing technology. He defined this commodity as “any methane not trapped in a porous, permeable, buoyancy-driven system.”

What are the characteristics of these unconventional reservoirs? They are extremely variable. The methane within them is not freely dispersed and they have low or heterogeneous permeability. The source rock and the reservoir are closely related, and these resources represent large but low-concentration resources. They have unusual pressure regimes, and in many cases they represent a lower-quality version of conventional reservoirs. In short, they are more challenging to extract – a state of affairs that can best be resolved with evolving technology, as the story of shale gas amply illustrates.

If Nobody Hears a Blowout, Did it Really Happen?

Canada’s worst-ever blowout wasn’t a celebrity, and despite the passage of more than a decade the regulator has never formally investigated the event. Is that a good thing?

This article appears in the July issue of Oilweek

By Peter McKenzie-Brown

Klua d-27-J blew out near Fort Nelson BC. No neighbours were under threat, and the blowout took place in the sticks as most Canadians were getting ready for Christmas. No one was injured and, except for an incinerated rig, there was no damage to property. The media didn’t get wind of the disaster, so Klua was relegated to the world of “incidents.”

The blowout began on December 6, 1999 and took 12 days to shut in. But what an incident it was! Chairman Mike Miller of Safety Boss was part of a team of petroleum industry experts who prepared an important paper on Klua for a conference in Texas two years later. “Eyewitnesses reported that the drill string was lowered the last fraction of a meter with no resistance,” the paper says, “as if the bit had entered an underground cavern….” Then all hell broke loose.

According to Miller, at its peak the well spewed an estimated 250 million cubic feet of natural gas per day plus 5,000 barrels of condensate and 45,000 barrels of salt water. After ten days, crews ignited the well, which was flowing mildly sour gas. After pulling the incinerated substructure of the rig from the well, the hole was shut in and a control BOP installed.

When Oilweek recently contacted BC’s Oil and Gas Commission (OGC) for the formal report on this blowout, there was none. The Ministry of Environment would lead clean-up efforts, but otherwise the file is still open.

It’s a Matter of Safety

With oil leaking in the Gulf of Mexico, Canada is well-positioned to deal with the heightened risks - and reap the bountiful rewards - of frontier exploration.

Photo: Chevron Canada, which is drilling the ultra-deepwater Lona O-55 well in the Orphan Basin off Newfoundland with the Stena Carron Drillship, must meet several new requirements stemming from the Deepwater Horizon tragedy.

This article appears in the July issue of Oilweek.

By Peter McKenzie-Brown

As the United States administration and BP plc struggled to deal with what could turn out to be the largest-ever offshore oil spill, the Canadian oil and gas industry could look back in admiration at a frontier drilling history that has been relatively free of stains.

Oil and gas continues to be pumped from fields off the East Coast. Crude oil has been produced and shipped from the Arctic Islands. And natural gas from the Mackenzie Delta region is poised to supply southern markets, pending completion of a long-awaited natural gas pipeline from Inuvik. And in the Queen Charlotte basin, off the coast of British Columbia, where a moratorium has barred drilling since 1971, there lies a “new, rich petroleum province waiting to be explored,” says widely-respected petroleum geologist Henry Lyatsky.

He has been actively promoting lifting the moratorium even while the media were buzzing about the Gulf of Mexico blowout, believes there are excellent prospects in Canada’s west coast basins. Opening them up for drilling would reward the industry for decades of nearly incident-free frontier exploration.

Those sentiments would alarm most people outside the oilpatch, and they would alarm Canadian environmental activists to the point of apoplexy. That, however, is exactly the point: There is widespread concern around Canada that rapid growth in the petroleum sector would pose environment, health and safety (EHS) dangers. Those concerns illustrate how profoundly EHS has become part of our national DNA. And that is a very good thing.

The Three-legged Stool
The EHS stool has three legs: customs and social attitudes; regulatory and industrial codes; technical skills and operating environments. If the legs aren’t the same length, the stool wobbles. Since the three legs of the Canadian stool are level and strong, there are good reasons to encourage the industry to reach out to new operating environments.

Consider reality in much of the developing world, for example. “We do a lot of work out of Third World countries where clearly life is cheaper,” says Mike Miller, the chairman of Calgary-based Safety Boss Inc. “We were doing safety management on a huge construction project in Iran, and we just had a hell of a time to get people on board with it. One of the comments we heard was that if they killed someone it would just cost fifteen hundred bucks. You’d take $1500 to the family and that would be the end of it. So how much money are you going to spend on safety? Our contract was about enforcing Canadian safety standards, and we found so much resistance that at the end of the day we just said ‘This isn’t going to work, guys, because you aren’t going to stand behind us.’” In the end, Safety Boss got out of its contract.

Miller’s example illustrates the social attitude leg of the stool in much of the Third World. By contrast, in Canada the legal resources applied to safety and safe working environments are huge. Apart from representing personal tragedy, injury and loss of life are expensive propositions.

On the matter of the second leg of the stool, regulation, rich countries like Canada are increasingly focused on stringent EHS rules. The Canadian experience illustrates how regulation has saturated public opinion so deeply that environment, health and safety have become essential parts of the social fabric. According to Dale Dusterhoft, the chief executive officer of well service company Trican, there is a “continued focus on safety, environment and hazard issues and it comes from all levels, it comes from government, it comes from our customers who are the oil companies, it comes from the public at large and it comes internally from within the service industry. It now affects everything we do, and it is helping us make real progress.”

Operating environments represent the third leg of the stool, and they reflect the industry’s collective experience. The sector has a wealth of experience in the Western Canada Basin and is increasingly knowledgeable about the frontiers. The industry’s technical knowledge and skill-sets are formidable.

Safety Costs
Although serious industrial incidents have become rare, as long as there is an oil industry there will probably be kicks and blowouts. The story of Canada’s oil patch is full of these events, some of which have become legend: Royalite #4 at Turner Valley (1924); Atlantic Leduc #3 (1948); Amoco’s second sour gas blowout at Lodgepole (1982-83). The most blowout-prone exploration program in Canadian history was probably Panarctic’s 1969-70 effort in the High Arctic. Of 17 holes, two were spectacular gas blowouts and three were relief wells drilled to bring those blowouts under control.

To some extent because of the disasters of its cowboy years, Canada’s safety record is now excellent– especially since the high-profile Lodgepole event. In years of high drilling activity the industry now sinks three times as many wells as it did in ’82 and drills four times as many metres, yet blowout rates have substantially declined. In 2008, for example, the ERCB recorded 0.118 blowouts per 1,000 non-abandoned wells.

This partly reflects technological advance. “Almost all blowouts occur because of human error,” says Mike Miller of Safety Boss. “Fewer than 5% occur because of corrosion. It’s almost always when there’s a rig over the hole – whether it’s a drilling rig, a service rig or a snubbing unit. That’s where the human error takes place. Today we can put holes down in half to a quarter of the time it used to take so there’s less exposure of time to risk. That’s one reason we have fewer blowouts: we can drill wells so much faster.”

Miller also commends the ERCB’s strict regulations for sour gas drilling. “We now classify wells with significant sour gas content as critical wells, for which a whole new set of rules apply, including the requirement for emergency response plans. That’s made a huge difference.” So big, reports the Energy Resources Conservation Board’s Bob Cullan, that “there hasn’t been a single sour gas blowout since Lodgepole. That’s because we have the toughest sour gas drilling regulations in the world.”

The cost of safety is huge, and it has meant big changes in operating procedures. Mike Miller describes dramatic changes in the safety business since his father founded the company. “People (doing safety turnarounds at gas plants) now have fall-arrest equipment. They don’t do anything without fire protection and breathing air equipment. A friend of mine tells me that at the plant he works at, the safety bill used to be $20,000. Now it’s like $300,000 to $400,000. Every time someone goes into a vessel someone has to be there to watch. They may need to have specialized safety equipment or even specially trained personnel to watch that person in the vessel.”

He adds, “I appreciate the safer work environment, but the paperwork can be simply overwhelming. Now on blowouts we have to take a safety certified officer, and their job is simply to do the safety recording – to record every detail of the safety meetings we have. ‘We met at such-and-such a time, these are the hazards we discussed, people have to wear such-and-such protection equipment, here’s what we said and did.’”

To put costs in perspective it is worth noting that, according to an ERCB report, the direct costs of the 1982 Lodgepole disaster (lost production, lost drilling rig, operations and remediation) totalled $200 million. In a technical presentation nearly ten years ago, Mike Miller estimated that indirect costs – more stringent critical sour gas well procedures, equipment and emergency response planning, which can amount to a quarter to a half million dollars for a deep test – had been in the order of $1 billion. The cost of EHS is high, but Canadians are clearly prepared to pay it.

So is Canadian business. Chief executive officer Dale Dusterhoft of Trican, which is a key player in hydraulic well fraccing, describes the safety issues his employees face as long-distance driving (often over rough terrain); controlling high-pressures and chemicals; and working with moving parts and equipment. “Whenever you have those elements, you have safety issues,” he says. While he acknowledges that there is more paperwork than ten years ago, he says “It’s just part of the process. It doesn’t hinder our operations. We have a safety meeting prior to each job, and we have to document every one. What’s more, every individual there has to sign off that they were in attendance and heard it and understood it. But these are just good business practices. They take a bit more time, but they save money in the long run because you don’t have as many incidents.”

High Arctic
Canada’s early experience in the High Arctic – a 17-well drilling program that included three relief wells to control two major blowouts – illustrates how bad things can be when you don’t properly prepare for drilling in new exploration territory. The stool becomes wobbly, and the risk of an uncontrolled release of hydrocarbons – the fancy phrase for blowout – becomes greater.

In that context consider that the EHS stool is shaky in most Third World countries, yet there are big increases in deep water drilling off the shores of Africa, Brazil, China and India. “Aside from the oil sands,” ARC Energy’s Peter Tertzakian pointed out in a recent research note, “offshore drilling is where most of the world’s incremental oil barrels now come from, and it’s those higher-cost marginal barrels that set price. Indeed, a large fraction of the world’s growing oil needs since the early 1990s has come from the discovery of new, deep offshore reservoirs.” In North America, much of that oil has come from the American sector of the Gulf of Mexico.

Notwithstanding the BP-operated Macondo well disaster, it is rich-world companies that are best suited to drilling the world’s offshore petroleum basins. Because of our national attitudes and far-flung technical expertise, environment, health and safety are well served when Canada-based companies drill offshore fields. This reality applies as much to basins in Canada as to those in the Third World.

The Beaufort Sea and the East Coast Offshore
In Canada’s Beaufort and East Coast basins there have been important EHS developments in recent months.

Going to the ends of the earth is nothing new for the Canadian oil and gas industry. Beginning in 1976, drilling expeditions in the Beaufort Sea were innovative and daring and continued for nearly a decade. The wells were in shallow water, however – often using equipment that sat on the sea floor.

Last fall the National Energy Board began a safety inquiry in anticipation of a revival of drilling in the Beaufort Sea. The review was triggered by a proposal from Imperial and Exxon Mobil to start deeper Beaufort drilling, using a new vessel built on the scale of a battleship. The Board is investigating serious concerns about opening up deeper northern waters for drilling. The previous generation of regulations assumed that in the event of a blowout the operator could drill a relief well in the same season.

The Board began developing its new regulatory approach because the Arctic work season is too short to follow the old rules for the next wave of bigger wells. After the Macondo disaster began, the Board announced that it would review Arctic drilling requirements in light of findings from the American inquiries into that event. “We need to learn from what happened in the Gulf,” NEB Chair Gaétan Caron said in a statement. “The information taken from this unfortunate situation will enhance our safety and environmental oversight.” The regulator is making sure all three legs of the EHS stool are the right size for deep Beaufort drilling.

Off the east coast, the Gulf debacle created consternation for a different reason: a new, deep well was being spudded. In May, Chevron began drilling Canada’s deepest offshore oil well 430 kilometres northeast of St. John’s in the offshore Orphan Basin in the North Atlantic. Lona 0-55 was spudded in 2,500 metres of water (compared to Macondo’s 1,500 metres). Despite political calls for postponement because of the risk of an ultra-deep-water blowout, Newfoundland defended the project as critical to its economic development. The gist of the government’s argument was that oil is too crucial to the economy to call off exploration. That sounds quite a bit like damning with faint praise.

In response to public criticism, the government of Newfoundland appointed master mariner Mark Turner, an expert in marine safety and environmental management, to review the province’s ability to prevent and respond to an offshore oil spill.

It isn’t surprising that environmentalists and the political opposition sounded their respective horns on the remote prospect of a North Atlantic blowout. Serious offshore oil blowouts always attract attention, and rightly so. Injuries and fatalities are more common. They pollute, they’re hard to clean up and contamination can last for years. When dispersants are appropriate at all, they are the least bad of the available tools. And offshore oil blowouts have a disproportionate impact on wildlife: a deer can walk past a puddle of oil, but fish, whales and seals have nowhere else to go.

However, crucial facts were lost in the conversation about Lona O-55. One is that there has never been a crude oil blowout offshore Canada. Another is that only hundreds of wells have been drilled in Canada’s vast east coast, compared to tens of thousands in the much smaller US segment of the Gulf. Also lost in the debate is that all Canadian offshore wells have recently become governed by a more robust regulatory regime – one which offers greater EHS flexibility as a carrot, but bigger sticks for those who fail to perform. That means better safety and environmental protection rather than less, as the knee-jerk critics protest.

The new rules governing offshore drilling were posted in the Canada Gazette last December, and took effect at the beginning of this year. They are performance-based rather than prescriptive regulations, and the industry certainly believes that is a good thing.

According to Patrick Delaney of the Petroleum Services Association of Canada, the trend in regulation is undergoing a fundamental shift to performance-based regulation from prescriptive rules. As he explains, under the new approach the regulator essentially says, “The journey is from A to Z” – Z being a plan which meets the regulator’s EH&S goals. “We aren’t going to tell you how to get there. But before you start it’s up to you to prove that you can do it safely. This is a safer approach.”

For offshore operators, the days are now over when agencies of government specify the safety equipment the industry should use. “A lot of governments are making this shift,” adds Delaney. “Alberta recently announced that it is doing a complete review of its regulations, and that it will move away from prescriptive to performance-based regulation.”

Paul Barnes, who is Atlantic Canada manager for the Canadian Association of Petroleum Producers, is another advocate of performance-based regulation. It’s more “modern,” he says. Britain, Norway, Australia – all the advanced countries with offshore petroleum operations are adopting it. “It is part of a robust regulatory system in Canada,” he adds. “We have a strong track record of safety and environmental performance. Canada needs energy and the world needs energy, and oil’s going to be a big part of the energy mix for a long time to come. Let’s get on with it.”

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.

Team of Rivals

As executive director of the Small Explorers and Producers Association of Canada, Gary Leach leads Canada's "Silicon Valley of oil"

This article appears in the February 2010 issue of Oilweek.

By Peter McKenzie-Brown

A year ago, Stan Odut was chairman of the Small Explorers and Producers Association of Canada (SEPAC), and he was deeply worried about the industry’s immediate future. “The sources of capital for the junior sector are equity, debt and cash flow,” he said, “but many companies are already mired in debt and credit lines are being pulled. You can’t get additional debt coverage. You can’t raise any equity because there is no reason for investors to put money into the energy business right now (because of collapsing commodity prices). And governments (provincially in particular) have strangled cash flow. So help me with the equation: you’ve got to get one of those factors to change to get the business going again.”

In the last year, what has changed? I put the question to Gary Leach, SEPAC’s executive director. He describes a cautious sense of optimism within the junior sector of Canada’s petroleum industry. There’s been a strong recovery in oil prices, for example, although gas prices are still languishing. “In recent months equity markets have been more supportive of the industry,” he adds, although they have been “selective”. They are targeting companies with “strong management, in certain commodity niches. But there is no tide that is lifting all boats.” Bank credit is still a problem for some companies; many are carrying a lot of debt, and lower commodity prices have reduced the value of their assets in the ground. Technically, this is known as a double-whammy.

On the positive side, “Banks have tried to be nimble and flexible. They don’t want to cause a lot of financial wreckage in the junior and midcap sector. A lot of the equity raised in recent months has been used to reduce debt, so things are improving.” However, he cautions, “If we don’t see a sustained rebound in gas prices in 2010, that may change.”

The Gas Story
Gary Leach describes himself as a “pure prairie product”. He was born in Manitoba, raised in Alberta and received post-secondary education (including a law degree) at the University of Saskatchewan. He spent much of his strictly legal career putting together international joint ventures, petroleum production sharing agreements, and international financing loans with multilateral institutions such as the World Bank and the European Bank for Reconstruction and Development.

He joined Calgary-based Canadian Fracmaster in 1995 and stayed with the business after it was acquired by BJ Services Company, the Houston-based petroleum equipment and services giant. His background in down-hole completions is a notable asset for a spokesman in an industry being transformed by horizontal drilling and new fraccing technologies. Soft-spoken and articulate, Leach joined SEPAC – the trade association for 350 small oil companies – in 2006.

We began our discussion with the natural gas story. At time of writing, gas prices are sitting well below their ten-year average. Where are those prices headed? “I think right now there’s possibly a larger gap in opinions about where gas prices are going than any time I can remember,” Leach says. “There are people who say the potential international demand (for gas) has barely been touched, so prices should go up. Others talk about the huge international supply potential, and they see things the other way.” Perhaps remembering the adage that predictions are especially perilous when they pertain to the future, he says “We are never going to get out of these swings in gas prices. I think there are going to continue to be big swings in the gas market. I don’t think anyone can accurately forecast gas prices beyond a couple of quarters.”

“For companies carrying a lot of gas assets on their balance sheets, it’s not a great time to be selling. “There are going to be a lot of assets put on the market. A lot of big companies” – he mentions Talisman, EnCana and Suncor – “are talking about moving conventional gas reserves off their balance sheets. The lowest cost gas resources are the ones they are going to pursue, and those resources are now shale gas resources.”

Since gas-price volatility is a fact of life, he says, “The low-cost suppliers are the ones that are going to do best. Companies have to learn how to drive down their costs.” For the junior sector, which has a lot of conventional gas on the books, the outlook is particularly uncertain. “The leading shale gas resource in western Canada is in a place that’s so remote and so expensive that mostly big players can participate. However, as the technologies and the infrastructure are developed, the smaller players will get in.”

Behind the Curve
When you ask Leach about Alberta’s place in western Canada’s industry, he is oddly ambivalent. For example, on the matter of shale gas he says, “If we were further along the curve in Alberta in developing shale gas resources, the smaller players would be developing them. But Alberta’s industry is behind the curve.”

He notes that both British Columbia and Saskatchewan long ago introduced important incentives for the industry, but that those policy environments didn’t spur high levels of petroleum sector growth until the technological environment changed in recent years. For example, Saskatchewan’s “Bakken field has been known for years. We used to just drill right through it. However, it is only recent that the technologies of horizontal well completions and multistage fracturing” – the technologies that led to the shale gas revolution – “made that reservoir viable.”

Alberta, of course, is quite different from either of those provinces. “The (Western Canada Sedimentary) Basin covers the province from north to south. We have every conceivable hydrocarbon opportunity here. There’s a lot of excitement about using those technologies to improve production from formations in Alberta that are well past their glory days – the Viking formation, the Cardium formation. A lot of companies are looking at targeting oil in these formations, but using horizontal wells and multistage fractures.” Leach thinks the industry will soon successfully use these methods to increase oil recovery in Alberta.

What is SEPAC’s single biggest challenge? Here his message is particularly striking. “We have to help policy makers and politicians understand what a tremendously exciting, dynamic, vibrant group of junior and mid-cap companies we have in Canada. Almost half the world’s publically traded oil companies are here in Calgary. It’s a remarkable statistic. It’s the closest thing to a Silicon Valley type business culture and industry cluster we in Canada have ever developed. It’s emerged on its own without government help. But over the years, we have had all these companies competing with each other. Hundreds and hundreds of companies are competing with each other for land, for resources, for capital. They have a tremendous publically accessible database that puts small companies on an equal footing with big players. It’s the most unique oil industry in the world, and Canada’s most successful business story. We need policy-makers to understand that story, so they don’t see the industry as just eight or ten companies. Let’s see the big picture, and not do things to harm it. This industry is amazing. We don’t want to lose it. We want to nurture it. It’s a great incubator of new ideas.”

Leach sees the Alberta government’s recent adjustments to the royalty changes of two years ago as a SEPAC success. “Both times (Premier) Stelmach came out with revisions to the royalty regime, he specifically mentioned that he wanted to help Alberta’s junior petroleum sector. The Alberta incentives brought additional cash flow, reduced costs, drew some investment into Alberta that would. They helped, but they were not the complete answer. They couldn’t help everybody.”

SEPAC is now working with other industry associations, the financial sector and others in developing a study of investment competitiveness within the province, which will be complete in the New Year. The idea is to answer the question, “Compared to other investment places, how does Alberta rate?” The provincial government will then have to take all that information and decide on new policies. We think if the province can set itself up as one of the world’s best places to invest, its future will be bright.” Citing a report from a large bank, he points out that about 60 per cent of the world’s investible oil resources are here in Alberta. Big international oil companies have been boxed into smaller and smaller bits of the world. This is one of the few places in the world where companies can book meaningful reserves additions.”

Moving Ahead
I’m always interested in the responses of senior people in the patch to the issue of peak oil, so I put the question to Gary Leach. His response is forceful and direct. “I think we’re near peak cheap oil. I think we’re near peak easily accessible oil. But the amount of oil in the world is enormous. The biggest problem to developing oil has to do with policy restrictions – off-limits restrictions on resource development. The US has huge oil shale resources, for example, but they are politically inaccessible.” Working with their client national oil companies, oil-rich countries have put resource development off limits to private sector oil companies. He mentions Venezuela’s Orinoco ultra heavy oil belt, Alberta’s oilsands, the vast heavy oil deposits in Russia, then cites the old gag that the Stone Age didn’t end because we ran out of stones.

He’s now just warming up. “The petroleum age won’t end because we run out of petroleum. Western European countries are consuming less oil than they did 30 years ago, and the United States is consuming less than it did in 2007. The petroleum age may end in a gentle decline because some of the advanced countries begin to move away from (oil). I don’t think it will end with apocalyptic change. Price signals will put a limit on demand.”

I mention the often-cited rapid demand growth in China and India among developing countries and the rapid growth in OPEC countries like Venezuela, where consumer prices are greatly subsidized. “Rapidly growing countries like India and China are still poor countries,” he counters. “They can live with a price around today’s price (US$77 per barrel) but they cannot afford oil at $150-$200 per barrel. (If prices rise to those levels) there will have to be some kind of market response. Before 500 million Chinese own a car, they will be driving something that doesn’t rely on oil: Maybe electricity-fuelled vehicles charged from nuclear reactors.” Whatever those vehicles are, Leach has no doubt “there are going to be other factors on the demand side, the technology side, that will temper those straight-line graphs that say oil demand will outstrip oil supply and prices will skyrocket.”

Of course, a basic principle of free-market economics is that supply and demand must always be in balance. Neither does a world with global economic growth constrained by energy shortages sound reassuring. Indeed, the situation he is describing seems compatible with mainstream peak oil theory, so I wonder whether his arguments against worldwide economic destabilization have settled the issue. All the same, I have thoroughly enjoyed the discussion. We shift gears, moving to lighter topics.

Has he read any good books lately? Yes, he says. He reads a lot, and is now reading Team of Rivals: The Political Genius of Abraham Lincoln by Pulitzer Prize-winning historian Doris Kearns Goodwin. This thick book describes Abraham Lincoln’s leadership skills by focusing on his war cabinet, which included three of the political rivals he beat in the 1859 presidential campaign. According to Leach, “it was amazing how he turned these diverse people into a team during the most cataclysmic period of American history.”

For a guy with responsibility for managing SEPAC’s affairs and representing its views to government, the news media and the public, political genius may be just what the doctor ordered. Bear in mind that “nearly half of the world’s public oil companies are here in Calgary.” Within the modern petroleum age, those hundreds of companies have become a team of rivals for the global oil industry to reckon with.

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