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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Just a ‘FRAC’ away

New gas mega-wells threaten to strain contractor fleet

This article appears in the April 2009 issue of Alberta Oil magazine.

The graphic compares natural gas production from a conventional sandstone reservoir to fracced, unconventional production.

By Peter McKenzie-Brown

If unconventional natural gas is a revolution in the making, so are the services required to make it happen. Industry spending patterns are shifting, with much bigger investments now being poured into operations below the ground.

Traditional ways of doing business are changing. Multiple wells are drilled from single sites, known as “pads,” to tap the new gas target. The old oilfield rhythm of busy winters and quiet summers is also changing as work grows in the warm seasons.

Despite the economic downturn, there is even a hint of a gas counterpart to the former oil sands labor shortage in the air. There is a risk that in the near future Western Canada will find itself short of powerful hydraulic equipment needed to make the networks of underground channels that make unconventional gas deposits flow. This would be a blow to exploration and production companies, but possibly a considerable financial boon to service companies with the right stuff to do the rock fracturing, a field known as “fraccing” in the industry.

The specialty is a well stimulation technique which improves production from geological formations where natural flow is restricted. Hydraulic fracturing pushes a mix of water, sand and some soluble chemicals into well bores at high pressure, both to spread cracks across the formation and hold them open for gas and oil to flow.

Originally a simple operation, fraccing has evolved into a high industrial art that uses multi-stage techniques in horizontal wells, reports Dave Russum, geosciences vice-president for AJM Petroleum Consulting. “Between the heel [start] and the toe [end] of a horizontal well, you isolate an interval close to the toe and frac that region,” Russum says. “Then you move back towards the heel, isolate another interval and do another frac.”

The technique is a powerful production tool. “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 [poorly flowing] rock than you would ever be able to reach with a vertical well,” Russum says.

In the old 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. A well that requires so much work would likely have a horizontal reach of 3,000 metres or more.

Analyst Kevin Lo of FirstEnergy Capital Corp. estimates that fraccing just one of EnCana Corp.’s Horn River shale gas wells in northeastern British Columbia requires a crew equipped with more than 30,000 horsepower of compression. In Western Canada, there is perhaps 800,000 horsepower available.

“We do not believe that there will be sufficient capacity to perform all of the jobs necessary” if B.C.’s Horn River and Montney shale gas drilling hot spots grow, Lo says in a research note. He also worries about the heavy lifting required to deliver enough fraccing materials. Fracturing a single horizontal well in the new unconventional gas reservoirs can require up to two thousand tonnes of sand.

Dale Dusterhoft, a senior vice-president at Trican Well Service Ltd. describes FirstEnergy’s estimates of requirements for the new gas production as conservative. “Some of the Horn River wells require up to 45,000 horsepower of compression,” Dusterhoft reports. “With 10 holes per pad, you may have 40,000 horsepower tied up for 10 weeks.”

The Trican executive predicts, “There will be shortages of equipment when we get up to full development of the shales.” If it happens, the squeeze will be a plus for service companies like his, which will then charge premium day rates, but a worry for the gas producers in the region.

Environmentalists have voiced concern that fraccing chemicals may contaminate groundwater. But Dusterhoft says that, before wells are fracced, the formations are securely sealed away from potential fresh-water reservoirs.

Use of chemicals is also limited in the unconventional wells in northeastern B.C. “We only use a polymer as a friction reducer, and maybe something to stabilize the clays. Mostly we just run water and sand,” Dusterhoft says.

Fraccing’s goal is to create a web of flow channels. When the technique is completely successful, he says, all of the fractures connect with each other to provide maximum production, he says. “We like to say we can ‘farm’ the reservoir.”

Huge fraccing jobs in northeastern B.C. require vast logistical support. Each well can require 2,000 to 3,000 tonnes of fine-grained sand. Parades of trucks deliver vast harvests of ancient sand mined from fossil beaches, often from quarries in Saskatchewan. Such a project may require a 40-member crew, operating 20 or more hydraulic compression systems mounted on large fraccing trucks.

High volumes of water are also used. 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 contributed to the developing seasonal shift in the fraccing business. “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,” Dusterhoft reports.

Water is easier to handle in warmer weather. In the longer term, the changing work pattern will require upgrading to all-weather roads to Horn River and Montney. Until those improvements are completed, service companies have to leave equipment in the area during freeze-up.

The shift to unconventional gas occurred much more quickly than anyone expected, Dusterhoft says. Among numerous implications of the switch, an old barometer of industry health –the sheer number of wells drilled – is becoming obsolete.

The production change, while increasing oilfield work, is contributing to a reduction in the total number of Canadian wells being drilled. In 2008, nearly 40 per cent of the wells involved horizontal or directional drilling – twice the level of 10 years ago. For the first time, FirstEnergy Capital said in a recent research note, the number of horizontal wells across reservoirs will soon match the number directionally drilled at angles. Greater proportions of industry spending on wells are going into completion services like fraccing.

Unconventional gas operations are not cheap. Drilling costs are in the range of $5 million to $7 million per well at Horn River, and $4 million to $5 million at Montney. Fraccing costs are estimated to be $2 million to $3 million per well.

But the production profiles for these wells make them worth their costs. Each may produce 7.5 million cubic feet of gas per day in their first year. Production declines rapidly but typically levels off at around two million cubic feet per day then stays steady for years. When gas prices improve, the new wells will be cash registers.

In the Centre of the Storm

This article on SEPAC chairman Stan Odut appears in the April 2009 issue of Oilweek magazine; graphic from here.

By Peter McKenzie-Brown

Toward the end of a long and thoughtful interview, a smile flickers across Stan Odut’s face. The topic of his grandchildren has come up, and he brings out a photo of the four who are aged seven and older. Wearing Ukrainian dress, they are dancing at a multi-cultural festival in Calgary. A Chinese dragon dance takes place in the margin of the picture, suggesting the great diversity of today’s Alberta. His pride is palpable and infectious, and he’s probably thinking back on a life well lived.

Odut’s story is exactly contemporaneous with that of Canada’s modern energy era. Born in Germany just as Imperial’s Leduc #1 well ushered in Alberta’s post-war conventional oil age, his family migrated to “a very poor farm” near Dauphin, Manitoba, where he grew up. The new chairman of the Small Explorer’s and Producers Association of Canada (SEPAC) moved to Calgary after earning an engineering degree from the University of Manitoba in 1969. Forty years on, no one is prouder of his city or his province than Stan Odut.

As SEPAC chair he is the voice of junior oil, and he urges small companies to join the trade association. “Membership isn’t expensive, and SEPAC can help you get your voice heard by provincial and federal politicians.” With more than 450 members, the organization describes itself as representing “Canada’s oil and gas entrepreneurs” – a tag line the association has actually trademarked.

According to Odut, the small companies need to “press for revised regulations, cutbacks in bureaucracy and a more efficient industry.” He has strong views on the changes needed to return health to the juniors.

Background: His early career included stints with Hudson’s Bay Oil and Gas, Texas Gulf and Canterra Energy – larger companies that were eventually absorbed by acquisitors. After finding himself at Husky after its 1991 takeover of Canterra, he left that corporation and began working with smaller companies.

He was one of the founders of Del Roca Energy, which eventually sold out to Tusk Energy. Five years ago he formed privately-held Sifton Energy, which he serves as president and chief executive officer. Sifton has 80 shareholders, ten employees and daily production of 950 barrels of oil equivalent. Odut’s original exit strategy was to sell out to a trust “but now with the downturn, we’re struggling a bit to keep on going. There would be no advantage in going public, though. Public companies are so badly discounted that there would be a real disadvantage to doing that.”

Now he begins to address his key messages. “The sources of capital for the junior sector are equity, debt and cash flow,” he begins. But in today’s environment, “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. 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.”

Odut describes the economic situation as “dire”, and observes that it has built up over several years. The treatment of trusts has been a major contributor. Another has been the loss of the Alberta royalty tax credit. “Actions by provincial and federal government have debilitated our industry”, which is mostly headquartered in Alberta. The economic environment is becoming similar to that of the 1980s, when exploration and development collapsed, layoffs replaced hectic hiring, and Alberta’s rural areas found themselves with little work on the rigs or in oilfield construction. In both periods, the junior sector was hit particularly hard.

Just as westerners with long memories generally finger the National Energy Program as an important cause of decline in that earlier period, Odut places blame for the deteriorating situation on Alberta’s new royalty regime. “It has resulted in fewer jobs, less activity and less money in government coffers.” He acknowledges that it has been “more than the royalty regime that has killed activity…. It’s also been oil and gas prices – but those prices are the same in Saskatchewan and British Columbia” where activity is still relatively strong. In Odut’s view, Alberta’s new regime helped drive activity into the other western provinces.

“The Alberta advantage seems to have disappeared,” he laments. “You can see it in municipalities increasing taxes on infrastructure, the cost of obtaining surface leases or the new royalty system. Alberta’s bureaucracy now seems to be anti-development.” While he acknowledges that “there are land bargains out there,” he stresses that “you need cash to take advantage of them. And if I put on my Alberta resident’s hat, should I be happy that provincial (mineral rights) are being sold for a song?”

As this article goes to press, the Alberta government has promised measures that will provide relief for the juniors, and the government has agreed to consult with SEPAC and other trade associations. “My advice on help is the sooner the better,” says Odut. “We have already lost the winter drilling season. Now we have to concentrate on (getting activity going during) the summer drilling season.”

Incentives: Only two years ago, when oil prices dropped to $50 per barrel, there was no let-up in investment in Alberta. Yet last year, when average oil prices hit their all-time high, that changed. Why? Because investors no longer feel they can count on a stable regime in Alberta.

“Large companies are still going around the world and investing,” says Odut. “They know that one pass through (countries with immature petroleum basins) can give them a good short-term return. They are less concerned if the regime changes. (But Alberta) is not a one-pass-through basin. You need to know there will be a stable return over time.” After the recent changes in royalties, that certainty is no longer there.

Although Alberta is a mature basin, Odut is optimistic about its future. “Better than 35 per cent of the conventional oil resources are still there waiting to be recovered,” he says. Odut’s optimism about Alberta’s productive potential is qualified by deep skepticism about its exploratory potential. “Right now, only one (exploratory) well in seven is a decent well. I think there are still a lot of good opportunities in the conventional sector. The opportunities are in technology, because of improved recovery methods. We aren’t going to find a lot of great new fields, but we can get a lot of left-over barrels of oil using new technologies. We need incentives to do that.”

“The present regime,” he says, “penalizes you if you come up with a good well by increasing royalty rates from 35 percent max to 50 percent max”. While acknowledging that at present prices oil royalties are “at the bottom of the scale,” he stresses that the present system “penalizes horizontal wells, which reduce the industry’s environmental footprint. If you are successful, instead of having four 10-barrel-per-day wells, you could have a single horizontal well producing 100 barrels per day.” However, because the present regulations impose lower royalties on less-productive wells, “you shoot yourself in the foot by drilling (horizontally) under the existing regulations.”

At the end of last year, the Alberta government announced a 5-year window in which companies could apply the old royalty system to new wells. Stan Odut wasn’t impressed. “It doesn’t address the basic question of what you are going to drill with. You need debt, equity or cash flow to drill, and it really didn’t address any of those issues. Equity I can’t raise any, credit there isn’t any and governments are strangling cash flow.” The royalty regimes are better in BC and Saskatchewan, he says, “and BC is tweaking its system to make it even better. The biggest problem is here in Alberta.”

The outcome is that large companies have taken their cash flow and vacated the province, leaving it to the junior sector. Yet the junior companies have little to work with. To turn this around, he says, “You have to acknowledge that capital will flow to where it will get the best return. Our fiscal regime does not encourage the flow of capital into Alberta.”

What’s a government to do? Provincially, he suggests incentives for horizontal wells. Federally, he argues for changes in flow-through tax rules.

If Edmonton encouraged small companies to use horizontal wells, production would go up and the environmental footprint would go down. “You need to encourage investment in horizontal wells, as Saskatchewan does. They have a royalty holiday for horizontal wells – you pay a very small royalty on the first 100,000 barrels or so. That way the investor is able to recover his money before the government begins receiving its take.”

Ottawa, on the other hand, should take steps to expand flow-through investment. Under the present flow-through rules, companies can pass tax breaks associated with exploration directly to individual investors. The focus of that program, however, is exploration, the success of which is in decline. “Flow-through rules should (be changed to) enable companies to put flow-through money into development wells, where the risk is lower. (The federal government should) make larger sums available, so slightly larger companies could take advantage of it. This would encourage investment, and that investment would be used for drilling. Companies could choose whether they wanted to put money into exploratory drilling or development. It would give you much more cash flow.”

Peak Oil: Stan Odut is one of a growing contingent of oilmen now subscribing to the concept of peak oil – the notion that the planet’s maximum rate of oil extraction is at hand. After that point arrives, the rate of production will enter terminal decline. “I believe we probably aren’t going to see an increase on the supply side globally,” he says. “With the global economic situation there has been (crude oil) demand destruction, but I would add that there has also been supply destruction because drilling has been declining, producers are shutting in supply” and many large projects, world-wide, have gone on hold.

Prices are low because “right now oil is overbalanced on the supply side,” he says. “When things do recover, I think we are going to be in a really tight situation. The horizon might be shorter than many people predict. I think within the next five years – certainly within the next ten – we will meet a supply crunch probably like we have never seen before.”

“There’s a huge disconnect between developing world and developed world consumption,” he says. “Either we have to tap some alternative resources which we don’t really know about today, or many of us in the developed world are going to have to really cut down on our oil consumption. The developed world has to contract its consumption a lot.” This sounds ominous, and Stan Odut quickly adds that he doesn’t want to be a scare-monger.

“I’m getting a bit long in the tooth and I have an eye for what my grandchildren are going to face as we go down the road. I think they are going to be facing a different world from the one we are in today.”

The Great Pipeline Debate

This series of articles first appeared in the June, 2008 issue of Oilweek magazine.

By Peter McKenzie-Brown

The Minister of Everything

“If we have overstepped our powers, I make no apology for having done so,” said C.D. Howe to Parliament in 1953.

Howe was known for his gathering arrogance. The second most powerful politician in Canada, he ran much of the government and was dubbed “Minister of Everything” by supporters and opponents alike. A man of extraordinary ability and energy, he served in Parliament from 1935 until 1957. His downfall was a Parliamentary wrangle known to history as the Great Pipeline Debate, which took him and the government he served down to a surprise defeat. Howe’s performance effectively ended a quarter-century of Liberal rule in Ottawa.

Half a century later, it is difficult to imagine the emotions aroused by a pipeline construction proposal. At one time, though, Trans-Canada Pipelines was the focus of a divisive national debate.

After twice rejecting applications, Alberta had granted gas export permits in 1953. Pipelines were now essential to get that gas to market, but efforts to develop the Trans-Canada line to Central Canadian markets encountered a Pandora’s Box of problems. These began with the fact that the project was primarily financed by American interests – merchant bankers Lehman Brothers and a covey of oilmen, including the legendary Texan, Clint Murchison.

Despite the strength of its board, TCPL had difficulties from the beginning. There were several competing proposals to move gas east from Alberta; because of the uncertainty, Alberta producers would not sign supply contracts, and distributors would not sign purchase contracts. TCPL’s original route, which would have taken the project through US territory, faced the fierce opposition of Canadian nationalism. When Ottawa rerouted the line through the rugged Precambrian Shield, which covers most of Canada north and east of Winnipeg, private-sector financiers balked at the additional costs.

Other trouble came from across the border. An association of coal producers called the proposal “a brazen attempt to force the American people to subsidize a costly and unnecessary pipeline across Canada.” Even the Federal Power Commission, whose approval TCPL needed to sell gas into the United States, got into the fray. The American regulator was skeptical of the project's financing and unimpressed with Alberta’s reserves.

Nonplussed, Howe used his considerable political skills to drive the project forward. “This is no ordinary project, but the largest capacity and longest pipeline ever undertaken,” he said. “The project is comparable in importance to our transcontinental railroads. In my opinion, if the project is allowed to collapse, the use of western gas in eastern Canada will be a dead issue for all time.”

Howe virtually compelled TCPL and its competitors to merge and put a bill before Parliament to create a Crown corporation to build and own the Canadian Shield portion of the line, leasing it back to TCPL. During the Great Pipeline debate in 1956, Howe tried to force the legislation through Parliament by using closure at every stage. This tactic annoyed the opposition parties, who objected strenuously, delayed its passage, and turned the pipeline into a major political issue. The use of closure created a furore which spilled out of Parliament into the press, and led to the government's defeat at the polls the following year.

After his electoral defeat, Howe said simply, “We were too old. I was too old. I didn’t have the patience any more that it takes to deal with Parliament. You know, over a year ago I went to the Prime Minister (St. Laurent) and suggested that he and I ought to retire. He wouldn’t hear of it – I guess he’d decided to live forever, and everything was to go on as it was going. So he said nonsense, we must stay. So we did – and look what happened.” Clarence Decatur Howe died on New Year’s Eve, 1960, aged 75.

The Wildcatter
Himself the son of a prospector, Francis Murray Patrick McMahon (known as Frank to everyone but the baptising priest) became a hard-rock driller in the 1920s. The following decade he shifted to wildcatting – unsuccessfully in BC’s Flathead Valley, then in Alberta.

Pacific Petroleums is the oil company he is most closely associated with. It originated in 1930 through the merger of two tiny Turner Valley-based companies, one of which McMahon had founded. In the early days, McMahon’s involvement with the company was tenuous – he wasn’t on the board, and an economy drive during the Second World War relieved him of his job as operations manager. After the war he rose to the top, however, and imbued the company with vision and energy. So successful did the company become that in 1979 Petro-Canada acquired it as a fully integrated oil company for the then-record purchase price of $1.5 billion.

McMahon was successful in Alberta but – always the maverick – turned his attention to exploration in his native British Columbia just after the war. He coaxed the government to open up lands in the Peace River area for development. First in the queue, in August 1947, he acquired permits #1-3 for a consortium he had assembled, thus obtaining exploration rights on 750,000 acres. His 1951 discovery of the Fort St. John gas field rewarded this gamble and contributed to the next stage in his remarkable career.

Not until the 1950s did natural gas development become a major continental enterprise, and early in those years there was a great deal of competition to build the lines that would eventually create North America’s fundamental pipeline grid. Frank McMahon was a fierce competitor in both of Canada’s major controversies.

With an eye to creating a gas pipeline to BC’s lower mainland and the Pacific Northwest, he incorporated Westcoast Transmission in 1949. His original plan was to export Alberta gas along this line. He encountered delays getting export licenses, however, so he simplified matters by first negotiating with the government of British Columbia for permits to transport and export natural gas from the growing reserves being discovered in the Peace.

Westcoast won final approvals from British Columbia, federal regulators and America’s Federal Power Commission in 1955. Within two years, the company had constructed a $170-million, 680-mile pipeline from BC’s Peace River area. The line delivered gas to some cities in the BC interior and to the Lower Mainland, and exported gas to the Pacific Northwest. In October, 1957, an American reporter provided a vivid description of the opening ceremonies. “At the turn of a valve,” he wrote, “gas roared through the 30-inch pipe heading south for Vancouver, and a gas flame leaped symbolically skyward. Said McMahon, ‘So far, (natural gas) has all been going out (of the United States). Now it will start coming in.’”

The huge American market tantalized McMahon, and around the time of the Great Pipeline Debate he also put together one of the bids competing with Trans-Canada. Audacious to a fault, in March 1956 he walked into the Ottawa office of C.D. Howe and presented his alternative. He would construct a pipeline from Alberta to Montreal, following an all-Canadian route. It would be 70% Canadian owned, and it would require no financial assistance from government. Furthermore, he would “personally post with the government $500,000 performance cash to complete the project by 1958, subject only to being able to obtain necessary materials.” The key to this financial alchemy was a bigger line and larger exports to the US market.

Although in some respects the proposal seems clearly superior to the TCPL proposal, Howe wanted nothing to do with it. He wouldn’t even discuss it. McMahon let news of this rejection out, however. As the clamour of the Great Pipeline Debate grew, news about this proposal contributed greatly to the din, and to the defeat of the federal government.

Born in 1902, Frank McMahon died in 1986.

The High Priest
Eldon Tanner was a politician (16 years in Alberta’s legislature) of great skill, and a man of impeccable integrity. The Minister of Lands and Mines in 1947, he turned the valve to officially start oil flowing from Leduc. In 1952 he retired from politics, moving to Calgary to head a small company called Merrill Petroleums. Reflecting on his years in politics, he believed his political legacies were fiscal responsibility, efficient administration in government and the conservation of Alberta’s natural resources.

In those days, the meaning of “resource conservation” was quite different from our meaning today. It meant limiting gas exports to those in excess of the province’s 30-year needs. This calculation consumed the Oil and Gas Conservation Board and helped delay the selection of a line to eastern Canada and points south. In 1954, premier Manning resolved the stalemate by informing C.D. Howe that Alberta would only give permits to one company to export gas eastward.

At that time only two serious contenders were left at the bargaining table: US-owned Trans-Canada Pipelines and Western Pipe Lines. Western was a Canadian company with an economical and realistic plan. However, to be profitable it needed more foreign exports than TCPL – an insurmountable political handicap. In the end a shotgun wedding married the two, with Howe’s finger firmly on the trigger.

The merged company needed a president, and in 1954 Tanner was asked to serve. Initially, he refused because the company wanted to host its head office in Toronto. TCPL was undeterred. According to Tanner, “The next day I received a call from Premier Manning. He said, ‘Tanner, these people want you to do this job and I think it is your opportunity to be of great service to your country’....Well, I got a call the very next day from Mr. C.D. Howe, who was the Senior Minister of the Canadian Government, telling me he wanted me to take the job. He was very complimentary and said that I was the only man who could hold these two companies together. Flattery, you know, will get you anything. I did feel that when the two asked me to do it, I should accept.”

The company agreed to have its head office in Calgary, and Tanner brought political savvy, business acumen and interpersonal skills to the job. According to the leading historian of TCPL, however, he “probably did not play as important a role in Trans-Canada’s survival and ultimate success as half a dozen of the original sponsors on the board. Nor did his ability or style ever qualify him to be a member of the power elite of Canadian business and public life. But his quiet diplomacy was to be important both to the morale of the employees and for relations with a great range of persons outside the company.”

With their ascendancy to power after the Great Pipeline Debate, the Diefenbaker Conservatives appointed a federal commission to study Canadian energy export policy. Its report suggested that Tanner might have acted improperly by exercising stock options in a company that received federal financing. Embarrassed, he relinquished TCPL’s presidency in 1957 and chairmanship of its board the following year.

Public libraries file Nathan Eldon Tanner’s official biography among religious books, and the last word on the man needs to go to his religion. A devout Mormon, after Trans-Canada he dedicated his life (he died in 1982, age 84) to the church. Indeed, for his last two decades he was President of the Quorum of the Twelve Apostles – the highest religious role a Mormon can aspire to.

The Battery and the Charger

This article originated here.

B.C. and Alberta need each other’s power

By Martin Merritt
About 14 years ago, Alberta began to restructure its electrical system, and it’s been quite a journey to the market-based system we have today. Most people don’t understand what an important role British Columbia’s government-owned system plays in our market. From my perspective as head of the agency charged with making sure Alberta’s electricity markets are fair, efficient and competitive, I see our relationship with B.C. as mutually rewarding.

Alberta’s electricity market includes a host of buyers and sellers. At one end of the spectrum are small consumers like you and me who depend on electricity in our homes; on the other are huge industrial consumers mining the oil sands, operating pipelines and milling forest products.

On the supply side, generators range from wind farms east of Crowsnest Pass to huge coal-fired plants near Edmonton. The diversity of Alberta’s electricity supply has increased substantially. We now have more technology, fuels, locations, ownership, and maintenance diversity than in the past. Our system’s reliability, its cost structure and Alberta’s collective exposure to various risks are well-served by this diversity.

Less known is that Alberta and British Columbia are buyers and sellers of each other’s power. We Albertans buy from B.C. during our peak hours. B.C. buys from Alberta during the night. This arrangement confers tremendous benefits on both provinces.

There’s a misconception among some Albertans that the relationship between Alberta and B.C. is parasitic: we’re the host and they’re the parasite. According to this argument, our western neighbour is pulling a fast one by preying on a weakness in our market design.

The facts do not support those ideas. The power-exchanging relationship between the two provinces is symbiotic, and the symbiosis is based on geography. Alberta has lots of coal and natural gas, while B.C. has big mountains, long valleys and lots of rain. It makes perfect sense that B.C. based its system on hydroelectric power while we constructed one that primarily burns hydrocarbons. Because of these basic realities, over the years the two provinces have evolved a mutually beneficial relationship – somewhat like a battery and a charger.

The power we get from next door perfectly complements our own – and vice-versa. Alberta’s electrical demand varies substantially throughout the day and across the seasons. When we are fixing supper and using our home appliances our demand for power goes up, as it does during heat waves and cold snaps. It tapers off during spring and fall. Like other mechanical devices, generators fail unexpectedly from time to time. If they are wind-powered, their output is quite variable and difficult to predict.

Whether for reasons of temporary high demand, short supply or both, we’re fortunate to be able to buy electricity from our neighbour. Last year B.C. sent us as much as 465 megawatts for brief periods. What we have in B.C. is a standby generator that can provide us with significant amounts of reliable power on short notice.

Could Alberta make do without B.C.’s hydropower? Sure, by over-building generation capacity in the province. It’s worth noting that we don’t just buy power from B.C. because we can’t supply it ourselves. We buy it anytime that they are willing to supply it for less than it costs in Alberta. Every hour of the year Alberta generators have to compete with B.C. for the right to serve Albertans. If we had built a generator of our own just to supply the power that B.C.’s government-owned generators sent us in 2007, it would have run only 742 hours over the course of the year, or just 8 per cent of the time. This would make as much sense as buying an additional family car to avoid the odd cab fare.

Like cars, generators have costs that are largely fixed. Investing over $500 million plus ongoing maintenance in a generator that would run infrequently would be a very poor use of capital in any market. At the end of the day such power would cost far more than the power we buy from B.C.

Mutual self-interest has evolved a smarter way. We sell electricity to British Columbia at night when we have surplus capacity, so they can recharge their hydroelectric reservoirs. We buy electricity from B.C. at suppertime or on cold days or when a larger-than-normal number of our own generators are down for maintenance.

Our neighbour buys electricity from us when we least need it, and provides it to us when we need it most. This enables both provinces to make optimal use of their generating and storage capacity and use assets more efficiently. This keeps power prices lower in both provinces than they would otherwise be.

This arrangement has evolved naturally because of the physical differences between our electrical systems. It depends very little on differences in our market models. Yes, the market models are different. Alberta has developed a system in which markets determine prices and the pace of investment, while B.C. has a regulated, government-owned power system. British Columbians are justifiably proud of their hydroelectric system, although today’s B.C. taxpayers do not appear as keen to invest in publicly funded generation as their parents were. As a result, B.C. has become a net electricity importer. Many Albertans might be surprised to learn that in 2007 we sold much more electricity to B.C. than we bought from them, though overall Alberta too was a slight net importer in 2007.

Despite the vast differences in our market designs and because of large differences in the mix of our generation assets, the electricity systems of Alberta and British Columbia enjoy a unique symbiotic relationship. The big battery next door provides a market for our night-time surplus and a peaking supply for our crunch periods. Combine this with an investment climate that has attracted a steady stream of investor-funded generation projects for the past ten years, and you have a system that has provided reliable, sustainable power to the most robust economy in the country.

Alberta’s Market Surveillance Administrator, Martin Merritt is head of an independent agency developed to ensure that the province’s electric markets operate in a fair, efficient and competitive fashion. The MSA also monitors the retail natural gas market.