Pushing South

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

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


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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


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

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

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

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

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

Taking Centre Stage

This article appears in the June 2008 Issue of Oilweek magazine.

By Peter McKenzie-Brown

At 10 o’clock in the morning of February 13, 1947, a group of dignitaries welcomed in the Canadian oil industry’s modern era. On that day Imperial Oil brought in its Leduc #1 discovery with fanfare, but the event was primarily of local interest. Internationally, only the American oil press paid heed.

The event that brought Alberta’s potential to the attention of the world came a year later. The occasion was the storied blowout at Atlantic Leduc #3. Here is the tale of that extraordinary event as seen through the eyes of Hugh Leiper – the last surviving crewman on the well. Twenty years old and at the beginning of a long and successful career, Leiper was derrickman on the rig as the adventure started.

His father worked in the small refinery at Turner Valley, which hosted Canada’s first major oilfield, so Leiper had lived with the industry from childhood. When the Second World War ended, the Turner Valley field was essentially dead from overproduction. “It had been ruined during the war,” says Leiper. “Jobs in drilling were not plentiful, to say the least. There were two rigs working in Wainright, one or two in Taber, Cantex had two working for California Standard and that was about the extent of the drilling industry at that time. Imperial had a rig of its own, the one they used at Leduc.”

After a year at Calgary’s Mount Royal College, Leiper couldn’t afford to continue studying petroleum technology. He signed on as a roughneck with Cantex in 1946 and moved to a new contractor, General Petroleums, a year later. “We were pretty lucky. We lived in camps. We were getting six bucks a day, but they deducted $1.50 for room and board. The steam rigs we used were cheap to operate; all you needed was water and fuel. But they were hard to tear down and move, and by 1949 they were gone. The new power rigs were faster and more portable.”

As drilling contractor, General Petroleums had already drilled two good wells on a quarter section of John Rebus’s 320-acre farm. Rebus owned freehold oil and gas rights, and fabled Calgary oilman Frank McMahon had snapped up that quarter section for Atlantic Oil Company, which he had founded.

The first two wells – wells that would take 4-5 days to drill today – had each taken a month of drilling. Rather than tear down the steam-powered rig to get ready for #3, Leiper says, “We bolted two huge steel beams across the bottom frame of the substructure, then used hydraulic jacks to put the end of each beam on an athey wagon. Athey wagons were steel contraptions, each with a pair of caterpillar tracks, but with no power. Then we hooked on a cat and lugged the whole rig, completely intact, over to the new location. I’d say that rig weighed 50 ton.”

“We had an old blowout preventer but they were usually clogged with mud and crud,” he says. “We really just put them on for show, and sometimes didn’t put them on at all. They were a joke, but I’m getting ahead of myself.”

Drilling began, but “we pretty soon lost circulation in the well. We pumped down straw, wire mesh, golf balls, chicken feathers – I can still smell those chicken feathers -- and anything else we could to try to regain circulation. Nothing worked.”

One evening Leiper was in the cookhouse listening to an argument among the engineers. Some of them “wanted to drill dry – just pump clear water down past the drill bit. The cuttings would theoretically seal off the lost circulation zone.” After fierce arguments, the dry drillers won the day, and disaster loomed.

It was 3 am, March 8^th, 1948. Leiper continues, “A fellow named Cliff Covey and I were in the cellar under the rig thawing out a line that was frozen solid. Then suddenly the mud started flowing up. There was a blurp of mud over the drilling nipple, and I said to Covey ‘Let’s get the hell out of here.’ We ran west under the rig and a huge master bushing (a rotary table) weighing several hundred pounds went up through the rig and into the air and landed just 20 feet ahead of us.

“There it was. What an awesome sight, the roar of this thing. You couldn’t talk to each other because of the noise. The rig was winterized as they called it in those days – boarded in with tin. The well was blowing huge chunks of shale and they were penetrating that tin just like you’d taken an AK-47 and opened up on it.

“The driller was a guy named Bill Murray, a very capable driller. He dispatched a couple of people to run down as fast as they could to the boiler house and tell them to shut the fire off. Then he and I ran up to the derrick floor and we raised the string of drill pipe as high as we could, chained down the brake on the draw works, and got off the rig.

“The crown of the rig was more than 150 feet off the ground, and when daylight came we could see what we were dealing with. Oil was blowing over the crown. It seems like lunacy today, but we put up some windsocks. We wanted to know when it was safe to fire up the boilers to pump weighted mud into the well. We were wading in oil up to our bellybuttons, carrying these sacks for the drilling mud.”

“This went on for three days,” he says. Then, suddenly, “the flow subsided. It must have got plugged up a bit, naturally.” The crew got the primitive blowout preventer functioning, and things appeared to be looking up. “I’m running one of the steam pumps, and the mud gauge is going down. It looked like we were winning. Then someone came up to me and said ‘I just come by some seismic shot holes on the road and I saw oil and gas coming out of them.’ That’s when it started. That’s when she started cratering, and it gradually got worse and worse.”

“There was two to three feet of snow in the field, and we needed to get water to the rig, we had to get a line strung up to the well to continue killing it. We started setting up a line using five-inch drill pipe in 45-foot lengths, and we were using bull chains to cinch up these thick-walled pipes.”

“I saw Cliff Covey go walking by, and I wondered what he was doing, going back to the rig. Then I saw him waving his arms for us to come. Well, he was just off the farm, and he had gone into an outdoor privy, lit a cigarette and thrown the match down the hole and caught the toilet on fire. We didn’t have anything to fight fire with. We got some gunny sacks and some little hand fire extinguishers from the pumpers. The flames had gone from the toilet to the sump. We’d swat out a bit of fire here and it would jump over there. None of us should have even been in there. It was lunacy. But we were young and didn’t realize the consequences, and eventually we got it out. We always called him Shithouse Covey after that.

“We decided to do a huge cement job on that well. We got 10,000 sacks of cement, put it into the hopper and pumped it down the well. Didn’t fizz a bit on that hole, not one damned bit. It was an awesome sight. The derrick, the equipment, everything but the boilers was collapsing into the crater.”

Eventually, command of the control operation went to Imperial Oil, although Leiper worked at the site until the end, for General Petroleums. “We didn’t get any danger pay,” he recalls. “The Imperial Oil guys got danger pay – they were a mile and a half away at the river. We didn’t get any, and we were right at ground zero.”

Imperial decided to drill two relief wells, but “one of those holes was plagued with fishing jobs and every other problem you can imagine. Then, in early September, the well caught fire. But we had finished a new water line from the North Saskatchewan River to the operations area, and we pumped huge amounts of river water down the relief wells. Finally, I think it was on September 8^th, the well came under control. It just went quiet.”

It took six months, two relief wells and the injection of some 700,000 barrels of river water to bring Atlantic #3 under control. As part of the crude oil recovery effort, trucks sucked more than two million barrels of oil from ditches and gathering pools in the area. Oilman Frank McMahon quipped that the well was “producing through a 40-acre choke.”

The size of the blowout and the cleanup operation created a legend. The whole world knew from newsreels and photo features about it. The words “oil” and “Alberta” had become inseparable.

From a technical perspective, much good came from this disaster. Most importantly, the blowout led to new regulation. “I didn’t see any Oil and Gas Conservation Board (ERCB) people in the area when we were fighting that well,” says Leiper. But after the event the board held a public hearing, and later instituted two important regulations.

The first had to do with surface pipe. The well had been cemented to a shallow shale formation which didn’t have a chance of containing the monster reservoir pressures it encountered. Under the new regulations, drillers had to install adequate surface pipe, and it had to be cemented into a “geologically competent formation” – one that would hold in the event of a blowout.

The second had to do with blowout preventers. After Atlantic #3, BOPs had to be adequate, and there had to be two of them, so you had a backup. This was costly to the industry. “The substructure had to be a lot higher after that, so you could fit all this equipment in the cellar,” Leiper observes. “But this changed the whole complexion of the industry. After #3 there was public regulation of the drilling sector. Prior to that, you were on your own.”

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.

Damage Control

Gasoline and other fuel prices are subsidized in the three representative oil-producing countries graphed on the top right - to the point that gasoline costs $0.12 per gallon in Caracas.

Compare the growth in oil consumption in those countries to growth for the world as a whole. Did you notice a pattern?

By Peter McKenzie-Brown

The world has two kinds of energy-consuming jurisdictions: Those which respond to high oil prices, and those which don’t. In this post, I want to help define which is which. I also want to offer a few explanations why dramatic increases in energy prices have not yet damaged the world economy. These are intimately related issues.

I recently had an interview with Marcel Coutu, the chair of Syncrude – the world’s largest oil sands plant. Syncrude has been in operation for 30 years, and it has gone through a great deal of debottlenecking and expansion. It now produces 350,000 barrels of light, synthetic oil per day.

I asked Marcel for his thoughts on peak oil, and he gave me a few comments that summarize things precisely.

All OPEC can now do is raise prices by cutting production. They cannot lower prices by increasing production because they don’t have the capacity. We are in a very pure free market situation, with prices being set by supply and demand. When I look at that dynamic, I have stopped worrying about the demand side. No matter how much the US goes into recession, for any period that is important to any of us, any decline in consumption there will be offset by increased demand elsewhere – in China and India, but also in developing countries that produce their own crude oil. Those countries generally subsidize oil products, and subsidies accelerate demand growth.

At these prices you are seeing some conservation somewhere, but it is being more than offset by increased demand somewhere else. Whether people are still going to be buying at $200 a barrel I don't know, but by the time we get to $200 it will be the supply side that will keep things tight and moving upward.

He didn’t seem to think this was a major global problem, and I wish I had asked why not.

Three Theories: Historically, rapid increases in oil prices have led to global recession. This certainly applies to the stagflation that influenced the decade after the energy crisis of 1973. The terrible recession of 1982 was without doubt related to the energy crisis of 1979-80. And the long, gradual boom that began in ’83 was closely tied to declining oil prices, and accelerated by their collapse in 1986.

What I think we need to ask ourselves is why high oil prices don’t seem to be doing a lot of damage to the global economy. According to The Economist, there are three possible explanations.

An important and interesting idea is that high oil prices are not hurting the economy simply because they themselves are the result of rapid economic growth around the world. “Rather than oil harming the global economy, it is global expansion that is driving up the price of oil” says the world's great champion of liberalism.

Another explanation is that developed economies are more efficient in their use of energy, thanks partly to the increased importance of service industries and the diminished role of manufacturing. For example, the EIA has calculated that the energy intensity of America's GDP fell by 42% between 1980 and 2007.

A third notion is that the oil price rise has been steady, not sudden. This has given the economy time to adjust. The Economist writes, “Giovanni Serio of Goldman Sachs points out that in 1973 there was a severe supply shock because of the oil embargo, when the world had to cope with 10-15% less crude almost overnight. Not this time.” It’s worth adding that during 1979-80, the percentage increases in oil prices were not as great as they were in the early 1970s, but in absolute terms those increases were greater by far.

The Role of Emerging Economies: As Marcel Coutu explained at the beginning of this article, the most important factor for higher prices has been the shift toward greater consumption by developing economies.

The US, for example, has responded to high prices by cutting consumption slightly. According to one source, the decline will be 1.1% this year, such that American consumption next year will be no higher than it was in 2004. Given such a niggardly response, growing demand from China and other emerging markets will be more than enough to offset this shortfall. With supply growth slight to neutral, the steady increase in demand is hauling prices remorselessly higher. It would take a recession in emerging markets to drive commodity prices substantially lower, and to date recession in those economies is not in the cards.

A couple of points deserve comment here. One is that the achievements of Western nations in reducing energy intensity are nothing compared to the achievements of China. According to an excellent paper on China’s energy consumption and demand , since 1980 China’s energy intensity has dropped by about 75% – nearly twice the drop in the US. The reason is that in every way the world's next superpower has become far more efficient.

Of course, I am raising this point because it suggests a very deep irony: Exporting the world’s manufacturing sector to developing countries has not only enabled the West to become a more efficient energy consumer. It has also helped those countries to become more efficient. Don’t blame the Chinese, in other words: They are doing a far better job at using the world’s resources efficiently than the West can even imagine.

Final Thoughts: These ideas, too, hark back to Marcel Coutu’s earlier comments. By subsidizing energy consumption within oil exporting countries, the world is contributing to inefficient energy consumption. Some of the cheapest gasoline prices in the world are in Saudi Arabia, Kuwait and Venezuela – the last being the all-out winner, with gasoline selling for $0.12 per gallon. The economies of these countries are not known for their gathering efficiency, yet the charts illustrate how much more dramatically oil consumption accelerates when prices are subsidized than when they are not.

The plain truth is that energy importers are subsidizing the inefficient consumption of oil in these countries because of the geographical reality that they have oil to export. Yet the countries we are most anxious about - China and India, for example - are the ones that are increasing their energy consumption not because of large subsidies, but because they are able to provide goods and services with greater energy efficiency than the rest of us.

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.