Language Matters

Petro-Canada: The Incredible Shrinking Assets

2009-10-31T10:24:00.007-06:00

Petro-Canada was the most divisive Crown corporation in Canadian history, and certainly an outcome of awful policy decisions. An obituary of its rise and fall, this article appears in the November 2009 issue of Oilweek

By Peter McKenzie-Brown
About 20 years ago I wrote a speech for Bill Hopper, who was then chairman and CEO of Petro-Canada. He had just taken on a one-year term as chair of the Canadian Petroleum Association (the CPA; now CAPP), which I then worked for.

The process was strange beyond imagination. Instead of simply going to his office to find out what he wanted to say, I learned at the last minute that I was to go with an entourage: CPA president Ian Smyth; vice president Hans Maciej; and my boss, Norm Elliott. Among the other members of the CPA’s board of governors, Hopper alone demanded that amount of attention. The interview took place in Hopper’s palatial offices in Petro-Canada Centre. Not surprisingly, the interview was a flop – a waste of time for all concerned.

This vignette is a reasonable caricature of the early years for the most controversial petroleum company in Canadian history. Especially under Hopper’s leadership, Petro-Canada set the national standard for self-importance, arrogance and underperformance. Although the worst times are long behind us, the company’s epitaph cannot be written without reference to those bad old days. In some ways, they were with the company to the end.

For example, if you believe that markets are inherently rational, try graphing the company’s share price to those of its peers. Every large Canadian oil company has done better than the People’s Oil Company, as it was once unaffectionately known.

When the crash came a year ago, Petro-Canada collapsed more deeply than most. This left it vulnerable to regime change, which quickly came in the form of a takeover encouraged by complaints from a large shareholder, The Ontario Teachers’ Pension Plan, which wanted to increase shareholder value.

The company and oilsands pioneer Suncor Energy soon announced a friendly merger, consummated on August 1st. The transaction created Canada’s largest oil and gas producer, with a market value of more than $50 billion. By the time the companies merged, Petro-Canada had nearly doubled in value from its 52-week share-price bottom, set last November. Clearly, the rational markets felt that with the takeover a better manager was in charge of its assets.

Few people will miss Petro-Canada the oil company. Its corporate history is a bit like the story line for “The Incredible Shrinking Man” – the 1957 movie in which protagonist Scott Carey, who had been contaminated by a radioactive cloud and pesticide, shrank slowly until he was reduced to living in a dollhouse.

In real, inflation-adjusted terms, Petro-Canada was the incredible shrinking company. Notwithstanding infusions of additional cash through equity sales, in real terms Petro-Canada’s market capitalization at the time of its merger with Suncor was less than the federal government’s original investment. In nominal terms (unadjusted for inflation), it lost nearly half the money its founding shareholder, the government of Canada, poured into its maw. And as the shackles of government ownership were slowly removed, it lost a combination of hard cash and opportunity for its second round of shareholders, a long-suffering gaggle of private investors.

The Background
Petro-Canada was founded as a Crown Corporation in 1975 by an act of Parliament and started operations the following year. The company was created upon noble ideals. In a period of intense energy insecurity, the left wing of Ottawa’s political establishment – the minority Liberals supported by the NDP as kingmakers – proclaimed the need for a national presence that would go boldly into the Canadian frontiers, which supposedly were being overlooked by the international players who then dominated Canada’s oil and gas sector. As importantly, the company would serve as a “window on the industry” through which policymakers could peer through clear glass. At start-up, the federal government transferred its 45 percent stake in Panarctic Oils and its 12 percent interest in Syncrude to the newly established company.

While the political issue of the day was ownership of Canadian resources – especially oil – Petro-Canada quickly went into acquisition mode by buying integrated companies rather than pure E and P operations. The idea was to wave the Canadian flag to consumers (aka voters) across the country. Outside Alberta, the political decision to create a national oil company was popular, and the company was given $1.5 billion in start-up money and easy access to new sources of capital.

During its first ten years, Petro-Canada purchased Atlantic Richfield Canada; Pacific Petroleums; Petrofina; most of BP’s Canadian refineries and service stations; and Gulf Canada’s retail and refining operations. The irony was not lost on the oil and gas sector: there were no shortages of refining capacity or retail operations, yet the company paid premium prices for assets which brought considerable liabilities with them. Other companies – BP and Gulf, for example – were selling them partly because the 1980s were a period of consolidation for retailing assets. The era of having a gas station on every corner was morphing into the present era of service stations only in heavy-traffic locations. And with service station closures came significant environmental liabilities, since product leakage from underground storage tanks was endemic across the country. That collective mess had to be cleaned up, and doing so was expensive.

The company did become an important purveyor of gasoline and motor oil at the service station, and one of its few unadorned successes was to develop the trusted and respected Petro-Canada brand of petroleum products. The single biggest boost to that brand came when the company sponsored the 1988 Olympic torch relay – a sponsorship that Ed Lakusta, at the time the company’s president, called the finest thing his company had ever done. Even sceptics began to believe Petro-Canada had a place in the oilpatch, and its gasoline sales soared.

Because of its many acquisitions in Western Canada, the company became one of the largest players in western Canada’s traditional oil fields, in the oilsands and in the east coast offshore. Did this lead to the discovery or development of more oil in the west? Certainly not. In 1927 John Bertram, an American Oil Company operative investigating the energy scene in Alberta, wrote a succinct description of what geologists now call the method of multiple working hypotheses.

“We know from our own experience,” he said, “that the geologists and also the officials of a company that operates in one area for a long time, tend to think along the same lines and to accept the same theories of oil occurrence. When other groups of men invade the same territory, the newcomers work with different methods, use different theories and drill structures the others condemned.” Through its acquisition of numerous companies on the government’s dime, Petro-Canada actually slowed oil development in western Canada – or so says the tried-and-true multiple working hypothesis method.

With the changing of the political winds, governments gradually began privatizing the company. Begun in 1991 under Brian Mulroney (who had ordered the company to act like a profit-driven company when he was first elected), this process was completed in 2004 by the Liberal government of Paul Martin, which sold more than 49 million shares for about $3 billion, bringing the government’s total recovery from its investment to $5.7 billion.

Petro-Canada acquired valuable offshore interests during the Hopper era. These included Hibernia, which is Canada’s most prolific ever oilfield. The company was the operator behind the Terra Nova discovery, which is now Canada’s second-largest offshore oilfield. Also in the offshore, Petro-Canada was the operator of the White Rose oilfield.

But the company did not truly begin operating like a profit-driven private company until 1993, when Hopper was replaced by Jim Stanford. During Stanford’s stewardship, the company made efforts to grow in important ways. Its east coast assets went on production, and the company went international, acquiring and developing in the North Sea, Libya, Syria and Trinidad and Tobago. At the end, those offshore and international operations were its biggest sources of income. After decades of rationalization, its refining and marketing operations – the second-largest in Canada – became a stable and reliable source of cash flow.

For investors, though, the bottom line is the bottom line, and Petro-Canada shares never performed close to the level you might expect from a company with its assets, image and cash flow. An important factor was the Petro-Canada Public Participation Act – Mulroney-era legislation dictating that no single entity can hold more than 20 percent of the company. This made the likelihood of a takeover remote, greatly weighing on Petro-Canada’s stock price. Call it the last curse of public ownership.

The Legacy and the Merger
The storied tale of Petro-Canada is an object lesson in the failures of government interference in the economy. Journalist Peter Foster’s 1992 book, Self Serve: How Petro-Canada Pumped Canadians Dry, won that year’s National Business Book Award and was a factor in unseating Bill Hopper.

At the end of a chilling chronology of hubris and mismanagement during the company’s first 15 years of operations Foster writes, “It can fairly be claimed that Canada is at least $10 billion deeper in debt because of Petrocan, a debt for which there is no corresponding asset. The money has gone….But although the original investment has been largely destroyed, the debt lives with us. We are like bad gamblers in debt to loan sharks, our obligations growing geometrically. The annual interest cost of the Petrocan-associated debt is about $1 billion, and all the income tax from 100,000 average Canadian families will have to go to pay that annual charge.”

According to another, highly hypothetical version of this analysis, Canada would be debt-free if, instead of spending $10 billion on petroleum assets during the high-interest-rate 70s and 80s, the federal government had instead reduced its debt by that amount. More to the point, the creation of Petro-Canada generated few if any useful results. To the extent the company contributed to the policies of the hated National Energy Program, it caused unnecessary and inestimable damage to the country and its oil industry.

Petro-Canada danced into the arms of Suncor with a tremendously deflated cash flow stream and dramatically lower profits after 2008’s oil-pricing bubble. During the company’s last quarter as an independent operator, its net earnings decreased by 95 percent to $77 million, compared with $1.5 billion a year earlier. The company cited the deadly combination of lower commodity prices and volumes plus higher costs and expenses. The recession-related collapse of oil and gas prices was clearly the most important source of this financial disaster.

Disaster that may have been, but for Suncor, with its high-cost oilsands production, the impact was far worse. In the second quarter the company suffered a net loss of $51 million, compared to net earnings of $829 million a year earlier. The financially weaker of the two companies – Suncor – was the acquisitor because of the strength of its management. The company, which at time of writing is trading at about $35 per share, started life in 1993 at about a buck. That’s serious growth – especially compared to Petro-Canada’s original $13 issue price, which had grown to only $41 at the time of the merger. Petro-Canada’s shareholders were a long-suffering breed.

Petro-Canada’s Jim Stanford and Suncor CEO Rick George first discussed merging in 1999, but the negotiations went nowhere. In the crisis atmosphere of the latest recession, though, the players were more motivated to get results. The announcement came less than two months after Petro-Canada’s big shareholder, The Ontario Teachers’ Pension Plan, began agitating for better shareholder value.

At a stroke, the merger between the two companies created Canada’s largest oil company, and the fifth largest in North America. Post-merger, Suncor controls 26.5 billion barrels of oil; the largest suite of oil-sands holdings in the world; daily production of 680 million barrels of oil equivalent; and an international reach that embraces the North Sea, Libya, Syria, and Trinidad and Tobago. The joint Canadian operations of the merged company cover the energy sector, from the Arctic to the east coast offshore, shale gas, refineries and a vast chain of retail outlets. The gas stations and other marketing operations are the only visible remains of what was once Canada’s national energy company.

What is the effect on the new, combined company? The most immediate impact is greater operating efficiency. The designers of the merger – Rick George and Petro-Canada’s Ron Brenneman, Stanford’s successor – forecast that joining forces will save $300 million a year in operating costs and about $1 billion in annual capital spending by eliminating duplication of pipelines, power and water infrastructure for oil-sands operations. In addition, Petro-Canada’s light oil assets are far less vulnerable to another oil price collapse, and will thus stabilize the combined company’s cash flow stream. Also, Petro-Canada brought with it a suite of non-core overseas assets that the company can sell to finance its core oilsands developments, like the Firebag SAGD expansion that went on hold last year.

Professor of economics and academic director of the University of Calgary’s School of Policy Studies Robert Mansell says the deal makes sense in many ways. “In a world with great uncertainty, where we don’t know what is going to happen with climate change policy, it gives you an ability to mix and blend and do all kinds of things that you wouldn’t be able to do if you were just oil sands. Long term, if you can maintain a very efficient, integrated operation that is better than a very narrow, specialized operation. And when you are talking about billion-dollar projects, being a large company is a lot better than being a small company. I see that as being an excellent strength that they can build on.”

If the new company has an Achilles heel, perhaps it is a relic of the Petro-Canada years. As a result of the merger, Suncor is now subject to the Petro-Canada Public Participation Act, which weighed so heavily on Petro-Canada for so many years. That law, which restricts ownership in the company by any single entity to 20 percent, will protect Suncor from predation during the period of consolidation. Longer term, though, will the last curse of public ownership weigh on Suncor’s shares, as it once did on Petro-Canada’s?

The Next Step

2009-10-25T07:38:00.003-06:00

An image from Qingcheng mountain, near Chengdu, in Western China

One of the most under-appreciated alternatives to crude oil is biofuel from lowly algae. Algal oil is more than a good alternative. It’s good business.

By David DuByne
Media organizations continue to feed us down-turning economic news. That’s fine for now, but why isn’t anyone talking about the problems we will encounter as the global economy starts to strengthen and recover?

Economists and energy traders are increasingly coming to the same conclusion: When the economy begins to get back on its feet again, there will be an immediate ceiling of resistance due to high energy prices which will once again crash the markets. This recurring cycle will continue until world population begins to decline, the economy permanently contracts to keep step with falling oil supply, or we develop energy alternatives and environmental solutions. Of these choices, developing alternatives is better than standing in a soup line during a prolonged worldwide depression and fighting wars for the world’s remaining energy reserves.

Biofuels
We need substitutes for liquid fossil fuel and it looks as if the current options will have to be combined as a multi-solution approach with each part contributing to the whole. Biofuels are part of the solution.

We have all witnessed dramatic food price increases as our world first produced biofuel using corn, sugar cane, sorghum, canola and palm oil instead of putting that on our plates. Plus, many of these crops could only be harvested twice or three times a year. This led most governments to quickly realize that non-edible feedstock crops were needed on non-arable lands. Second-generation biofuels included jatropha, castor beans and Chinese tallow. Those products have important limitations: multi-year long “seed to harvest” growth times, high transportation costs and the need for additional seed treatment to get refined product.

Problem is, by next year when there are 80 million more mouths to feed on our planet, the availability of farm grown biofuel will diminish even further. The market for fuel is growing with our growing population. But so is the demand for food.

Now we have entered the third generation of biofuel. Algae bio-crude is stepping out in front as a real contender to make a difference as energy demand continues to increase. According to one authority, “In the beginning, there were algae, but there was no oil. Then, from algae came oil. Now, the algae are still there, but oil is fast depleting. In the future, there will be no oil, but there will still be algae.” We argue that common sense dictates that algae biodiesel will become one of the most important biofuels.

Profitability
Alternative methods are great in theory, but in our world “profit is king”. Projects must show a return so investors will seed the investment. Until the solution itself is profitable there will be no change-over. In this area, algae have important advantages. It has multiple product revenue streams from the bio-crude and associated by-products, and it qualifies for carbon tax credits.

As worldwide energy reserves dwindle, the Chinese government has had a serious wake up call and is now aggressively pursuing renewable energy projects including algae biodiesel. Newspapers around the country carry stories of how China is moving down the green path of development. If it’s true, China’s move in a new direction toward algae-derived liquid fuel may leave the west far behind in the number of installed hectares. Since the world’s manufacturing is done in China all they have to do is manufacture and install, the infrastructure is already there.

China can ramp up production on a scale to convert our existing liquid energy production within the next three to five years. It has the resources and motivation. Additionally, since many pollution and environmental problems exist in Asia, solutions could emerge from countries like China to tackle both issues in the energy production chain.

When we look back in history, production follows the same model. First a product is introduced but it is extremely expensive and there is no centralized manufacturing of that product. As more companies start to come out with the same product, than larger scale production begins and the price drops slightly. In the last stage many businesses are manufacturing in a centralized location with prices driven down to the lowest levels that make it affordable for the average person or family. The DVD player is a perfect example. It cost $1500 in the 1980s; now you can buy one for $50.

Algae growing equipment is still in the beginning stage where machinery is expensive and not readily available for the average person or family. DAO Energy intends to change that. I am one of the principals in this company.

Global Solutions
DAO Energy, LLC is an algae bio-diesel company registered in Texas. However, our staff live in Chengdu, in Western China. Our market research has led us to the opinion along with most others in the algae industry that manufacturing cost for photo bio-reactors and grow-out units is the major stumbling block on the way to viable mass production globally.

Our solution is to help algae bio-diesel companies worldwide to inexpensively source, manufacture and commercialize growing systems. This will provide a cheaper alternative for algal production in every country. We seek to cooperate and partner with international companies that wish to reduce material costs by manufacturing in China. These algae growth systems can then be maintained domestically in any country to create local jobs and support energy independence. Additionally, we will produce high quality, inexpensive “off-the-shelf” photo bio-reactors for schools, universities, and private individuals. I personally hope schools will use these as educational tools for students to see where we are heading with renewable energy and solutions that already exist. We are not out to reinvent the wheel, we want to offer basic photo bio-reactors. We want to seed the concept of “algae growth for everyone” at the individual level into the mind of the populace, because if we are going to convert systems for energy production it will take an effort from everyone, individually, not just at the corporate and governmental levels.

Dao Energy is in the process of designing, modeling and building algae bio-fuel prototype equipment with the purpose of lowering material costs and advising on materials sourcing and logistics in China. Local extrusion and injection molding factories already have everything we need right now for production of our “off-the-shelf photo bio-reactor”. There is a tremendous amount of overproduction and idle factories that are looking for different higher value chain products to manufacture. This is the consequence of the economic recession in China.

A close-up of Dao Energy's reactor

Our near-term plans are to build a grow-out photo bio-reactor next to an ammonia plant, sequester their excess CO2 and then harvest and process algae on site at the plant. In the future when algae production does evolve into a global industry this model of local production, local usage can be mimicked everywhere. Eventually, installation of mass grow-out units will increase and as with everything else over time the single dots will connect into a massive web that should cover the planet and provide some assistance as a liquid fuel replacement.

The Sichuan Trump Card
We have been courted by local business owners that have connections to Sichuan government officials who want us to conduct our project in Sichuan province. The reasons include earthquake reconstruction, job creation, environmental cleanup, carbon sequestration and energy production all in one program. Not surprisingly with mandatory CO2 emission compliance just around the corner, carbon credits have been one of the main subjects talked about in our discussions along with oil production.

Sichuan province remained one of the only electrical generation carbon neutral provinces in China as of 2008. In fact, provincial authorities sold all of 2008’s hydroelectric carbon credits to Saudi Arabia in early 2009. As we have been told, the current Chinese time line is three years before emissions controls take effect on a compulsory level and all carbon credit trading or sales go through China Construction Bank (CCB) in Sichuan. There has also been quite a bit of talk about a “Carbon Credit Trading Floor” being started in Sichuan to cover the western part of China. These are the reasons we have chosen Chengdu.

It’s all about Cost
Consider for a moment that we would be squandering our remaining energy reserves and commodities by building new facilities in every country to produce algae growing equipment while existing factories in Asia are unused. If we choose to go down that path it will be one of the greatest wastes of commodities, energy and investment in human history. During the last 15 years investment poured into Asia for this very purpose; centralizing world production of consumer goods. We should use that investment wisely in a way that benefits every nation.

I need to reiterate to everyone that although our system is manufactured in China for a lower cost, the installation, upkeep and repair of the grow-out and bio-reactors units will be done in each individual country along with growing, harvesting, de-watering and pressing of the algae. Refinement of the oil and processing of algae press cake by-products will be handled by companies in the local community. Local and interstate truck drivers will be driving on fuels produced as a supplement to existing nationwide supply chains. This idea of locality can be replicated everywhere.

At the end of the day, whoever manufactures the most affordable equipment will have the ability to produce oil at a lower cost than anyone else. Manufacturing algae bio-fuel equipment in China utilizing existing infrastructure should ultimately lower the cost of machinery, which in turn will lead us to our main objective; the production of inexpensive crude oil and local job creation in every country.

You can contact Dave Dubyne through his website.

From North to South: How Norman Wells led to Leduc

2009-08-22T17:40:00.008-06:00

I delivered this presentation to The International Commission on the History of Geological Sciences, August 11, 2009

Synopsis: In Canada’s early years, important hydrocarbon discoveries occurred almost independently of settlement. In the frontiers, of course, that pattern continues. The relationship between Norman Wells and Alberta’s post-war discovery at Leduc is one example of a pattern that turns on its head the American model of petroleum development. Remote exploration has always played a critical role in our industry’s development.

It would be easy to think of Canada’s petroleum industry as one that began in the south, grew wealthy, then began exploring and developing more remote lands. That is indeed a realistic caricature of the US industry, but in Canada the story was different. The most important oil discovery prior to Leduc actually took place just south of the Arctic Circle. In a drama worthy of the great white north, that discovery led directly to the creation of Canada’s modern petroleum industry.

By Peter McKenzie-Brown
Before I address the major topic of my presentation today, I would like to suggest an idea about the development of Canada’s petroleum industry compared to that in the United States. Simply put, the patterns of petroleum industry development in the two countries paralleled their respective patterns of settlement.

As you know, the US takes up the best temperate lands along the eastern seaboard, and there are no major barriers to settlement between New York and San Francisco. The Cordillera is a problem, but settlement in the far west was still not seriously hindered – especially after the construction of the transcontinental railways. That pattern exactly reflects the development of the US petroleum industry. In the US there are many sedimentary basins – smallish, but regularly spaced across the country. Once Colonel Drake drilled his historic well, the American petroleum industry developed with patterns of settlement.

Canada has quite a different geography. Settlement was difficult in this country because of the predominance of the Canadian Shield, which provided barriers in many ways. Trapped between the Shield and the Cordillera, the Western Canada sedimentary basin is far bigger than the many on-shore basins in the US. Because of the Shield, it is well separated from the small basins in eastern and central Canada. The Shield and our northern latitudes created what I call the coureurs du bois model of how the Canadian industry developed.

In case you don’t know the expression, coureurs du bois were fur traders who earned their livelihoods with the aid of canoe transport along our mostly northward-flowing rivers. They played a big role in the creation of Canada. For example, from remote northern locations they brought information about resource potential to our political and commercial centres.

Partly because of their efforts, our earliest hydrocarbons were found in outposts of settlement. Consider our Oil Springs discovery, for example, which was contemporaneous with Colonel Drake’s 1859 well. Based on investigation into the well-known gum beds near Black Creek, the Oil Springs discovery took place on the north shore of Lake Erie – in an area without roads, but along the transportation and trading system afforded by the Great Lakes.

Alberta’s first recorded natural gas find came in 1883 from a well at CPR siding No. 8 at Langevin, near Medicine Hat. This well was one of a series drilled at scattered points along the railway to get water for the Canadian Pacific Railway’s steam-driven locomotives. The unexpected gas flow caught fire and destroyed the drilling rig. The discovery took place as we built our first transcontinental railway – itself an effort to settle our empty prairies before the Americans did the job for us.

The Athabasca oil sands were already well known – in fact, the first recorded mention of Canada’s bitumen deposits goes back to a Hudson’s Bay Company record of June 12, 1719. Hoping to find light oil beneath the sands, in the late 19th century Ottawa undertook a drilling program to help define the region’s resources. Using a rig taken north by river, in 1893 contractor A.W. Fraser began drilling for liquid oil at Athabasca, where the oil sands had been known for centuries. In 1897 he moved the rig to Pelican Rapids, also in northern Alberta. There it struck natural gas at 250 metres. But the well blew wild, flowing huge volumes of gas for 21 years. It was not until 1918 that a crew succeeded in killing the well.

These few examples illustrate my point. Quite unlike the situation in the US, Canada’s early hydrocarbon exploration took place along transportation corridors rather than in settled areas. The country had been well explored during the fur trade era, but settlements were still few and far apart. That pattern is in evidence in the case of Norman Wells, to which I now turn my attention.

Ask any of Canada’s exploration professionals when Western Canada’s oil industry began, and you will get one of two answers. The first is the Dingman #1 discovery, which began disgorging wet gas at Turner Valley in 1914. The second is Imperial’s 1947 oil discovery at Leduc. The more thoughtful industrial historian would probably say Dingman was the critical event for the industry’s early years, while the modern era began at Leduc.

I want to suggest that another event was equally pivotal. The year was 1914. The occasion was an expedition down the Mackenzie River by a British geologist, Dr. T.O. Bosworth. There are direct links between that trip and the modern industry’s birth.

The Bosworth Expedition: Two Calgary businessmen, F.C. Lowes and J.K. Cornwall, commissioned Bosworth’s journey. They wanted to investigate the petroleum potential of northern Alberta and beyond, and to stake the most promising claims. Bosworth did not disappoint. His confidence that the north was highly prospective is apparent on almost every page of his 69-page report.

Bosworth’s own words suggest how ambitious the expedition was. “The undertaking was planned in March 1914,” he says. “In April I consulted with the officers of the Government Geological Survey and other Departments in Ottawa and gathered from them all available information; maps and literature bearing on the subject.

“At the beginning of May, I journeyed from London to Canada accompanied by three assistant geologists and surveyors, and on May 19th, the expedition set out from Edmonton to travel northwards in the Guidance of the Northern Trading Company. We returned to Edmonton September 24th.”

During that period, the Bosworth expedition covered huge distances. And according to his report, there were excellent exploration prospects in three general regions: “The Mackenzie River between Old Fort Good Hope and Fort Norman; the Tar Springs District on the Great Slave Lake; and in the Tar Sand District on the Athabasca River.”

His report offered concise, well-written geological descriptions of rocks, formations and structures. It also included chemical reports on both rocks and oil from the many seepages in the area. Some of his greatest praise came from investigations north of Norman Wells, areas which to this day have not yielded a major oil discovery. “Near Old Fort Good Hope (lat. 67 30’) in the banks of a tributary stream, the shales are well exposed ... from the fossils it is evident that the shales are of Upper Paleozoic Age and probably belong to the Upper Devonian,” he said. “This remarkable series of Bituminous Shales and Limestones, of such thickness and of such richness contains the material from which a vast amount of petroleum might be generated and might pass into an overlying porous rock. It is admirable as an oil generating formation.”

In a discussion of the evidence of good reservoir rock, Bosworth points to a nearby occurrence of “gray clay shales and shaley sandstone,” and to another of “greenish shaley sandstone containing occasional fossils – corals, chenetes and rhynconella.”

Both of the reservoir rocks Bosworth speculates upon lie above the Devonian shales. He was looking specifically for “overlying porous rock” to form the reservoir. It does not seem to have occurred to him that reefs within the shales could have served as reservoirs, even though he specifically noted the presence of Devonian corals.

Before I turn to the outcome of this expedition, which was quite important, I would like to share with you the business advice he gave his clients in the conclusion to his general report. “To avoid all competition,” he said, “I strongly advise that you form a controlling company or syndicate containing the most influential men. I recommend particularly that you arrange matters in such a way that it would be to the obvious advantage of every oil man to join you, and that you freely provide the opportunity so that the Company may include every man who wishes to venture anything in the exploitation of the oilfields of the North. By this means alone can you hope to avoid competition and the unfortunate results which must follow….”

In his report Bosworth noted that he had “investigated” the discovery at Turner Valley. Fifteen months in the drilling, the wet gas discovery came in on May 14, 1914 – just before Bosworth left Edmonton on his expedition. Within 20 years, that discovery would be recognized as “the largest oilfield in the British Empire.” Bosworth, however, was not impressed. In his view, the real potential was in the North.

Believing Turner Valley was doomed to disappoint explorers, he wrote that that “there are a number of oil companies in Western Canada who have capital in hand which must be spent on drilling wells. At this moment they are faced with failure (at Turner Valley), and might gladly turn to any region where there is a genuine reason to expect oil. Any such companies might become associated with your controlling company to the obvious advantage of all parties, on terms which can be mutually arranged...”

After further commentary, he advises his clients in these words: “You would also provide for the transportation; the necessary railroads; the pipe lines, the refineries, and, what is more important than all the rest, and which would give you complete command of the whole situation, all of the oil produced in the region would pass through your hands to be marketed by you.

“If you could succeed in promoting a great scheme on some such lines as these, no smaller rival group could hope to compete against you, and you might eventually be in the position to control the great oil fields of the North.”

One of the great ironies of these comments, of course, is that they came barely three years after the Standard Oil Trust was dismantled for just such anti-competitive practices. In addition, Bosworth completely misread the importance of Turner Valley and the petroleum potential of Alberta, so smitten was he by the North. The practical value of his advice may be seen in the fact that seven decades elapsed before oil from the Norman Wells oilfield actually began flowing to southern markets.

Now, let us push on with our story. Bosworth does not remark on the coming of World War I. However, when he and his men left the world was at peace; when he returned, Europe and the British Empire had become embroiled in that terrible war. He was probably totally unaware of those developments while in the north.

The exigencies of war postponed exploration of Bosworth’s claims. So did the Dingman discovery. The petroleum industry by this time was focused on Turner Valley field development, where standard practice was to strip naphtha from the gas stream and flare the gas itself. By 1918 an Imperial Oil subsidiary, The Northwest Company, had acquired the properties Bosworth had staked for his clients. Imperial had hired Bosworth himself as chief geologist. The company decided to drill on one of those claims.

Imperial Oil Limited’s legendary exploration geologist, Ted Link, led the drilling expedition. By train, scow and riverboat, he and his crew followed Bosworth’s route north to Fort Norman, just south of the Arctic Circle. They had taken with them the wherewithal to assemble a cable-tool drilling rig, and they soon set to work. One valuable member of the party was an ox, which supplied heavy labour during the summer. As the autumn cold began killing off the forage, he delivered steaks and stew.

Before moving on, it is worth noting that the most important early geological work at Norman Wells, including the location of the discovery well, needs to be attributed to Ted Link – not to T.O. Bosworth. In an important 1947 presentation to the AAPG, J.S. Stewart of the Geological Survey of Canada is adamant on this point.

Canol: Imperial’s first well brought in the great Norman Wells discovery, in 1920. However, there was no practical way to get the oil to market. Because demand in the Northwest Territories was marginal, Imperial had little reason to develop the field. However, later in the decade the company constructed a tiny refinery at Norman Wells to supply gasoline and other products to missions, mines, riverboats and other local customers. The company did not need many wells to meet local needs, and did little investigation of the geology of the reservoir.

That changed after Pearl Harbor. When the Americans came into the Second World War, they were extremely concerned about having secure local fuel supplies in the North, especially after Japan took control of a couple of Alaska’s Aleutian islands. They therefore worked with Canada to develop Norman Wells into a source of local oil supply for a refining and distribution complex. This was the beginning of the Canol Project. The name supposedly comes from the contraction of “Canadian” and “oil”, but I suspect the second syllable is actually “oil” with a Texas accent.

Construction crews built a 950-kilometre oil pipeline over the Mackenzie Mountains to a newly constructed refinery in Whitehorse, in the Yukon Territory. The pipeline was built over some of the most difficult terrain in the country, and much of the work had to be done in bitter cold. Crews also laid product pipelines to Skagway, Alaska. In total, they constructed 2,560 kilometres of pipeline.

By any standard those lines were terrible. The line ran on top of the ground, alongside the road, often without supports. Vulnerable to frost heaving, snowstorms and flooding, the Canol pipelines were not designed for extreme cold. They were neither installed nor handled properly, and they failed frequently. The crude oil pipeline leaked onto the permafrost. So did the product pipelines, which delivered diesel and gasoline to a fuelling station in Skagway, Alaska.

To meet the needs of the refinery, Imperial drilled more wells, and began to better understand the Norman Wells reservoir. Of particular note, the company discovered that it was a Devonian reef – of earlier vintage than the Leduc and Redwater fields soon to be discovered in Alberta, but still a Devonian reef. That turned out to be the geological key.

By the time the refinery was ready to begin operations, the company had drilled 60 productive wells out of 67 project wells in total. The test for the field came on February 16, 1944 when the pipeline began operating. As a producer of good-quality oil (39° to 41° API), the field surpassed expectations. By October 1944 Norman Wells was producing 4,600 barrels per day by natural pressure.

The extraordinary Canol project did not contribute meaningfully to the war effort. The threat to west coast shipping had disappeared and it was clear that the war would soon be won. First oil flowed through the pipeline in 1944, and the refinery operated for less than a year before being mothballed. Perhaps Canol was the greatest white elephant in petroleum history.

No one really knows how much the project cost – estimates range up to US$300 million, all paid by American taxpayers. However, for the following calculations I will use one of the conservative estimates: $134 million. Total oil production was about 1.5 million barrels. In as-spent dollars, therefore, it cost $89.33 per barrel. The Whitehorse refinery only produced 866,670 barrels of refined product. Dividing that by total project cost, you get $0.97 per litre.

Now, let’s adjust those numbers by official consumer price inflation in the United States. In today’s money, the oil would cost $982 a barrel. The refined products would cost $10.69 a litre. And that’s before taxes!

Later studies of the project’s environmental impact in Whitehorse were revealing. The Canol legacy included the creation of an environmental horror known locally as the Maxwell Tar Pit. Appalling disposal and clean-up practices during the Canol debacle had created an oily mess that was declared an environmentally contaminated site in 1998. Forty years earlier, a man had stumbled into the pit and got stuck. He later died in hospital.

Leduc: Although Canol had little impact on affairs of state, it had a huge impact on oil development in Western Canada. As the result of wartime field development at Norman Wells, Imperial learned that the field’s reservoir rock was Devonian reef. Armed with this knowledge, the company’s geologists – led by Ted Link, who by this time was in charge of Imperial’s exploration efforts – rethought their approach to Western Canada.

This was an important example of thinking outside the box. Other oilmen at the time were on the hunt for big plays that looked, walked and talked like Turner Valley. They would be roughly 340 million years old. They would be thrusted anticlines of Paleozoic age in a Mississippian formation. Much fruitless drilling in the foothills sought the next Turner Valley.

Perhaps we should not give all the credit to Imperial Oil for the geological idea that there might be Devonian reefs in Alberta. In an email, my friend Clint Tippett asked whether GSC mapping of the Rockies west of Edmonton – work undertaken by Helen Belyea, Digby Maclaren and others – influenced Imperial’s thinking. Before the Leduc discovery, Charles Stelck at the University of Alberta also gave thought to the question of Devonian reefs in Alberta.

However Imperial arrived at its revolutionary idea, the importance of its decision to drill for a reef cannot be understated. That geological idea brought forth a series of great discoveries. The first came with the aid of primitive seismic technology, and it was a big one – the famous Leduc #1 discovery well. When it came in to much fanfare on February 21, 1947, Leduc laid the groundwork for one of the world’s great post-war oil booms.

There is another important connection between post-war oil development in Alberta and the Canol project. The refinery built in Whitehorse played an important role in Alberta’s industrial development. Imperial bought the mothballed refinery for one dollar, dismantled it and moved it to Strathcona, near Edmonton. There, the company reassembled it to handle production from Leduc and other post-war discoveries. That refinery laid the foundation for one of Canada’s biggest refining complexes.

As I leave this discussion, a final piece of trivia. Although Imperial is the hero of this drama, I understand that the company’s geologists mapped the Leduc reefs at a 90° angle to their actual orientation. After mapping them correctly, Texaco came to have the dominant position in the Leduc chain of reefs.

Summary: The Norman Wells story illustrates a pattern that turns on its head the American model of petroleum industry development. Briefly put, remote exploration has played a critical role in the industry’s development since the earliest years of oil and gas exploration in this country. Bosworth was wrong in important areas. However, his work greatly influenced that of his successor, Ted Link, who ultimately proved that Devonian reefs were an important key to Canada’s petroleum wealth. That change in thinking paved the way for a series of discoveries which represented the birth of the modern petroleum industry in Canada.

It would be easy to think of Canada’s petroleum industry as one that began in southern Ontario and Alberta, grew wealthy, then began exploring and developing its frontiers. But this model doesn’t fit the facts. Key discoveries and developments took place in remote regions. In the sector’s early years, important discoveries occurred almost independently of settlement, and a great deal of oil and gas development continues to take place in sparsely populated areas. In our frontiers, of course, that pattern is fully intact.

If not for the Bosworth report, Canada’s petroleum industry would have had quite a different history. Imperial Oil’s efforts were heroic – indeed the stuff of legend. Enormously frustrated with its unbroken string of 133 dry holes, Imperial planned the program that yielded Leduc as its last major wildcat play in Alberta. If Leduc had not come in, it is easy to imagine the Devonian oil fields lying fallow for many, many years. No other big players were exploring the prairies.

In the actual case, however, oilmen around the world soon became aware of this important new discovery, and they began to bring expertise and investment into the province. They created one of the first great post-war oil booms, and helped lay the foundation for one of the world’s most diverse and technically advanced petroleum industries.

In respect to its long-term impact, T.O. Bosworth’s 1914 report may have been the most influential geological document in Canadian history. I hope my brief comments today have given you reason to consider that claim.

References:
1. T.O. Bosworth, 1914; “The Mackenzie River between Old Fort Good Hope and Fort Norman; the Tar Springs District on the Great Slave Lake; and in the Tar Sand District on the Athabasca River.”Available at the Glenbow Archives, Calgary; reference number M-8656; 69 pages.
2. J.S. Stewart, 1948; “Norman Wells Oil Field, Northwest Territories, Canada”; in Structure of Typical American Oil Fields, Volume III, pp. 86-109; original paper read before an AAPG meeting in Wichita, Kansas, on January 18, 1947.
3. Peter McKenzie-Brown, 1988; “Two Historical Documents: Notes for an Address to the Petroleum History Society”; online at http://languageinstinct.blogspot.com/2006/09/two-historical-documents.html

The Next Step

2009-08-12T17:28:00.010-06:00

An image from Qingcheng mountain, near Chengdu, in Western China

One of the most under-appreciated alternatives to crude oil is biofuel from lowly algae. According to a frequent contributor to this blog, who is developing production in China, algal oil is more than a good alternative. It’s good business.

A close-up of Dao Energy's reactor

You can contact Dave Dubyne through his website.

Star Power

2009-08-03T07:36:00.010-06:00

As fusion power progresses, the Alberta Council of Technologies urges the province to take a leading role in developing the power of the sun

This article appears in the August 2009 issue of Oilweek; graphic from here

By Peter McKenzie-Brown

During the Second World War, celebrity physicist Albert Einstein suggested in a now-famous letter to American President Roosevelt that nuclear chain reactions in large masses of uranium could release “vast amounts of power and large quantities of new radium-like elements.” And, he speculated, “Extremely powerful bombs of a new type may thus be constructed.” While America had only poor-quality uranium, Einstein noted, “There is some good ore in Canada.”

The ore used to create the first atomic bombs came from a rich deposit of uranium and radium along the shores of Great Bear Lake, in the Northwest Territories. During the long days of summer, a wartime mining company hired local Indian men to carry 40-kilo burlap bags of ore from the mine to the Mackenzie River. They carried those loads for long hours, for months on end. When the bags ripped apart, they shifted the spilled ore off the trail, but took the contaminated bags to their temporary village. Years later, the ore-carriers began dying of cancer, and the community now known as Deline became a village of widows. Canada was thus an important contributor to the first nuclear age, which was born of the fission of radioactive elements.

Within a decade, the United States had made tentative steps toward a different kind of nuclear age – one based on nuclear fusion. This system smashes together light atoms like those of hydrogen. As it turns lighter elements into heavier ones, fusion releases vast amounts of energy. This is the principle behind the hydrogen bomb. It is star power – the fuel that keeps the Sun and the countless other stars alight. As a human invention, its only practical use has been as an unused weapon of violence and terror. Until now.

"[Fusion ignition] is imminent and will be one of the most extraordinary technologies discovered by mankind. We will be reproducing the physics of the sun.”

On March 10, the National Ignition Facility at Lawrence Livermore Labs in California trained 192 high-power lasers onto a point the size of a couple of match-heads. The ensuing reaction generated more than a million joules of energy – enough energy to theoretically light up 10,000 100-watt light bulbs. The American effort was costly, but its implications were huge. That step suggests the birth of a nuclear age in which virtually limitless amounts of inherently safe and environmentally attractive will be cheaply available. Compared with carbon or uranium fuels, fusion generates little radiation and no greenhouse gases or air pollution. Since it uses small amounts of fuel, it is likely to have little impact on land and habitat.

The day before this extraordinary American achievement, a standing committee of the Alberta Legislature met to consider a proposal by which Canada would become involved in these revolutionary technologies. Canada would not supply ore, as we do for nuclear fission. After all, the fuels needed for fusion are abundant around the world. Instead, we would help develop technological expertise for the second nuclear age.

Visionaries: The proposal came from a small, minimally-funded and loosely-organized group of visionaries provincially chartered as the Alberta Council of Technologies. Clearly, the goal of the media relations surrounding the meeting with the legislature was maximum public awareness. In this, they certainly succeeded.

The idea is to prove that controlled nuclear fusion can become the world’s energy future. Theoretically, it could provide clean and nearly limitless electrical power for humankind, with everything that implies. It could mean a reversal of global warming and the reversal of policies by which agricultural products are transformed into fuel.

According to Dr. Perry Kinkaide, the group’s chairman, his council was asking the province to contribute to a demonstration of fusion ignition. Fusion ignition, he said, “is imminent and will be one of the most extraordinary technologies discovered by mankind. We will be reproducing the physics of the sun.” When you get into the physics of this “imminent” technology, which talks about creating temperatures so hot (up to 100 million degrees Celsius) that they can only be enclosed by magnetic fields or lasers, it’s like tripping forward through a time-warp. Yet new technologies – demonstrated by the test at the Lawrence Livermore Laboratories – have changed the picture.

Adds Allan Offenberger, a retired University of Alberta engineering professor and another program proponent, it is the new technology of “inertial confinement” of the heat of fusion that is changing everything.

Inertial confinement uses laser beams to quickly heat to ignition a “fuel pellet” of simple atoms like the commonplace hydrogen isotope deuterium and the much less stable hydrogen isotope tritium. Because this process rapidly induces fusion, you don’t have to confine the fuel at all. The advantage: a relatively simple reaction chamber design.

Even so, this is a long-term proposition. A demonstration project isn’t likely for 25 years, say, with commercial facilities following a decade after that. However, the promise is great. Once the bugs have been worked out, the fusion energy could be very cheap.

To begin to develop expertise in this area, the proposal suggested that the province pony up $4 million this year and commit to another $17 million, total, in the two fiscal years following. The proponents argued that if Alberta scientists don’t get in on the ground floor, they will fall behind in expertise. Joining the project later, they argue, will be more expensive

Once the province got its foot in the door, the proponents call for an intensive program of R&D “to develop inertial fusion as a viable energy technology.” This phase would cost perhaps $40 million per year. Eventually, according to the council, having expertise within the province could lead to commercialization of the technologies. Perhaps the province could become “a provider of high power lasers, reactor systems engineering and related technologies for fusion energy and other applications.”

According to Offenberger, the aim is to create a safe, relatively cheap and clean method of producing electricity based on fusion. One attraction of this form of energy, he says, is that huge amounts of energy could be created with less than a kilogram a day of two types of hydrogen fuel. Also, there is no chance of meltdowns from this form of nuclear energy, which produces no hazardous wastes. The only waste products are heat and, from the size plant the group visualizes, about a kilo of helium per day. The proposal also points out that there could be huge savings on transmission costs “because (fusion) plants can be located close to electricity users.”

Canada is the only major industrial country without a fusion research presence. Given the country’s energy wealth, proximity to the United States and trade surpluses, perhaps that’s not unreasonable. I put the question to someone with the broadest imaginable view of electricity supply and demand within Alberta.

Technological Dominance: At the time of our interview, Martin Merritt was completing his term as the Alberta government’s Market Surveillance Administrator. His job was to make sure electricity and natural gas markets within the province were free and fair. Although he was quick to say he had no expertise in nuclear fusion, he surmised that “The best place to do this would be in the US, where the problems of energy supply, environmental problems, worries about global warming and the need to remain technologically dominant are so powerful. Europe also has those problems. In that sense, the timing seems perfect” to be developing these technologies.

By contrast, he opined, “Alberta’s main reason (to become involved) is that as an important energy power, we have many reasons to have an oar in developing energy technology.” He added that “Alberta needs to get around the (environmental) brush we’ve been tarred with. Perhaps adopting this form of energy could earn us green credits.”

Perry Kinkaide’s Council of Technologies, however, sees an urgent need for Canadian involvement. In a document on the council’s website, the group argues that “The window of opportunity is closing fast for Alberta and Canada to participate in a global partnership for developing ‘fusion,’ the ideal solution for meeting the world’s primary energy requirements – forever! Participation will secure our position as an energy superpower as the world transitions to fusion, with significant socio-economic and environmental spin-off benefits.”

In this compelling commentary, the organization addressed “the need for fusion energy and the prospects of a revolutionary new technology for its achievement.” Citing significant environmental, health and safety implications, it also noted that “the strategic fit of fusion technology with the demands of North America’s coal-based electric power industry as plants reach end-of-service and require replacement.” What is needed immediately, they insist, is an action plan “to ensure Alberta’s and Canada’s place in the emerging fusion-energy economy.”

While the notion of fusion energy is closely tied to the generation of electricity, perhaps it could meet an oilsands challenge which went untried during the optimistic early years of the first nuclear age.

Fifty years ago, Richfield Oil Company proposed an experimental plan to release liquid hydrocarbons from the oilsands through the expedient of an underground nuclear explosion. The company proposed detonating a nine-kiloton explosive device below the oil sands at a site 100 kilometres south of Fort McMurray. Thermonuclear heat would create a large underground cavern and simultaneously liquefy the oil. The cavern could serve as a collection point for the now-fluid bitumen, enabling the company to produce it.

This idea came remarkably close to actually taking place. The project received federal approval in Canada, and America’s Atomic Energy Commission agreed to provide the device. But before the pilot could take place, public pressure for an international ban on nuclear testing had mounted. As the late Ernest Manning once told me, when he was premier the provincial government withheld approval and thus killed the plan.

Perhaps in the second nuclear age, energy from nuclear fusion could become a safe and realistic heat source for producing and refining the dense oils Canada is famous for. This idea may sound far-fetched until you consider that in Peace River Shell is already testing the use of electric heaters to refine bitumen carbonates in situ, deep inside underground formations. When you start talking about a second nuclear age, nothing seems impossible.

Exploration Fuel

2009-07-27T08:13:00.006-06:00

New computer modelling system allows exploration of Canada's potential energy future; graphic from here. This article appears in the August 2009 issue of Oilsands Review

By Peter McKenzie-Brown

“This is a way of getting inside the energy system, getting a sense of its possibilities. I’ve been around for a while, and I’ve never seen anything like it.” The speaker is Bob Taylor. After a long corporate career with a pair of big oil companies, he joined Alberta’s Department of Energy’s as assistant deputy minister for oil development. Now retired, in that job he had responsibility for conventional oil, oil sands, land access, and energy and Aboriginal relationships. Today he is excited about something he believes is much bigger than all of these combined.

An engineer by training, Taylor is part of an informal group of senior patch people who have formed a not-for-profit organization they call the Energy Futures Network. They argue that Canadian policy-makers – whether they work in government, industry or the world of NGOs – should be able to take the longest possible view of resources to make sensible decisions.

"The exact analogy [to the modelling system] is the flight simulator. You can get into the simulator and use the controls to see how the plane will respond. The nice thing is that if you crash the plane, you can learn from your mistakes. You don’t want to crash the plane in real life.”

With the help of an Ottawa-based firm called whatIf? Technologies , he thinks they’ve got it. Taylor is excited because he believes he can now feel, touch and imagine Canada’s possible energy futures to the end of this century: No small feat. The trick was to create a computer model that could deal with supply and demand without factoring in price. Economists would call that heresy; Taylor calls it “dynamic and robust.”

His Energy Futures group has just done a simulation of Canadian gas supplies for a government agency, and he believes the results will worry – or should worry – oil sands producers. “Without significant development of Canada’s unconventional gas and a significant reduction in natural gas use,” he says, “Canada will become a net importer somewhere between 2023 and 2030. Even with development of unconventional gas and a less aggressive shift towards natural gas supplied electricity, Canada may become a net importer by about 2050.”

This, he says, has wide-ranging implications for the oil sands, which use gas to produce hydrogen for upgrading, to supply heat for production and upgrading operations, and to generate electricity. “There will be both economic and societal pressure to reduce the use of natural gas for oil sands production and upgrading. The housewife in Chicago will win out on the purchase of natural gas every time.” He adds that “the timing to make the technology changes is short. The life cycle for technology-dependent major capital is anywhere from 15 years to 40-plus years.”

Bypassing Gas: You can imagine the office comedian saying through hands shaped like a mock megaphone: “Helloo-o! Earth to planners! Make oilsands production and upgrading less natural gas-intensive, and start doing it now!”

Taylor’s Energy Network report uses a reference case in which oilsands production reaches 5 million barrels per day. Reducing sectoral gas demand is going to be critical, he concludes if the industry is to avoid industrial turmoil from conflict between consumer needs (remember the housewife from Chicago) and industrial demand.

Is it possible to lower the sector’s natural gas intensity? Taylor believes it is. “We could cut natural gas intensity for in situ production by 30 per cent through the use of solvent technologies,” he says, “and we could cut in half the gas we use to create hydrogen for upgrading. This would save (consumption of) about 1.3 billion cubic feet per day,” by mid-century.

Taylor notes other possible ways to reduce methane consumption. One option could be a different extraction technology: the Chinese government is building a demonstration facility based upon Supercritical Extraction, for example. Another possibility would be to gasify upgrader bottoms. Many ideas are out there.

He thinks more gas savings can be had from Petrobank’s THAI (toe-to-heel air injection) system – a trademarked, patented non-steam process that could be a simpler, cheaper, cleaner and more efficient alternative to SAGD in situ production. However, he says, the THAI process has a significantly higher CO2 output per barrel of production, and the world is now facing an environmental revolution. Worries about global warming could put this technology at risk.

“That is the beauty of a physical model that tracks all inputs and outputs,” Taylor says. “If you want to see how the THAI technology will affect the future, you can put in the technical parameters that show very low methane inputs. However, the system would need to reflect the THAI system’s much greater production of CO2 per barrel of production, compared to SAGD. You win on one side, but lose on the other.”

The CanESS Model: It is important to note that all these conclusions come from a study of natural gas – not the oilsands. In Taylor’s view, his conclusions are less important than the methods he used to get there. He believes the model he hired whatIf? Technologies to develop is revolutionary.

Michael Hoffman, a partner in the company, agrees. “We build tools that really work with numbers,” he says; “they aren’t just mind models. We create tools that enable them to play what-if games. We want models of the system that allow you to explore the system through scenario analysis. The exact analogy is the flight simulator. You can get into the simulator and use the controls to see how the plane will respond. The nice thing is that if you crash the plane, you can learn from your mistakes. You don’t want to crash the plane in real life.”

The Canadian Energy Systems Simulator (CanESS) focuses on Canada’s energy systems. It interconnects some 800 variables, and incorporates hundreds of thousands of StatsCan data points. According to both men, it is eerily able to take you into the energy system, and enables you to feel and touch the way the world will evolve in the decades ahead.

As Hoffman explains, “The core business of our company is to build models that put quantitative data behind a physical economy model. The data we use represent physical stuff in Canada – tonnes of crops, tonnes of coal, gas volumes, barrels of oil, liquids and bitumen. It’s oriented physically, not price oriented; it only looks at supply. When we make assumptions about demand, they are based on bottom-up modeling, using assumptions based on past data. The model is calibrated back to 1976, mostly using government data going back that far.”

Hoffman brings out a laptop to demonstrate how the model works. We are quickly up and running. “The value of this kind of tool is to explore the boundaries of the system,” he says. “Remember: this is a full-system energy model. It explores the whole energy system. It’s not a predictive tool; no one can predict the future. It’s a tool to explore the system. My hope is that policy-makers would want to have a tool like this to inform policy. With a tool like this, you can explore the implications of policy.”

Take the idea of developing biomass as an alternative to gas for the oil sands, for example. He changes a few core assumptions to explore the possibilities. It quickly becomes clear that supply wouldn’t be sufficient to offset much gas demand.

“Well, it just wasn’t as effective as we’d hoped,” he says philosophically, but adds that we should think of the potential. “Since this model provides a full-system context, you can do this in any area to avoid making bad policy decisions. Once we explore policy with this tool, we can say that, at the limit, here’s what we can get from this resource. That kind of information is really helpful in informing the conversation.”

Proof in the Pudding: Taylor and Hoffman see the completion of their contract with Alberta’s Department of Energy as a big step for energy policy-making in Canada. “We have now demonstrated the significance and the power of this system,” says Taylor. “Now we can explore the implications of energy policy options. We can have intelligent discussions about some of the possibilities for our energy future. If we don’t want that future, what assumptions do we have to make? What do we have to change? We can examine that now, and that’s important.”

The proof is in the pudding, and the demonstration the two men provided to the Department of Energy got rave reviews, they claim. “We can now offer people the opportunity to explore questions within the model. We want to assist the energy industry in doing some analysis, and help them answer questions.”

“The Energy Futures Network is a not-for-profit,” Taylor reiterates, “and whatIf? is a relatively low-margin business. We want to work with planners and policy-makers to encourage them to use this tool to help answer questions. We want companies like Imperial, for example, to use this model to help organize their thinking.” Taylor and Hoffman expect the model to be continually refined so that it ever more accurately reflects changing ideas and information about the sector.

CanESS, one hopes, will prevent crashes. As Hoffman said, “You don’t want to crash the plane in real life.” Really.

Colossal Chore

2009-06-20T09:16:00.006-06:00

Even government computers are strained by oilfield waste

This article appears in the May 2009 issue of Alberta Oil Magazine

by Peter McKenzie-Brown

The story of petroleum is a story of waste.

Consider the volumes involved: At perhaps 3.5 million barrels per day, Canada is the world’s seventh-largest oil producer, and at 16.9 billion cubic feet per day, the third-largest natural gas producer. Add in the gas liquids and related products and the sheer volume of fossil fuels that flow out of the Canadian soil starts to become astronomical.

And these numbers measure “spec” oil and gas – products that are clean enough for pipeline transport. Consumers rarely consider the huge amounts of waste created as the industry brings its output up to spec.

At every stage, considerable volumes of waste need to be treated. Consider the sources of upstream oilfield waste. Seismic surveys, wellsite construction and drilling produce wastes ranging from bush cuttings to rock chips to drilling and fraccing fluids. Production wastes include salty byproduct water, gunk in tailings ponds, contaminants like carbon dioxide and hydrogen sulfide, and soil contaminated with sulfur. Once a plant needs to be decommissioned or a well shut in and abandoned, the producer creates more wastes that need to be carefully managed.

How much waste is involved? In Alberta, the Energy Resources Conservation Board regulates oilfield wastes. After a lengthy explanation of the limitations of the board’s computer system, Susan Halla, a regulatory manager, says, “We’ll be able to give you exact information in 2011.” In the meantime, she won’t even guess.

Even when detailed data are available, it will be incomplete. The reason is that most wastes from oil sands mining operations are not considered oilfield wastes. They are classified as “industrial wastes” and regulated by Alberta Environment rather than the ERCB.

Petroleum waste only begins in the “upstream,” exploration and production side of the industry. Once spec products flow through the pipeline into the “downstream,” refining and distribution processes produce wastes of their own. Like waste from oil sands mining, they are classified as “industrial wastes” and regulated by Alberta Environment.

By far, however, the largest volumes of physical waste occur in the distant downstream end of the petroleum products life cycle. Many items – plastics and chemicals, say – end up in landfills and dumps, unregulated incinerators, beaches and worse. Equally important, consumers burn natural gas and refined products to generate energy, thereby yielding carbon dioxide, nitrogen oxides and a variety of other unsavory incidentals. As emissions, however, they are technically not considered “wastes.”

The seriousness of upstream waste management did not become clear until the 1980s. An ERCB chairman of the era, the late Vern Millard, once explained, “We used to think Earth could absorb any amount of human waste without a problem. It has now become clear that it can’t.”

In an effort to obviate official regulation, the old Canadian Petroleum Association – the forerunner to today’s Canadian Association of Petroleum Producers – created an industry-wide voluntary code of waste management practices. Although regarded as a good stop-gap measure, the CPA guidelines didn’t last. Governments soon took over the job of regulation.

The ERCB’s role in waste regulation began in the mid-1980s, when the industry began to recognize that oil could be recovered from oily leftover materials in tank bottoms, separator sludge, flare pits and so on. Facilities known as reclaimers began to emerge in active oil- and gas-producing areas. At first, the board’s regulation of these facilities was aimed at making sure volumes of recovered oil were accounted for properly. Spurred by the federal government’s 1986 proclamation of dangerous goods transportation regulations, though, the board became heavily involved in oilfield waste management, regulation and inspection.

In 1990, Alberta began consolidating existing environmental acts and regulations into a comprehensive document that eventually became known as the Environmental Protection and Enhancement Act. This and other environmental measures slice and dice provincial wastes in a number of ways. They can be classified as oilfield wastes or industrial wastes, and those wastes can be hazardous, dangerous or not-dangerous. Alberta Environment regulates hazardous and industrial wastes. The ERCB regulates oilfield wastes.

As waste regulation evolved, it became apparent that reclamation or recycling services could no longer be permitted to operate without regulation. After all, they were reclaiming wastes that were potentially dangerous, and sometimes hazardous. Hazardous oilfield wastes include hydrocarbons with low flashpoints; highly acidic or alkaline chemicals; and such volatile organic compounds as benzene, toluene, ethylbenzene and xylenes, which collectively go by the acronym BTEX.

After these products had been defined as hazardous, the board gave the owners of the province’s reclaimer operations a simple choice. Transform their facilities into high-standard waste management facilities or, in the words of CCS Corporation’s Greg Dickie, “clean them up and shut them down.” Most chose to convert to quality waste management operations.

With oilfield waste facilities not allowed to handle hazardous materials, the province badly needed a large disposal facility. Accordingly, Alberta developed a “special waste treatment center” northwest of Edmonton at Swan Hills to deal with hazardous oilfield wastes and also carcinogenic PCBs, which are primarily a waste product from electric transformers. Owned by the province but operated by the private sector, Swan Hills is primarily a specialized, high-temperature waste incinerator. The oilfield wastes that require incineration there include spent filters, oily rags and specialized high-BTU wastes.

As the 1990s wore on, regulators developed rules covering everything from the construction of landfills to deep well injection of liquid wastes. Those rules and the constant changes to them are available in a glut of guidebooks, information letters, directives and interim directives – all of which have been posted online by the agencies responsible.

Practice Run

2009-06-20T08:35:00.006-06:00

H2S re-injection a rehearsal for carbon storage program

This article appears in the May 2009 issue of Alberta Oil Magazine

by Peter McKenzie-Brown

Once an obscure part of waste management, the injection underground of unwanted gases will soon become a huge part of Western Canada’s business. The industry has had plenty of practice at disposing of nastier materials than carbon dioxide.

Oil and gas operations produce two kinds of acid gases – hydrogen sulfide (H2S) and carbon dioxide (CO2). The former is usually stripped from the gas stream and converted into sulfur. Tom Byrnes, a reservoir engineering manager at the Energy Resources Conservation Board, says the sulfurous impurity is sometimes just stripped from the gas and re-injected underground. “It’s usually an economic question. There may be small volumes of H2S in the gas stream, or the infrastructure [to strip out sulfur] may not be in place to make it practical.” In Alberta, the board regulates all disposals through disposal wells and first approved an H2S re-injection project in 1989.

Both of these acid gases are routinely stripped from natural gas for re-injection, as appropriate. “But the smaller the concentration of H2S or CO2 there is in the gas stream, the more expensive it is to get it out. It’s a problem of diminishing returns,” Byrnes says.

If H2S can have commercial value as a source of sulfur, CO2 is frequently injected into operating oilfields to stimulate production. This is not new. Carbon dioxide has long been used for enhanced oil recovery, to urge additional barrels out of elderly oilfields. One such project has been operating in the 50-year-old Weyburn oilfield in southern Saskatchewan for nine years.

The project uses a 330-kilometer pipeline to transport carbon dioxide captured at the Great Plains Coal Gasification plant, which manufactures methane from coal near Beulah, North Dakota. As it keeps oil flowing from this aging field, each year the EnCana-operated project disposes of about 1.5 million tonnes of carbon dioxide emissions. This is environmentally beneficial, since CO2 is both an acid gas that can acidify water and a greenhouse gas that can trap heat within Earth’s ionosphere.

While EnCana’s Weyburn project is profitable in its own right, most industrial operators would find it economically prohibitive to strip CO2 from industrial processes for sequestration down disposal wells. Those economics changed profoundly last July when Alberta Premier Ed Stelmach announced a $2-billion commitment of government assistance to advance carbon capture and sequestration (CCS) technologies in the province. Provincial authorities are now sifting through a dozen applications for funding, and will announce the successful projects as decisions are made.

Alberta’s involvement follows a gestation period of deep study, including a provincial policy paper which observed that “Alberta has a unique opportunity to implement carbon capture and storage to substantially reduce our greenhouse gas emissions. CO2 emissions can be captured where they are produced, transported and stored in geological formations (such as depleted oil and gas reservoirs, coal beds and deep saline aquifers) that may be located hundreds of kilometers away.

Ultimately, CO2 capture and storage technologies provide the province with the greatest potential to substantially reduce greenhouse gas emissions while, at the same time, retaining our ability to produce and provide energy to the rest of the world.”

According to that policy paper, Alberta is counting on CCS to meet 70 per cent of its long-term greenhouse reduction targets. If the five provincially subsidized projects – likely to cost a billion dollars each–all go into operation, they would collectively reduce emissions by up to five million tonnes annually. That is likely just the beginning for large-scale underground carbon sequestration projects in the province.

While five million tonnes annually of sequestered CO2 may seem like a large number, it’s barely a whiff of what’s possible. Over four decades, Alberta’s greenhouse gas emissions plan targets a 200-million tonne cut in emissions, but only compared to a do-nothing scenario. That volume is a bare indication of the huge volumes of waste – solids, liquids, effluents and emissions – generated by one of the world’s leading petroleum producers.

Stairway to Heaven

2009-06-13T09:30:00.005-06:00

Anne Davison, Wendy Noonan and Terry Martin at the fabled city of Machu Picchu

By Wendy Noonan

I sat at the kitchen table, drinking coffee, wondering who I was. My grown-up children wanted my support, and my newborn granddaughter pulled at my heart. My parents needed me. My husband humoured me. Just retired, I had put my career behind me. I had decisions to make about my future: what next?

I opened the newspaper and saw a small advertisement for a four-day, 47-kilometre trek along the Inca Trail to the storied lost city of Machu Picchu. I couldn’t get that Arthritis Society ad out of my head, and eventually I plunged in. The challenge, I hoped, would bring back my focus.

To my delight, two friends decided to join me. I assured them this was something we could do. Altitude was no problem. After all, Calgary is 3,200 feet above sea level, so what would be difficult about Machu Picchu’s 4,200? Wrong! I’d missed a detail. We would climb to 4,200 metres – more than 13,000 feet.

I started training and began to think of other things. A good friend with lupus, a form of arthritis, had just been diagnosed with a rare type of blood cancer related to the disease. She agreed to be my “arthritis hero” – the person I dedicated my efforts to. As I thought of her quiet suffering, the required fund-raising became part of a larger challenge.

In Lima I met the 35 fellow trekkers from across Canada participating in the experience. We were bussed to Cuzco – high in the Andes – where we began adjusting to the altitude. Struggling to breathe, I learned I would have to lug my own gear. To prevent abuse, the porters carried only our sleeping bags – along with tents, food and other camp necessities, of course. When I saw their loads, I stopped complaining.

The trek began at the start of the Inca trail. We hiked along the Vilcanota River beneath the snow-capped Nevado Veronica, through cactus gardens and fields of corn to the Llactapata ruins. The first night was surreal: a tent in a camp in the Andes; cool, beautiful, so many things the Calgary suburbs are not.

The next day was the most challenging. A six-hour climb took us through an area known as the cloud-forest, through some meadows, and over the Dead Women’s Pass (4,200m): its name concerned me. Then the climb became even more arduous – uneven, steep and irregular stone steps that seemed to go on forever. The song-phrase “I’m climbing the stairway to heaven” took the form of an earworm. Against my will, it sang and sang and sang in my mind.

As I approached the summit I could hear the cheers of those already on top; an indescribable victory was at hand. I saw a condor high overhead. Surely this was a sign that all was well. Certainly I now knew I could accomplish anything.

I expected the third day to be easy – after all, I had survived Dead Women’s Pass. Wrong. It was twelve hours of hills; I would have given anything to walk on level ground for just a few steps. We trudged to the ruins of Runquracay, over an associated pass (3,850m), then on to the ruins of Sayacmarca. We soon traipsed through a humid-forest where moss grows four feet deep, then into the rainforest, where we passed through several Inca tunnels.

This was the most beautiful day by far. The trail was alive with countless species of orchids and birds. At times I took off on my own to experience the beauty and joy of the Andes. I let it settle around me and wished I could hold the memories of this day for a lifetime.

The next day we began the final leg of the trek to Machu Picchu. After hiking along narrow Incan stone paths and a 50-step nearly vertical climb I finally arrived at the Sun Gate. I had reached my destination and was able to look down on the Machu Picchu citadel. At first it was shrouded in mist, but the clouds magically lifted and the view became spectacular: the lost city, surrounded by jagged mountain peaks. The trek was over. I had accomplished an incredible feat.

After descending into modern Machu Picchu, I phoned my family. The emotions of those moments were overwhelming, something I had not trained for. I cried and cried and cried. My daughter later described it as “Mom finding God”. Maybe she was right. Since then I certainly have a better understanding of what is important to me. My Machu Picchu journey gave me more than I can tell.

Last month I went off on another adventure with Joints in Motion – this time a marathon in Trieste, Italy. The challenges were different. The adrenaline flowed when I thought about how I needed to prepare for that event – the training, the battle with the nagging voice in my head that kept asking, “At your age can you become fit enough to run that far? In this lousy economy will you be able to raise the money?”

I put aside those doubts because I wanted to give something in the battle against arthritis. I wanted to support my arthritis hero, and my challenges were small compared to those she faces every day. Fund raising takes on a whole new meaning when you hear stories of how loved ones deal with this often terrible disease.

In my own small way I believe I have made a difference. Now more than ever, I believe we all can do that. This is my way.

Waste to Wealth

2009-06-08T11:47:00.006-06:00

Cleaning up after fossil fuels is a thriving enterprise, recession or not.

This article appears in the May 2009 issue of Alberta Oil Magazine

By Peter Mckenzie-Brown

Oil and gas fields, like homes, never stop generating trash. The difference lies in the volume and nature of the rubbish. From exploration through production and eventual abandonment of wells and plants after fossil fuel reservoirs deplete, energy waste management has grown into an industry in its own right.

Common oilfield wastes include oceans of brackish “produced water” that flow to the surface in volumes measured in millions of barrels and have to be separated from oil then put into safe disposal. There are other oil-contaminated materials that can be solid or liquid. The process of completing wells alone generates respectable volumes of drill cuttings and other solids that can no longer be left lying around.

Over the last 25 years, waste regulations have become steadily tougher, encouraging growth of a disposal business that has outlasted boom-and-bust cycles of energy prices and spread across the countryside in tandem with exploration and production operations. Since 1998, the number of producing wells across Western Canada has more than doubled to about 226,000.

Deepwell Energy Services is considered a small newcomer in the field but already has four facilities in Alberta, including a large new waste treatment facility south of Calgary, near Claresholm. Last year, the company acquired a 50 per cent interest in a water disposal facility near Midale, Saskatchewan, as the celebrated Bakken oil drilling play expanded across the southeastern reaches of the province.

Built upon assets that have been around for a while, three-year-old Deepwell organized itself as an income trust and went public just before a federal government decision dubbed by investors as the Halloween Massacre of 2006 to start taxing trusts in 2011. “Everyone in the trust system is now trying to figure out how to reorganize,” says Bob Ritchie, a veteran of more than 25 years in the industry who was Deepwell’s president until March 23.

The biggest players in oilfield waste have already made their moves: Newalta Inc. has reverted to the traditional corporate model. With the help of a large hedge fund sponsored by investors from the United States as well as Canada, CCS Corporation turned itself into a private company in 2007. For its part, Deepwell is using a five-year transition period allowed by the government to decide upon its next move.

Licensed to deal only with “upstream” exploration and production materials, Deepwell typifies the independent specialist in oilfield waste management operations. “It’s up to the producer to characterize and classify their wastes. Our facilities can accept a lot of waste streams, but some materials are not on the list of acceptable materials,” Ritchie explains. Lubricating oil used in exploration and production machinery, for instance, has to go to another specialist as a refined product. Production companies are responsible for tracking and reporting their waste streams to Alberta’s Energy Resources Conservation Board.

The watchdog agency keeps a close watch on waste disposal. “All our Alberta sites are ERCB-approved,” Ritchie says. “We use compacted clay liners, concrete berms, groundwater monitoring, water run-off and run-on systems – it’s all self-contained. The facilities are inspected quite often and very rigorously. It’s completely random. ERCB inspectors are out there at least once a quarter.”

Deepwell vice-president Brian Johnson describes how the company deals with basic waste streams in its Alberta facilities. “We purify produced water as much as we can, then inject the cleaned-up water down our disposal wells,” he says. These are drilled into secure underground formations of porous sedimentary rock capped or surrounded by harder stone, in structures that can be used as natural vaults for permanent storage.

Crude oil waste that has value is also scoured out of industry equipment. The material comes “from such sources as tank bottoms we clean up and dry up and either credit back to our customers, keep for our own account, or do a bit of both,” Johnson reports. The recovered oil must satisfy standard quality specifications before it can be put into pipelines. Cleaned-up solids like sand used in well “fraccing” or fracturing operations are shipped off to sanitary landfill sites.

While Deepwell is a small player in the sector, CCS Corporation is big. It has 48 facilities across Canada, from northeastern British Columbia to Manitoba, plus operations in Louisiana and Texas. Greg Dickie, a senior manager, reports that CCS deals primarily with dangerous materials.

“Wastes coming into our facility are called dangerous because they have a flashpoint, and they have a flashpoint because they contain hydrocarbons. The ERCB defines oilfield wastes, and there’s a clear line between hazardous wastes and dangerous wastes, and between dangerous wastes and not-dangerous wastes, and they fall within different jurisdictions,” Dickie says.

Hazco, a CCS subsidiary, operates a network of industrial landfills, bioremediation facilities and hazardous waste transfer stations. Hazardous wastes are regulated by Alberta Environment and mostly treated at the special treatment facility near Swan Hills. “Our business is to recover hydrocarbons from the wastes and then deal with the byproducts,” Dickie says. “The solids go to landfill, while the liquids go to deepwater disposal. We separate oil from water at our sites.” CCS also has terminals. “We are connected to a pipeline. We receive a producer’s oil, clean it up and send it through the pipeline.”

As economic recession slows down drilling and development across Western Canada until energy prices and bank credit make comebacks, is waste still a growing business? The consensus among the specialists is yes. At Deepwell, Ritchie says: “Last quarter we saw a downturn in exploration activity, and that is not likely to be good for the industry. Having said that, we do get a significant portion of our business from production, and production tends to continue even in a low commodity price environment.”

At CCS, Dickie says: “Up until most recently business was growing – right through 2008, in fact. We believe our industry will continue to grow even as the conventional industry begins to deplete. The types of services we offer through our operations are services that assist people in cleaning up, remediating and managing depleting assets. We believe our business will continue to grow even if the oil industry has the occasional decline.”

In the long run, conventional oil and gas production are in decline in Western Canada as geological reservoirs deplete naturally. Does that mean there will be less oilfield waste?

At Deepwell, Johnson isn’t so sure. “The lines between conventional and nonconventional production are beginning to disappear,” he says. “More and more effort is being put into making unconventional wells produce economically. As we use more unconventional resources, there will be greater volumes of waste. It is a growth sector.” He adds that as fields age, they tend to produce more water, and the need for water disposal will continue to grow.

Dickie sees additional opportunity within areas where there is still some infill drilling to be done. “As the percentage of oil in production goes down, the percentage of water and other materials, including emulsions and some solids like silts, goes up. That’s where our facilities become valuable to producers,” the CCS executive says. Emulsions or streams of mixed liquids and solids need to be treated as oilfield wastes.

Much water is also produced with some of the newer oil discoveries including Saskatchewan’s Bakken formation. Sometimes the water is used to maintain reservoir pressure. Sometimes it’s simply re-injected into a deep rock formation, to prevent surface- and groundwater contamination. Whatever the case, the volumes are increasing, and the job of getting rid of the stuff is requiring more effort.

At the ERCB, regulatory manager Susan Halla flags another reason the waste management business is going to continue to grow. Reading from the regulations, she describes oilfield waste as “an unwanted substance or mixture of substances that results from the construction, operation, abandonment or reclamation of a facility, wellsite or pipeline.”

Based on that definition, the industry creates wastes at all stages of operation – from construction to decontamination and reclamation. So there will be wastes to manage whether an operation is in the stage of development, oilfield decline, closure, abandonment or surface land reclamation.

Environmentalism is a growth force, says Ritchie, who saw the effects of public demand for cleaner industry first-hand as a project manager for TransCanada Corp. as well as during his tenure at the helm of Deepwell. “The movement to be environmentally responsible has continued to advance. Over time it’s likely to become more stringent, and that is actually likely to help us.”

It is a widespread industry consensus that western Canadian waste management regulations are among the most stringent in the world. “Over the last 15 years Alberta has been at the forefront of waste management, even compared to Louisiana and Texas. I don’t know of another regulator that has taken the same initiative as Alberta in developing waste management regulations,” says Dickie. Where CCS operates, “the ERCB is the leader. Saskatchewan and British Columbia are close behind, and Western Canada is at the front of the pack.”

At the ERCB, Halla stresses that Canadian regulators work with each other to make sure their regulations march in step. “We work with Alberta Environment to harmonize waste management practices within the province. We also have committees to harmonize practices in Western Canada, and also we are involved in national harmonization.”

Ritchie says there is momentum for improvements within the private sector. Annual inspections of facilities became routine at Deepwell, he recalls. “I think the whole industry has a heightened awareness of the need to meet or exceed regulations. Everyone is conscious of environmental stewardship. I see the whole industry trying to advance their performance.”

Canadian gifts help mobilize the disabled

2009-05-23T12:40:00.019-06:00

Crippled when she fell from a building 15 years ago, Ratchapon Deesala receives a gel cushion and a much-needed replacement wheelchair. Ratchapon lives with family in the community.

By Bernie McKenzie-Brown

For most of us, it is a simple matter to get out of bed and get ready to take on the day. Spare a thought, though, for those who can’t get out of bed because they are quadriplegic. Spare another for those who can’t get out because they need help dressing and getting into their wheelchairs. Then there are the men and women who need colostomy bags changed or urinary catheters replaced before their days can begin. This is reality for many disabled adults. For a fortunate few, life has begun to improve.

Last week physically handicapped patients and staff at McKean Hospital couldn’t hide their excitement and pure joy as medical equipment and other items started to arrive. The day’s delivery included two modified beds – one for a quadriplegic and one for a paraplegic – as well as a dozen new wheelchairs and 15 gel cushions.

This Canadian-funded initiative is helping transform life for young and severely disabled adults who live at Chiang Mai’s McKean Rehabilitation Centre. The 720,000-baht project has begun to provide help for 13 extended-stay rehabilitation patients and for outpatient clients who live in their community. Their ages range from about 16 to 42. Some have suffered since birth; others are often victims of motorcycle and industrial accidents.

Those who live at McKean share accommodation in tiny one-bedroom bungalows. All suffer from debilitating handicaps. They desperately need equipment and such aides for daily living as wheelchairs, braces, and prosthetics to make their lives more comfortable. Unfortunately, this equipment is too expensive for their families to afford. The hospital delivers good care in a caring environment, but it, too, is constrained by budgets.

An initiative of the Rotary Club of Chiang Mai West, the McKean Disabled Project’s main aim is to make it easier for the disabled to move about. In addition to purchasing high-quality wheelchairs, the Canadian project has provided funds for the purchase of motorcycles, which will be modified for use by wheelchair-bound patients. The project has also modified regular bicycles into tricycles propelled by hand.

The project has other aims, one of which is to help patients deal with painful bed sores. This terrible condition develops in those confined to beds or even wheelchairs. To manage this condition, the project has funded the purchase of gel cushions.

McKean’s residents show off new equipment and supplies, from hand-driven bicycles to gel cushions.

Funding began with a grant from the Rotary Club of Calgary Centennial. Several Canadians also made personal cash gifts. These sums were then matched by The Wild Rose Foundation, a funding agency sponsored by the government of Alberta (a Canadian province). This agency, which promotes charitable, philanthropic, humanitarian, and public spirited acts, thus provided the single largest contribution to the project. These sums were topped up by The Rotary Foundation, taking total contributions to the budgeted amount of 720,000 baht. The involvement of several branches of the global Rotary organization is tribute to the far-reaching philanthropy of the world’s largest service organization.

McKean Hospital has been serving the people of Northern Thailand for a century. It was established by a humanitarian missionary surgeon, James McKean, in response to the plight of those with leprosy in Chiang Mai. Still the centre for leprosy treatment in northern Thailand, today McKean also operates a program of extended general rehabilitation programs to treat the disabled. McKean Hospital’s disabled patients include those who live at the facility full-time; those receiving short-term treatment; and outpatients.

For some people, the simple act of getting out of bed in the morning is no simple matter. For some who live with this simple truth, simple generosity is bringing hope and the gift of greater mobility.

A Quieter Voice

2009-05-21T13:09:00.009-06:00

In the current economic slump, oil and gas companies are struggling to maintain their charitable activities. The graphic suggests the "third sector" of society.

This article appears in the June 2009 issue of Oilweek.

By Peter McKenzie-Brown

As this year’s GO-EXPO winds down, the Blues Brothers – a storied band – will perform at a dinner concert to benefit the Arthritis Society. Thus will the market economy enable a cultural icon to support an organization with no interest in profit, but which fights a disease that costs Canada’s economy $4.4 billion per year in lost work-days and health-care costs.

The Blues Brothers affair illustrates one of the countless ways in which the not-for-profit sector finds money to do things that contribute to civil society, but which fall outside the ambit of government and business. Charities are part of what some people call the “third sector” of society; the other two are business and government.

People trust the third sector more than they trust either business or government, according to research institute Imagine Canada (itself a not-for-profit). Third sector employees work for less than they might command in the private sector, and openly want to make society a better place. That attitude brings distinction to the sector.

One example is Steve McNair – formerly an executive vice president with the Canadian Imperial Bank of Commerce and now the Arthritis Society’s CEO. “The private sector should be supporting organizations like ours,” he says. “We supply programs, educational services and research funding. We advocate for better care, and we help people with the disease. A captain of industry would see that these are good reasons to support the Arthritis Society, since it helps his employees and customers. We don’t raise money to raise money,” he adds. “We raise money to deliver on our mission.”

Of course, health charities are only part of the not-for-profit sector, which includes homeless shelters, universities, food banks, opera companies, amateur bowling leagues, hospitals, service clubs, political parties, museums and houses of worship. Says McNair, “the third sector meets a whole lot of need, helping the other two sectors survive and thrive. For example, if our organization can find ways to cure arthritis, the first sector can function more effectively. So can government, since it would reduce the numbers collecting government benefits.”

Canada’s charitable sector, which represents eight percent of GDP, has a big impact on the economy. It’s bigger than the retail sector, bigger than manufacturing, bigger than automotive production. A million and a half people work in the sector directly – far more than in petroleum. Volunteers make up the equivalent of another two million full-time employees.

Perfect Storm
Like much of the rest of the economy, the charitable sector is caught in a perfect storm – less income as the need for its services grows. Although a recent survey of Alberta’s charities found that their experiences varied widely across the sector, several common worries were clear. Earned income, donations of stock, and corporate donations and sponsorships had already declined. Not-for-profits that charge for their services had begun increasing rates and reducing costs in an effort to maintain levels of service.

All of those organizations were uncertain about how their revenue sources this year and beyond would be affected. These worries received stark confirmation on April 7th, when the Alberta government’s budget – projected to run a $4.7 billion deficit – included deep cuts in discretionary funding for the sector. These developments are having a powerful impact on the sector.

Jim Kinnear – the founder of Pengrowth Energy Trust and a respected philanthropist – acknowledges that the financial crisis is putting a lot of pressure on the sector, but adds philosophically that “it just is what it is. There’s less capital available for charitable activities despite increasing demand for charitable services. Financial problems are affecting society across the board, and it’s putting a lot of strain on the system. Few people alive today have seen an economic downturn like this one – not unless they were alive in 1929. Hopefully, we will recover from this situation, although it may take a while.”

Although gloomy about the world’s immediate financial outlook, Kinnear believes strongly in the third sector. “Charitable organizations enable us to build for the future, for future generations. Helping to fund them has a lot of social value – it’s a value add that you just can’t quantify. The community should support and endorse not-for-profit organizations.” At present, his personal focus is the Kinnear Centre for Creativity. He has agreed to raise or personally donate $10 million to this new Banff Centre facility.

New Breed
Pengrowth uses an unusual community investment model. Unlike almost any other large publically traded oil company, it gives Kinnear – its president, chairman and CEO – virtually unlimited authority to make philanthropic decisions.

By contrast, TransCanada PipeLine’s Jamie Niessen belongs to a new breed of managers responsible for corporate giving, and he believes in the importance of his job. “Imagine a day where there are no volunteers,” he says. “No tee-ball, no hockey for your kids, no choir practice. Some things run by not-for-profits are even essential services” – women’s emergency shelters, for example. “We see our work with non-profits as essential. We are committed to being a good neighbour and an employer of choice,” and that means making strategic community investments.

Like other representatives from the petroleum sector, Niessen worries about the impact of the economic downturn on the not-for-profits. Within the sector “the biggest concern is in respect to endowed funds. (Largely because they are invested in equities,) endowments are taking a huge hit. I understand that non-government organizations are holding their budgets constant for this year. That will be reevaluated for 2010. On the corporate side, most donations budgets this year are being kept constant. Because TCPL grew as a company, though, we’ve had to grow our community investment budget.”

TransCanada increased this year’s budget from $6 million to $7 million. That amount includes direct support for a host of individual projects which Niessen groups into five general categories: civic investment, education, environment, human services and health. “We generally offer funding for 3-5 years, then move on,” he says. “What we want to know is, did we move the needle? Did we make a difference in building the capacity of the organization? That’s pretty important to us.”

To give an idea of the fine detail of TCPL’s contribution plan, subcategories for health include heart and stroke, diabetes, bones and joints and stress-related illness. Much like other large corporations, TransCanada calculates its giving by factoring in its participation in the United Way campaign and its unlimited matching gift program for employee donations in the $50-$1,000 range. “To encourage volunteerism outside of work, we also make a cash donation to match the time an employee donates.”

Talisman Energy is a representative player from the producing side of big oil. According to Reg Manhas, a vice president, “We haven’t cut budgets this year. We mostly have multi-year projects, so this gives us a smoothed out budget. Community investment is more important now than it was a year ago. Our reputation, our relations with our partners, our employees find this important. We don’t want to jeopardize relationships we have built up over the years.”

Talisman focuses on education and youth, with local programs distributed from company offices around the world. Like TCPL’s Niessen, Manhas waxes eloquent about the importance of the charitable sector. “There are so many things that would not occur in society without that third railing in society. Without not-for-profits to fill in the gaps, this would not be such an interesting place to live. Not-for-profits play a huge role in creating civil society – in advocacy, in so many ways. It’s an avenue to provide societal dialogue. It gives a voice to people who would otherwise perhaps not have a voice.”

Petroleum Giving
No one knows how much money the petroleum sector gives away each year, but the numbers are large. Imagine Canada, an institute that studies and provides research about the not-for-profits, reported that of 78 “oil and gas establishments” studied Canada-wide, 83 percent donate cash; 46 percent donate goods; 45 percent support employee volunteers; one third donate services.

According to Jocelyne Daw, an Imagine Canada vice president, “In Calgary businesses are more generous than are other companies across the country, and giving has moved toward partnership orientation. Companies work with their not-for-profit partners to try to achieve particular goals.”

She distinguishes between big public companies –Enbridge, EnCana, Imperial, Nexen and Shell, for example – and the industry’s many privately held companies. “Relatively speaking, our research tells us that publically listed companies are a lot more generous than privately held ones.”

With triple-negative precision, Daw says “There is not one person in Canada who is not affected by the not-for-profit sector. In terms of diversity, (the sector) has grown dramatically, especially in response to government decisions to download efforts from the bureaucracy to the community. Today there are groups for the environment, groups for literacy. Homeless shelters and food banks didn’t exist 30 years ago. If you lose your job you may get your EI, but if you want support in getting a job, you go to a non-profit. If you need food, you go to the food bank. When you need an outfit for a job interview you can go to one of these places and borrow clothes to dress for success. The diversity and scope and the role (not-for-profits) play is far greater than it was 30 years ago.”

The changes in the sector have led to big changes in the ways companies allocate their corporate gifts. “Thirty years ago companies would write the odd cheque and then they would be done with it,” she says. “Today, companies are so engaged in community that it’s a must-have that is fully integrated into the DNA of the company itself. There is greater and greater recognition that everybody needs to be working together in a different way, breaking down silos, coming together around common causes and around focused outcomes.”

While she acknowledges that philanthropy and government funding play an important part in the sector, Daw notes that a lot of not-for-profits are running small businesses to generate earned income. “There’s a lot of blurring of the lines between who does what and how it all gets done.” Adds TCPL’s Niessen, “particularly in Alberta, there are many efficiently run organizations with strong levels of self-generated revenue.”

Voice of Humanity
Not-for-profits are also changing by absorbing employees with corporate backgrounds; Steve McNair, for example, came out of retirement to lead the Arthritis Society. “The good work of third sector organizations is a form of compensation,” he says, “and that attracts many talented people. However, we must be aware that third sector organizations need to find better ways to challenge these educated, talented people so we can get the most out of them.”

McNair adds that complacent not-for-profits will be worst hit by the economic crisis. “Corporate Canada is looking for the best models to be effective in this environment. The not-for-profits have to do the same. There are more needs out there than ever before. To do well and stay funded you have to show your relevance. People will not financially support you if there is no reason to do so, so you have to make sure the reason is clear. If your relevance is there, you will sustain your operations or even grow.”

Fund-raising is now more important than ever before. For not-for-profits as for business, growth depends on revenue. The sector relies heavily on the income-generating drive of staff and volunteers, and the generosity of society – generosity which reflects a moral imperative. As a beneficiary of this sector, it matters not whether you attend a Blues Brothers charity concert or a rubber-chicken gala complete with silent auction; whether you write a cheque to your favourite charity, volunteer your time, buy at a thrift shop or purchase a Kinsmen raffle ticket. However you help, you are nourishing a better world.

In a recent presentation, Canadian Lieutenant-General and Senator Roméo Dallaire – one of the few celebrated heroes of the Rwandan Civil War – called non-government organizations “the voice of humanity.” Perhaps that says it all.

Blues Brothers Revival

2009-05-19T08:24:00.007-06:00

The Official Blues Brothers Revue will perform at a charity event for The Arthritis Society on June 12, 6:30 pm in the Big Sky Showroom at the New Stampede Casino (421 12 Ave. S.W. Calgary). Each hundred dollar ticket includes a $30 tax receipt.

The nine-person band stars Wayne Catania as Jake Blues and Kieron Lafferty as Elwood Blues.

Wayne and Kieron starred in the "OFFICIAL BLUES BROTHERS REVUE" during its recent premiere and live theatre run in Chicago IL. The play was written and produced by Victor Pisano and sanctioned by Dan Aykroyd and the John Belushi estate. As a result they can entertain you as the Blues Brothers Revue. with a 7 piece band including a 3 piece horn section.

Wayne and Kieron starred in the A&E Documentary Film -“Lost in Las Vegas”. This film aired across North America. They have been part of the cast of the renown “Legends in Concert” performing lengthy engagements at: The Imperial Palace in Las Vegas NV; and Biloxi MS; Bally's Park Place in Atlantic City NJ; The Sheridan Center, Toronto Canada; and Legends own theatre in Myrtle Beach SC.

Wayne and Kieron have starred and performed in a variety of shows and casinos: Premiere Cruise Lines - Florida and the Bahamas; Windsor Casino - Canada; Harrah’s Casino Cherokee, NC and Tulsa OK; Camel Rock Casino - Santa Fe, NM; McPhillip’s Street Station, Winnipeg, MB, Canada; and Taj Mahal, Atlantic City, NJ.

Performing as the Blues Brothers at corporate and private functions across North America and the Caribbean fill in the remainder of Wayne and Kieron’s Calendar: Singing the Canadian National Anthem at the Sky Dome for the Toronto Argonauts; US Cellular Field (White Sox); Phillips 66 - Nashville, TN ; Cysco Foods - Salt Lake City, UT; BDO Dun Woody; Air Canada; Suzuki Canada; McDonald’s Canada; and Nestles Canada, to name a few.

When not behind their sunglasses and in their fedoras….. Wayne is busy acting. You can see him in numerous television commercials (nationally and internationally) He has featured in such series as “Relic Hunter” , “Doc” and “Street Time” as well as a variety of short films and the mini-series “Mob Stories” for Bravo.

Kieron is an accomplished Musician singer songwriter and has written music for film and television including the soundtrack for "Lost in Las Vegas" He's released three CDs of his own material "Sensible Religion", "Seven Sisters" and "Boomtown" and guested on many other recordings.He's also been very busy doing voice over work for television and radio.

“Infectious and unbridled energy...Blows the roof off” - Chicago Sun Times

“Great energy & music. This IS Chicago. Even audience members with no rhythm are dancing”
WTMX The Mix

“While giving a great nod to the past, (this) is indeed its own show worthy of its own audience” Chicago Review

Just a ‘FRAC’ away

2009-04-18T09:52:00.009-06:00

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.

Productivity Alberta

2009-04-18T09:41:00.005-06:00

This article appears in the April 2009 issue of Oilsands Review

By Peter McKenzie-Brown

“It’s really tough to be less productive (than other companies) when times get bad,” according to Jim Rakiewich. “You and your competitors are both scrambling for sales, but prices become compressed. So the companies that aren’t really productive and have too much cost built into their products – they really get killed.” The president and CEO of Edmonton-based McCoy Corporation, Rakiewich was discussing Alberta’s productivity growth – or, more to the point, the lack thereof.

In economics, the definition of “productivity” is bloodless. It is a ratio comparing what is produced to what is required to produce it – usually an average expressing the total output of some category of goods divided by the total input of, say, labour or raw materials. Bloodless the definition may be, but the reality of Alberta’s productivity ranking is downright bloody: Dead last in labour productivity growth among Canadian provinces during the period 1997-2005. Growth was 1 per cent a year – below the national average of 1.4%, and well below growth rates for U.S. and European countries.

The Alberta government is concerned about this problem, and in March launched an agency – Productivity Alberta – to help improve provincial productivity. Rakiewich is one of a group of private sector CEOs who have agreed to serve as advisors to the agency. “If you want to stimulate productivity in Alberta,” he says, “it’s important to have those who are passionate about it on the governing board. That’s why I’m on the board.”

Alberta’s go-to person is Lori Schmidt, a senior director in the Finance and Enterprise bureaucracy. “When this process started,” she said, “companies were working flat out, didn’t have enough people, but despite working at capacity were finding their bottom line continually shrinking. That’s why we started to look at the importance of increasing our productivity. Today, with the economic conditions changing, there’s probably even more need for firms to look at their efficiencies. This doesn’t mean getting rid of people, but utilizing our people to their best ability. Are we utilizing all the inputs and resources and processes that we have so that we can continue to compete?”

Schmidt describes the new agency sees itself as a “path-finding service” which will offer two levels of service to any business that asks for it. “For free, we will offer a preliminary assessment to help them with their operational efficiencies, perhaps by directing clients to online tools. Right now, people may know they have problems but don’t know where to begin. That’s the free part.” Adds the ever-enthusiastic Jim Rakiewich, “You don’t really pay for someone to help you analyse your processes and offer advice. In effect you are getting free consultants, and these are really sharp guys. Where your costs come in is in implementing those ideas.”

“The second part,” continued Lori Schmidt, “is to connect (our clients) to tools and programs and services that are already out there in the marketplace. We want to be the connection point” between organizations that need to become more efficient and resources they can use to achieve that aim. “This is available to any business, but we are really focusing on value-adding businesses – anyone who produces a good. Manufacturers and their supply chains, for example, but also small and medium enterprises. In Alberta, that means businesses with 100 employees or less. Those companies have been doing a lot of work in the oilsands.”

According to the new agency’s slick new brochure, “Productivity Alberta brings together the talents and efforts of people and organizations across the province to tackle productivity challenges and to provide a direct point of access to productivity enhancement offerings. This industry-guided, not-for-profit corporation works in concert with government, industry, academia, associations and communities throughout Alberta to address productivity challenges.”

Jim Rakiewich has bold opinions about the importance of higher productivity and about the reasons why Alberta’s recent record has been so dismal. “Those who are more productive have lower input costs. If you are not really connected (to the importance of increased productivity), you have a lot of waste in your system.”

Alberta’s low productivity growth has had a number of causes – most importantly the tight labour market. There is also a geographical component to Alberta’s poor recent performance. According to Rakievich, “North America is not very competitive compared to the rest of the world, and Canada generally performs worse than the U.S. Alberta just hasn’t been very focused on becoming more competitive” – to a big extent because of the tight labour market. “Rather than finding the right skill sets for jobs on offer, (companies in Alberta) have been hiring warm bodies and trying to bring them up to standard.” He adds that, because manufacturing is such a small part of the provincial economy, there is less experience to draw from than in, say, southern Ontario.

Rakievich’s final comment pertains to the threat of global markets to Alberta business. “Markets are really global in nature, now, and outsiders are coming in to steal market share. This is forcing us to realize someone is going to eat our lunch if we don’t smarten up.” Heed this.

In the Centre of the Storm

2009-04-03T21:31:00.007-06:00

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.”

Contractor Survival

2009-02-26T19:22:00.010-07:00

The infrastructure business shifts as the economy reels

This article appears in the March 2009 issue of Oilsands Review; photo from here.

By Peter McKenzie-Brown

Infrastructure reflects the times in which it is created. In Alberta, a literally off-the-wall example can be found in the control panels at the Turner Valley Gas Plant – a mothballed facility now being prepared for restoration as a historic site. Made in Germany during the 1930s, its control panels sport swastikas welded into the steel – a reflection of the political turmoil of the day.

The network of firms that create and maintain roads and industrial facilities make up the infrastructure business. Combined, they represent a huge segment of the modern economy. In Alberta in recent years, this business has been increasingly dominated by efforts to develop oilsands infrastructure, but since the beginning of the global financial crisis that has changed.

Infrastructure firms with contracts to design, engineer and construct massive projects like Petro-Canada’s postponed Fort Hills project have led to layoffs in professions where, a year ago, the demand was almost desperate. However, these cases have not yet been large. Indeed, many companies sense a need to rebalance the sector. Once that’s done, they say, demand for new and revitalized infrastructure will remain strong. Indeed, there is even a sense among some firms that both the province and the oilsands industry itself can benefit from the breathing room the slowdown is providing. Perhaps the irrational exuberance of the last few years really needed a pause for serious contemplation.

Spider webs and feeding chains: The infrastructure business consists of a spider web of design, engineering, manufacturing and contracting firms working with owners to build and install roads, pipes, wires, vessels and related technology. And in recent decades, the business has changed in dramatic ways. For example, said Bernie McAffrey, “It used to be that electrical and instrumentation was maybe 10 percent of the cost of a compressor station, say. Today that part of the equation I would guess is over 23 percent. A typical project now needs more than twice as much automation technology as it did a couple of decades ago.”

McAffrey founded Ber-Mac Electrical and Instrumentation in 1981. As last year wound down, a largely unnoticed item in the news – the acquisition of Calgary-based Ber-Mac by Swiss multinational ABB – received regulatory approval to proceed. More than three times larger than ABB’s previous western Canadian operation (built up through a combination of organic growth and small acquisitions), the new entity is an especially big player in the oil patch. McAffrey is now a vice president of ABB Ber-Mac, which employs about 750 technical and field people in the three western provinces, including 715 in Alberta.

Even though the financial crisis became apparent while the acquisition was in the works, ABB did not pause in its efforts to acquire the Canadian firm. According to ABB Ber-Mac’s new vice president and general manager, Marcus Toffolo, “This acquisition was not for cost-cutting but for growth. Long term, we may take skills out of Alberta to the rest of the world but that’s not feasible just yet because of regional demand.” He added, “When we looked at this acquisition (we were impressed with Ber-Mac’s) basic business model of vendor neutrality, regional distribution, customer satisfaction. We don’t want to change that.”

In broad terms, the infrastructure business applies technical and scientific knowledge and uses resources to build systems that benefit the economy. It employs a feeding chain that begins with minnows – firms of just a few technical staff – but ranges up to large multinationals like Zurich-based ABB. That global giant has more than 100,000 employees and annual revenues in the tens of billions of dollars.

McAffrey, whose company has successfully risen from the bottom toward the top of the feeding chain, has seen huge changes in the entire business since he set up his firm. “The amount of installed technology in Alberta has grown by leaps and bounds. In the beginning there were only two oil sands plants. In terms of magnitude and sophistication (infrastructure in Alberta) has grown dramatically.” The good news for the business is that these huge amounts of installed infrastructure have to be maintained and continually upgraded. Nowhere is this truer than in the oilsands.

Colleaux Engineering vice president Al Striga sketches out the size of the challenges. “It’s very unusual to see so many huge facilities packed into such a small area as (the Fort MacMurray area). If you throw in the need for cold weather operation, you don’t see anything else like this anywhere in the world. You have to specify cold-weather compatible equipment, instrumentation and metallurgy. Enormous pieces of equipment have to move at temperatures ranging from -40 to +30, and everything has to be reliable. The challenges are huge.”

His company is one of the minnows at the bottom of the feeding chain, but has done some oilsands work. “Large firms get the project. We get involved as subcontractors to the big firms. We get awarded a module or component of a facility.” Like other firms, Colleaux Engineering has been hit by the postponement of oil sands projects. “Within 72 hours of the time Fort Hills went down, we got a call saying our part of the action was all over.”

Like everyone else interviewed for this article, the principals at Colleaux Engineering are optimistic about Alberta’s medium-term outlook. “We’re hearing everything from doom and gloom to an optimum environment,” said Striga’s sidekick and the company president, Steve Colleaux. “We aren’t too worried about the future. We’re in an interesting part of the market. We don’t need a lot of work to stay busy. A company with a thousand people needs 200 hours per person per month. That's a lot of hours.” His 20-year-old company only employs ten technical staff.

What’s hot, what’s not:Although many oilsands projects are disappearing into the black holes of indeterminate postponement, opportunities for the infrastructure business in Alberta still abound. The amount of effort needed for infrastructure maintenance is vast. Consequently, there will be a rebalancing of the infrastructure industry in the province, with the slack from project cancellations being shifted toward these other areas.

The construction of new oil sands projects is an area of disappearing opportunity, and the business is alive with reports of large-scale oil-sands related layoffs. Some projects are staying the course, however – notably Imperial Oil’s Kearl project.

According to a source who requested anonymity, “Kearl is going ahead like crazy…. Rather than scaling back their efforts, (the project team at Imperial) are doing the opposite. They are spending about $1.5 million dollars per day on more than 1,000 engineers to engineer the hell out of it right now while contract engineers are cheaper. (Because of parent ExxonMobil’s strong cash position), they have the option to be greedy when others are frightened and frightened when others are greedy. In a couple of years when the competition is just starting to re-examine their preliminary plans, they will be digging holes and welding steel based on contracts formed in a down market.”

Despite the cancellation or downsizing of some projects (notably two Enbridge proposals to take bitumen to US markets via Ontario and Quebec), transmission is still a solid area of growth. So is the creation of new infrastructure in areas where oilsands operations are strong.

Asked how the shifting sands of the bitumen business have affected his business, Mark Wrightson – president of Whaler Industrial Contracting – was direct and to the point. “We submitted a proposal (for a SAGD project) to Connacher Oil and Gas in the fall. Just prior to the contract being awarded, the project was shelved. When Petro-Canada postponed Fort Hills, half a dozen projects fell off our project board.” However, he said, “our primary focus is on transmission – pump stations primarily. Eighty percent of the work we are doing is in transmission infrastructure, and Enbridge, TCPL, Husky and others have projects to take away bitumen. There is such an infrastructure deficit in take-away capacity that we expect these projects to remain strong.” The downside, such as it is, is that “there will be a lot more competition for that kind of work.”

Similarly, built-up infrastructure needs to be maintained, and basic oilsands maintenance presents tremendous opportunities. According to Pinal Gandhi, a project manager with Whaler, “It’s not going to stop. Syncrude and Suncor have old plants. They have a tremendous need for maintenance. They will cut down on the expansion side, but they will continue to put a lot of money into maintenance.” His enthusiasm is infectious. “Until recently (Suncor’s) upgrader was operating at 150 percent of capacity. Pumps were worn out” and so was a lot of other equipment. The company “wanted production. They didn’t care about the cost. The downturn is an opportunity to slow down on production but put money into maintenance.”

He adds that “Fort MacMurray itself has a huge need for infrastructure. They need (highway) flyovers, all kinds of supporting facilities. Anyone who works outside of the city has to spend a minimum of three hours per day to commute to work.” Again, he believes that the slowdown in oilsands development provides the opportunity for the infrastructure business to work with the city and the province to upgrade roads and develop other infrastructure. Wrightson concurs: “It’s embarrassing how little has been invested in infrastructure at Fort MacMurray.”

A construction manager with the Trotter and Morton group of companies, Mike Dickson has the ironic motto that during construction “contractors are merely an inconvenience to someone else making money.” In today’s environment, he says, “long-term projects that are three to four years out are being cancelled. (That is why our company) sees opportunity and is more interested in the smaller projects involving the necessary infrastructure maintenance and not mega-expansion.”

In general, newer infrastructure employs fewer people than the systems it replaces. According to Colleaux Engineering’s Al Striga, it develops in a virtuous cycle. “The more automation you implement, the lower the cost becomes, and the more automation you want.”

An oilsands automation engineer with one of North America’s largest engineering firms (he requested anonymity) discussed the potential of recent breakthroughs. “Digital automation has been around forever and a day, but the fact remains that if you go to any plant anywhere in the world, you will find that 80 percent of the loops are on manual. So we are not doing our job correctly. Ideally, you should have a plant that operates on automatic 100 percent of the time. We’re missing the boat somewhere, and I just can’t put my finger on why. If we can put more loops on automatic, we can approach that Holy Grail.”

As beguiling as such a development sounds, it’s going to be a long time coming. As Steve Colleaux acknowledges, automation (one of his firm’s specialties) controls processes better than people. “In a perfect world, automation can do everything. However, in the real world things aren’t like that. The system may come up with an alarm that says ‘We have a malfunctioning pressure transmitter. We can’t see what’s happening in this vessel.’ You need operators around to deal with those real-life problems.”

There are other problems in the wind. According to Trotter and Morton’s Mike Dickson construction used to be founded on the “three-legged stool of owner, engineer and contractor.” That changed, he says, with the advent of engineering, construction and procurement (EPC) teams serving as project managers. “Contractors are now the labour, which really means the risk.”

He believes relationships between owners and contractors may become strained in the emerging marketplace. “The sustainable win/win contract philosophy we have been experiencing (which was based upon the owner’s need to woo contractors and the contractors’ need to see repeat or possibly evergreen contracts) has given way to the more win/lose style of heads-up construction.” This, he says, may result in a more litigious environment.

What will mark the infrastructure development of the next few years? Nothing like the swastika in the gas plant – that much is for sure. Perhaps the mark of infrastructure during the next few years will be welded instead on the bottom line. “In the boom,” said Whaler Industrial’s Mark Wrightson, “just-in-time construction didn’t work at all – in fact, it rarely works well at the best of times. You couldn’t get deliverables on time. Everything was delayed. But today you can get turbines and gensets (electrical generators combined with engines). They are now being manufactured for a smaller market. A lot has changed.”

For the infrastructure business, perhaps the real mark of this changed era will be slower-paced, lower-cost, more orderly development. Surely that isn’t all bad.

Getting More for Less

2009-01-27T18:41:00.008-07:00

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

By Peter McKenzie-Brown

North America’s natural gas business is going through fundamental change, but Alberta’s conventional gas sector isn’t well positioned to compete. As Canadian Natural Resources' president Steve Laut told a conference call when he was discussing his company’s deep cuts in capital spending for 2009. “We are drilling (for gas) in B.C. but cutting back in Alberta. The oilsands can withstand (Alberta’s) higher royalties, and on the oil side, the government got it right, but they missed it on gas. Alberta is the worst place for gas development in North America, and likely the world.”

Why are things so bad? Part of the problem is the province’s much-maligned new royalty regime, which sapped the industry’s motivation to invest in the province’s traditional source of supply, conventional gas. In November the province gave explorers the option to pay royalties at the old rate for four years, provided the wells were more than 1,000 metres deep and spudded after the New Year. This eleventh-hour tinkering “will have an improvement on activity levels in the province,” according to Tristone Capital vice president Cristina Lopez, “but it will not improve the cash flow outlook for companies that are going into a difficult commodity-price environment.” That’s a major reason for the decline in conventional exploration and development.

“There’s been a tendency to assume that as long as we have gas opportunities in Alberta, people will come here to invest their money to get it out,” said Dave Russum, who is head of geosciences at AJM Petroleum Consulting. “We should not automatically assume that will be the case. When you change the royalty system and make other such changes, then investors will go to other opportunities where they have other advantages – closer to markets, or where there’s a better royalty regime or a lower cost structure.” He notes that until this year there has been an absolute correlation between wells drilled and gas prices: When prices went up, so did the number of wells. This year, prices went up but drilling in Alberta went down. Was this an unintended consequence of Alberta’s new royalty regime?

Probably, but other economic factors are also at play. Geological targets are changing; costs and prices are fluctuating for reasons that have nothing to do with natural gas activity levels (think oilsands); new technologies are fundamentally changing the economics of development; and issues related to environmentally responsive, full-cost accounting are playing an increasingly important role in project approvals.

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

That country, whose conventional gas production peaked in 1972, began focusing on unconventional natural gas in the 1980s. Today, the Lower 48 states are producing gas at rates near their 1972 peak. Increasing supplies from unconventional gas fields and coal-bed methane are outstripping by far the decline from conventional sources, and LNG production from Alaska is possible. A number of commentators have suggested that these factors could soon make the United States again self-sufficient. An obvious implication is that Canada must develop alternative markets to help create price security.

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

The cost of developing and delivering Western Canada’s gas varies greatly from region to region, but the WCSB is still one of the world’s most expensive onshore basins to develop. A recently released National Energy Board map illustrated the geographical diversity in cost related to developing and producing these gas supplies. The average cost of gas supplies ranges from $11.18 per thousand cubic feet in the BC Foothills to $6.58 per thousand in the adjacent Alberta Deep Basin.

For gas producers and analysts, the critical factor in the NEB analysis was that gas prices need to average $7.88 per thousand cubic feet for producers to generate a risked after-tax rate of return of 15% in this basin. Given an average Alberta spot price for natural gas around $6 during 2007, the report intoned, “the average economics for new gas development in western Canada were marginal.... These results are consistent with the general impressions expressed by industry players about the tight economics of new gas....”

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

Even though unconventional gas is more expensive to develop than conventional production, that’s where about 60% of natural gas activity is going. Like the US, which made great progress developing unconventional gas during an era of lower prices, Western Canada is developing these resources in a period of price/cost disequilibrium – that is, lower prices and higher costs. This is counterintuitive. In classical economics, adversity in the gas industry – the lower margins and riskier business environment of the last few years, for example – would force the industry to drive down costs and increase efficiency.

The U of C’s Mansell squelched that assumption, first zeroing in on the dynamic relationship between price and cost. “Costs drive prices,” he said, “but prices also drive costs.” Supply costs go up and down depending on activity levels, rig and services availability, materials, labour, technology, changes in well productivity, changing drilling targets, and changing fiscal and tax regimes. Crown land prices go up and down as well.

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

Technology: While companies employ cost-cutting measures (shutting in higher-cost gas supplies during tough times, for example), Mansell makes the case that real efficiencies are more likely to arise in periods of relative prosperity than in periods of economic adversity. “In a tight margin environment, would companies put more R&D and technology into increasing efficiency? It’s not clear. They actually have more free cash to play with in a higher price environment (and are therefore in a better position to increase efficiency). However, if a company is financially healthy, it can even increase profits in a low-cost environment by applying new technologies.”

In other words, greater efficiency in the petroleum sector comes mostly from technology –improved drilling, seismic and other technologies used in exploration and development – along with the obvious benefits of such capital infrastructure as plant and pipeline. According to Mansell, “It’s a dynamic environment. Mostly because of better know-how, over longer periods of time the industry is getting 1.5% to 2% more output per unit of input each year.”

How is that happening? AJM’s Dave Russum puts a technical slant on things. “Per well costs are higher than in the past, that’s true. However, we now understand that in certain kinds of gas resources we can greatly increase productivity by increasing drilling density in lower-quality gas reserves. You need to be able to fracture the maximum amount of the reservoir.”

So important has this trend become that it is contributing directly to the reduced number of wells being drilled in Canada. This year, nearly 40% of the wells drilled in Canada will involve horizontal or directional drilling – twice the level of ten years ago. For the first time, First Energy Capital said in a recent research note, the number of horizontal wells will match the number directionally drilled, and more and more of well costs are in completion technology.

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

As the U of C’s Mansell points out, “Current costs may not reflect future costs. As you learn more about the resource, costs could come down substantially – not only the cost of production, but also the cost of finding new reserves.” Recent innovations in fracing wells illustrate how this can happen.

Companies have made great strides in increasing the number of fracs they can make in a single horizontal well. Horizontal wells drilled into shale reservoirs now average eight fracs each – an astonishing improvement from only ten years ago, but one that is causing potential bottlenecks in the system.

According to Kevin Lo of FirstEnergy Capital, to fracture just one of the Horn River shale gas wells in north-eastern BC, you need a fracturing crew equipped with more than 30,000 horsepower of compression. To put that in perspective, in Western Canada perhaps 800,000 horsepower is available.

“We do not believe that there will be sufficient capacity to perform all of the jobs necessary, should (BC’s Horn River and Montney shale gas) plays grow,” he said in a research note. He also worried about the logistics of bringing in enough propping agent: fracturing a single horizontal well in these reservoirs can require up to two thousand tonnes of sand.

Stewardship: Another area where big changes are happening, of course, is in environmental practice and policy. Take the case of EnCana’s application to drill in the Suffield National Wildlife Area, where a hearing began last September.

The gas at Suffield is shallow, biogenically-derived gas in mixed sand and shale sequences. Since it is not generated in the same temperature and pressure systems that create conventional hydrocarbons, shallow biogenic gas is an unconventional variety. The Milk River and Medicine Hat sands of south-eastern Alberta and south-western Saskatchewan are classic examples of this type of unconventional gas. This was the first gas produced in western Canada. It is continuously gas-producing, and it is the largest gas-producing region in the WCSB.

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

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

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

The issues are complex, and the ERCB has a long history of listening carefully to all sides and dealing with these situations fairly. However, this is only right. As the U of C’s Mansell explains, economic theory supports the environmentalists’ point of view.

“In theory,” he says, “you want to be as close as possible to full-cost and-full benefit accounting from a social point of view. Policy decisions should incorporate all incremental benefits and the incremental costs – including costs and benefits that don’t necessarily show up in the market. How you estimate that isn’t an easy question to answer, but your accounting should be based on a benefit-cost analysis.” Since a poll by the provincial government found that only 16% of Albertans believe the province does a good job of looking after the environment, this story has legs.

So there you have it. Alberta may be “the worst place for gas development in North America.” However, the WCSB remains an important gas basin, and activity throughout the region is helping illustrate gathering industrial trends. On the policy side, issues related to full-cost accounting will likely take years to iron out – but at least they are being heard.

The Case against Dirty Oil

2009-01-17T10:25:00.016-07:00

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

By Peter McKenzie-Brown

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Upgraders on the Backburner

2009-01-09T08:47:00.012-07:00

Has Alberta priced itself out of the market?

This article appears in the January 2009 issue of Oilsands Review

By Peter McKenzie-Brown
The fall of 2000 was extraordinary. The global financial crisis suddenly went into warp speed. Nations desperate to soften the blow began an offense against collapsing capital markets but, their efforts notwithstanding, credit became scarce and more expensive. The business and political atmosphere quickly took on a sense of urgency, alarm and panic which will certainly take many months and possibly years to resolve.

The Fort Hills Energy Limited Partnership (led by Petro-Canada) dropped a bomb into that painful environment. The joint venture’s preliminary engineering and design work had found that estimated costs for the oilsands project had risen “considerably.” Petro-Canada said that. “Initial indications suggest that the estimated capital costs for the Project, as currently conceived, have increased in the range of 50%.” That would put the cost of Fort Hills – which will include an integrated oilsands mine and bitumen extraction plant near Syncrude and an upgrader near Fort Saskatchewan – at $23.8 billion.

There was a great deal of consternation on the news. This combined with a general meltdown in equity markets, and there was blood on the streets. Petro-Canada’s stock rapidly lost six years’ worth of share-price growth.

A few days after Petro-Canada made its gloomy announcement – and still during this period of freefall – EnCana and partner ConocoPhillips announced that they had begun construction of new upgrading equipment at their Wood River, Illinois, refinery. The $3.6 billion project would add a 65,000 barrels per day coker to help process growing supplies of heavy crude oil; increase total crude oil refining capacity by 50,000 barrels per day to 356,000 barrels per day; more than double heavy crude oil refining capacity to 240,000 barrels per day; increase clean product yield by 10 percent to 89 percent; and eliminate 40,000 barrels per day of low-value asphalt production.

The two companies had already begun expansions at their Foster Creek and Christina Lake SAGD joint ventures, where EnCana expects bitumen production to increase from 70,000 barrels per day at present to about 180,000 barrels per day in 2012.

Out of the market? In response to these parallel announcements, financial analyst William Lacey of FirstEnergy Capital came out with a particularly thoughtful analysis in which he asked the question, “Has Alberta priced itself out of the market?”

At the risk of oversimplification, Lacey makes two points. First, economically speaking it makes far more sense for companies to develop SAGD (steam-assisted gravity drainage) projects to produce bitumen than to develop new Syncrude-style mines. Second, it makes economic sense to have that resource upgraded at US refineries. Following the logic of these ideas, he suggests that the best way to develop Canada’s oilsands would be to modify North America’s pipelines and refineries in such a way that more bitumen can be taken out of Alberta for upgrading and refining.

Again at the risk of oversimplification, two numbers show the stark contrast between Fort Hills and the EnCana joint venture. The cost of producing a daily flowing barrel of oil through the Fort Hills project is in the US$180,000 range. The price EnCana/ConocoPhillips will pay to reach the same goal is about US$60,000 – consisting of $22,000 for bitumen production and $28,000 for refinery modifications.

SAGD projects also have the advantage of a very small environmental footprint. According to EnCana’s Alan Boras, the Christina Lake SAGD project “all in is a quarter section – the size of what traditionally was a small mixed farm. You can concentrate (steam-generating and other producing) facilities and have multiple wells from a single pad. Your fingertips are underground, although they stretch out in all directions. They aren’t visible from the surface.”

In an interview, FirstEnergy’s William Lacey also acknowledged the importance of the system’s small environmental footprint. He added, “The joy of SAGD is its scalability. You can develop it over time, and you can use cash flow to help lever into the next phase.”

“SAGD has its risks,” he acknowledged “– water treatment, reservoir quality, technical completions. There’s a lot more risk there than there is in mining. Mines, however, are all-or-nothing. You don’t produce your first barrel until you weld the last vessel in place. Capital cost inflation of (mining projects) means they have priced themselves out of the market. If you can just get this stuff (bitumen) down to the US Gulf coast, with some minor modifications to existing refineries there you could inexpensively upgrade the stuff.”

He added, “There’s a finite amount of this you can do, of course, because of the need for diluent to ship the bitumen.”

Integration: In a sense, Lacey’s commentary only offers another economic argument for the trend toward continental integration that has been developing for decades. A recent study by consulting firm Wood Mackenzie argues that this movement is already well underway. According to the firm’s Lindsay Sword, “supply of Canadian oilsands products (to the Gulf) will increase by 2 million barrels per day between 2007 and 2015; half of this growth will be in Canadian heavy crude blends.” She added, “Refinery projects targeting Canadian heavy blends that we expect to proceed are aligned with our forecast of additional supply: Canadian heavy blends supply will increase by 1 million barrel per day by 2015, and projects that are planning on processing heavy blends will increase by 1.1 million barrels per day.”

In practice, this means the continental petroleum industry is on track to realize efficiencies by having greater volumes of bitumen upgraded in huge, American refinery complexes, as in the case of the Wood River project. However, Lacey acknowledges that the opportunities to realize such great efficiencies as those at the EnCana/ConocoPhillips project “are fairly limited.”

“While there may not be any more opportunities to bring on upgraded oilsands product capacity at around $60,000 per barrel per day (as the EnCana project is doing), the latest data points reinforce our opinion that … modifications to North American refineries and expanded pipeline routes to handle bitumen provides significantly better returns on investment than building upgraders in Alberta, while adding barrels through a new SAGD project appears less expensive than from a new mine.”

This notion is not popular with Alberta, of course. Alberta Energy spokesman Jason Chance pointed out that the government is quite interested in keeping value-added processes in the province. Over 60 per cent of Alberta’s raw bitumen is upgraded in Alberta, and provincial energy strategy aims to increase those volumes. Chance acknowledges that Alberta is a high-cost environment, and that there are “labour and supply challenges,” but says the province is nonetheless committed to increasing the amount of bitumen upgraded in the province.

One approach is the province’s “royalty-in-kind initiative.” The province is evaluating expressions of interest from players who would like to upgrade Alberta’s royalty bitumen within the province. Royalty bitumen – bitumen the province will one day accept in lieu of royalty payments – would become a secure source of supply for the successful refiner or upgrader. Taking on this supply would eliminate their need to produce the stuff, but the successful company would have to upgrade it within Alberta’s borders.

Perfect Storm: At the time of the interview with Lacey, the business news was all-crisis, all the time. Oil prices were half their all-time highs, and energy stocks were hovering near multi-year lows. A discussion of the credit crunch was inevitable. Lacey began with this salvo: “The cost of capital is such an important part of (share-value) evaluation, and in this environment risk has therefore gone up.”

Think about it. The cost of developing an upgraded flowing barrel per day at Fort Hills costs $180,000. What can you compare that to in the open market? Based on stock market evaluations on the day Lacey was interviewed, if you decided instead to buy a public oilsands company, you could buy Canadian Oil Sands Trust – the major shareholder in Syncrude – for $100,000 per flowing barrel. You could buy Suncor for $90,000 or Imperial Oil for $80,000. As these numbers show, stock markets driven by panic are not efficient.

“We’re going through some short-term gyrations in oil prices and there are some global recessionary issues,” said Lacey, “but we will work our way through that. Last time I checked, (the global petroleum industry was) having some difficulty in replacing barrels, and this slow-down is making that problem even worse. We’re going to be in an even worse position coming out of it.” Looking into the longer-term, that will make production from Canada’s oilsands even more valuable.

In the meantime, Canada’s petroleum industry may soon be in play. In the case of EnCana, that risk is greatly reduced. “The EnCana split (into separate oil and natural gas companies) didn’t make any sense because it put assets into this market at such depressed values just opens yourself up for potential acquisition,” Lacey argued. “I’m not a protectionist, but I do want to make sure that companies that are sold are recognized for their value.”

However, “this is a perfect storm for some of the very large-cap companies to use their balance sheets to buy up assets.” One potential acquisitor is China, with more than $1 trillion in foreign currency reserves and an express desire to buy energy and other resource assets around the world. “They’re not stupid,” said Lacey, “they’re opportunistic. How opportunistic (they can be) is the question. (Western) governments are aware of their intentions. Will they allow them the opportunity to buy core petroleum assets? I would argue ‘No.’”

He points instead to super-majors like Exxon Mobil as potential predators. The world’s top five publically traded oil companies finished 2008’s third quarter with $62-billion in cash and annual cash flow of $232-billion. Compare that cash on hand to the depressed market capitalization of Canada’s premier energy companies at the beginning of December: EnCana ($39 billion); Husky Energy ($26 billion); Canadian Natural Resources ($24 billion); Imperial Oil ($33 billion); Suncor ($22 billion); Petro-Canada ($14 billion); Talisman Energy ($10 billion); and Nexen ($11 billion).

The credit crisis into which Petro-Canada and EnCana made such dramatically different announcements has already become a yeasty period of adjustment – not only for the oilsands business, but for the industry as a whole.

For example, one sunny day in late October, PetroCanada announced that it would delay the Fort Hills upgrader, constructing the mine instead. That same day, Suncor announced that cuts to its capital spending would delay completion of the Voyageur upgrader by a year. Other large projects – Lacey suggests Imperial’s Kearl oil sands project as a real possibility – may be placed on the backburner. The shift from mines to thermal projects will probably take on new importance. Perhaps more upgrading will be farmed out to US refiners at the expense of an expanded upgrading sector within Alberta. Questions of corporate survival and consolidation will arise and need to be answered. Some companies will cease to exist, and new or merged entities will take on leadership roles.

For however long it lasts, the global credit crisis is likely to coincide with a period of rapid change for Canada’s petroleum industry. Perhaps the aftermath of the 1986 oil price shock – when prices suddenly dropped by more than two-thirds and interest rates were in double digits – is the most recent analogue for what to expect. In those days, capital shortages changed everything, quickly.

Because of high costs, primitive technology and relatively plentiful conventional oil prospects, in the post-collapse ‘80s the first projects to go were in situ oilsands developments. Because they now offer relatively inexpensive, predictable, long-term flows, this time they might be the ones most likely to stay in prospect. “I would speculate that (companies like ExxonMobil are) less fussed about where their share price is today,” said William Lacey. “They are more fussed about long-term prospects for replacing reserves in their portfolios....This is a huge opportunity time, but it requires people who have longer-term vision.”

The Squeeze is On

2008-11-20T08:17:00.005-07:00

This article appears in the December 2008 issue of Oilweek.

By Peter McKenzie-Brown
“I’d rather you didn’t mention the company by name. In fact, better not mention my name, either, because the story is a disaster. We don’t want (the information) out yet.”

From an officer in a small oilsands company – call him Don Fischer, – that comment sums things up for many juniors. Fischer argues, however, that the recent meltdown in global financial markets is only the killer blow in a credit squeeze within Canada’s petroleum sector that has been developing for three years.

A credit squeeze occurs when interest rates rise and new credit is difficult to access. At such times marginal borrowers, or those who have borrowed at the end of any debt-induced asset bubble, get squeezed out of further borrowing. A contraction in the growth of money supply occurs, triggering a slow-down in the growth of previously inflated assets purchased with debt.

Such a squeeze is a natural part of the economic cycle. This time, however, it has taken the form of a whirlwind that threatens to leave behind an astonishing combination of devastation, cataclysmic change and opportunity.

For some of those who anticipated the problem, there were ways to protect themselves. For example, Pennwest Energy – Canada’s largest conventional energy trust, with anticipated cash flow this year of $2.8-$3 billion – saw a year ago that something was happening, and restructured its debt in response. According to president and COO Murray Nunns, “We termed out a portion of our debt into private long-term notes and Pennwest isn’t drawing on the full extent of its bank lines. We thought that was prudent given the conditions that might arise in the banking sector.” Of course, many companies did not have the foresight or the financial resources to protect themselves.

Triple whammies: According to Fischer, even before the global crisis hit many companies in the sector were having credit problems. “We faced a triple whammy – maybe more whammies than that.”

One whammy has been high exchange rates. The loonie has risen during this decade from just over 60 cents per US dollar (when an American business magazine famously dubbed it the “northern peso”) to $1.10 last year. As a result, American oil companies benefitted far more Canada. Since the Canadian sector profited much less from oil price increases than those in the States, for example, its access to capital for exploration and development tightened. It was one of a number of factors (including labour shortages and rising environmental costs) contributing to high operating inflation in the oil patch.

Another whammy has been Canadian natural gas production, which now seems in terminal decline. Export markets in the US are well supplied and they are also far from Canadian supply. This means transportation costs take a big bite out of producer revenues. At this writing, the price of gas at Alberta’s AECO Hub was more than a dollar cheaper than gas at Louisiana’s Henry Hub –$6 and change per thousand cubic feet. According to market analyst Martin King of FirstEnergy Capital, “at current prices, little in the way of new natural gas production is economic in Western Canada.”

Until recently, however, the greatest whammies have come from government. Ottawa’s decision to tax trusts – the SIFT, or “specified investment flow-through tax”, will impose a 31.5% duty on the net income of energy trusts starting in 2011 – has made trusts unattractive as exit strategies for junior producers. It has also taken money out of the hands of investors. The Alberta government’s decision to increase royalties is also cutting into the industry’s available capital. It will significantly cut net income when it goes into effect in January – not a good thing when energy prices are in decline. This development has already affected drilling, which has been dropping from a peak for three years.

The hottest resource plays tend to be at either side of the basin, in BC and Saskatchewan. That’s partly because of Alberta’s new royalty framework. According to landman Bob James, who is president of privately held Tiger Moth Energy, “The most plentiful hydrocarbon that remains to be found in this province is natural gas, but it’s prohibitive to explore for it because of the upcoming royalty structure. That really needs to be looked at, because it means in a couple of years this province will be ‘way behind where we should be in terms of drilling and production. And that will ripple across the country.”

And now, the perfect storm: These and other factors had been offsetting the higher oil prices of the last year. New projects had become harder to fund. Leveraged companies and those without cash flow were shedding assets. Despite a pickup last summer, drilling has been in decline for three years. The environment was not good, but disguised by higher oil prices – and, during spring and summer, higher gas prices too.

But when the financial crisis roared out of Wall Street and the City of London in September, it created a whole new environment. The global financial crisis unfolded at warp speed, and the full fury of its power will take months to unfold. When this article is in your hands, no doubt the situation will still be changing rapidly. Like the 100-year rogue wave the Hibernia production platform was designed to withstand, it hit during what had seemed to be a rough but not overwhelming storm. The TSE’s index of larger energy stocks lost 50% of its value in little over a month, and the juniors fared far worse.

After the big wave hit, Jeffery Tonken (CEO of junior producer Birchcliff Energy) famously said “It’s Armageddon out there. I’ve lost millions. Everyone has.” He was referring primarily to the collapse in share prices – especially for junior companies.

Already hit by poor gas prices, the lot of most juniors became far worse after the world saw trillions of dollars vapourize in weeks. Investors are worried that banks will reduce or even refuse to renew their revolving lines of credit. This will stymie their ability to expand, since they won’t be able to invest much more than cash flow. According to Murray Nunns, president and COO of Pennwest Energy, “The vast bulk of the junior market is going to be left floating on an ocean of limited access to capital.”

There are exceptions, of course. According to Tiger Moth Energy’s Bob James, “Adversity breeds opportunity. As things turn down land becomes cheaper, properties come up for sale that would ordinarily not be up for sale and prices go down. It’s harder to take advantage of these opportunities, though, because capital freezes up and courage freezes up. So you have to recognize these opportunities and pursue them with conviction. Just now you have to be sure you aren’t exploring and drilling for gas, though.” As if to emphasize the point, when contacted for an interview he was putting in a bid at an Alberta land sale.

James stresses that a credit crisis for an enormously capital intensive industry will have huge repercussions for producers.

Keith Macdonald agrees. He is president of another privately held company, Country Rock Resources, serves on the boards of half a dozen oil and gas companies and is also a director of the Small Explorers and Producers Association of Canada (SEPAC). “The cost of borrowing for juniors is going up, and this reduces your flexibility. Right now we also have the backdrop of lower gas and oil prices. The A-teams of the oil and gas world are going to be able to get capital, but the rest are going to have to scrape and scrap for every dollar that they raise.”

“Already a lot of those companies are trading at deep discounts to their net asset value,” he adds. “We’re already seeing companies with good development projects that simply can’t raise the funds they need. Ordinarily that isn’t a problem. Now the junior sector has to stay within its cash flow and consolidate for survival until they reach the size where they can conduct meaningful drilling programs. I think that means 2,000 to 3,000 barrels per day.”

“In terms of planning, you have to plan for the longer term. A lot of things have to be worked through, including the steps governments have taken to help resolve the crisis. I think companies have to be planning for maybe an 18-month time frame.”

The impact of the financial crisis on service companies may be equally profound. “Any time there is uncertainty, companies are going to budget less,” said Nunns. “We’re coming into the budget cycle right now and most companies are going to be cautionary simply because of uncertainty. The juniors aren’t going to get much capital and there’s limited access to further capital from other players. So drilling has to slow, (this crisis) has to feed through to the service industry within the next six months.”

The silver lining: In a nutshell, small service companies carrying debt will struggle. Mid-cap companies and minnows will take sometimes desperate measures to fund core projects that need more money than cash flow can provide. Exploration will tail off. Distress sales and mergers and takeovers will occur.

According to Nunns, “The acquisition market should improve. People will be chopping off arms and legs so they can continue with projects they really like, and as a result there should be an active acquisition market. Keeping an eye on this market for the next six months to a year will be a very handy thing to do in (the world of royalty trusts).”

“Living in Calgary is really good when hydrocarbon prices are through the roof,” he adds, “but the lows are when you can create value. The credit crunch presents that kind of opportunity for the right companies in the right situations. We think opportunities will present themselves, including the ability to buy hydrocarbons at more reasonable costs, and that can be a good thing for the long run.”

According to Gwyn Morgan, retired CEO of EnCana, there are other good reasons to welcome the change in commodity prices. “A lower dollar will make Canadian manufactured products more competitive. Lower oil prices will be good for Canadian businesses and families, yet they are still high enough for oil companies to profit from quality projects. Farmers will welcome lower fuel and fertilizer costs.” But how long will these benefits last?

Murray Nunns, for one, thinks the dip in hydrocarbon pricing will be relatively short-term. “There has been an immediate reaction in the futures market of lowering commodity pricing in anticipation of a recession which will lessen demand for six months to two years. ,” he said. “In conjunction with limited access to capital and project funding being tougher to find, supply additions are going to slide. Because of the limited supply adds during this time period, we should begin to see some distinctive upward pressure on price in the mid-term.”

“If you look at the history of oil,” he continues, “there was only one year in the last fifty in which (global) oil demand declined; 2008 might be the second.” As president of a large, well-capitalized company, he can take the long view of developments.

China syndrome: China has spent millennia taking a long view of developments, and is sitting on more than a trillion dollars in cash. Twelve to 18 months ago the country was trying to buy world resources everywhere. Nunns asks, “How active are the Chinese going to be in the resource acquisition market?” He thinks the answer is obvious, but after being pressed offers these comments. “The Chinese economy is not going to grow at quite the same rate it has over the last decade. It is probably going to focus more on internal growth. There will likely be continued internal economic development, and this will generate significant demand for key commodities and resources. I’m not an expert in the area, but they may see the credit crunch as the ultimate buying opportunity.”

In a recent article on Chinese energy policy, Oilweek noted that the Middle Kingdom has proclaimed its intention to “promote the common development of energy around the world, expand the global market, and make positive contributions to the world’s energy security and stability.” In a world of extreme instability in global energy markets, perhaps those ideas will translate into takeovers of bigger companies with cash flow or debt problems. Thus, perhaps, could China and other countries sitting on piles of foreign currency recycle their US dollars.

If so, which well-known Canadian companies would be most likely to become takeover targets?

The Crumbling of China’s Export Market

2008-11-13T07:24:00.031-07:00

"After a recent visit to China, Nobuyuki Saji, chief economist and equity strategist for Japanese investment bank Mitsubishi UFJ Securities, issued a report warning that China could be on the verge of pushing the world into a deflationary spiral," writes today's Globe and Mail. "The problem? Swelling industrial overcapacity, which threatens to undermine prices both for China's exported goods and its imports of raw materials."

In the following commentary, Language Matters contributor Dave Dubyne gives his take on things. Photo above, the Shenzhen skyline on a low-smog day. To see the alternative, scroll down.

By David DuByne
The Olympics have come and gone, and the promises by Ministry of Finance government spokesmen that the Chinese economy was set to grow healthily and steadily after the summer Olympic Games and that a post-Olympic economic downturn was highly unlikely need to rethink their official statements. Even today after the $500 billion dollar rescue package from the Chinese government the National Bureau of Statistics (NBS) reiterated “China's economy is in good shape despite the changing economic environment, and it will remain stable with relatively fast growth. We should be confident about the country's economic outlook."

Rosy scenarios now fly around the daily news that even in the worst of global economic times China will be minimally affected. The fundamentals of China's economy are sound, the central government is in total control and if a problem occurs, the solution is already unfolding. The National Development and Reform Commission will continue efforts to expand domestic consumption amid the global economic uncertainty and People's Bank of China says “there is still room to tap more domestic consumption.” The Ministry of Finance reiterated “A high savings ratio can stimulate demand when economic recession occurs. China's economy is therefore cushioned against the worst of the disaster.”

With all of this positive news; who should be worried? My answer: Anyone that understands the ripple effect, that’s who! The leaders say one thing to pacify the people while on the streets another world exists. I want to delve into the beginnings of a disintegrating China.

I sat in disbelief reading today’s Shenzhen local paper stating that Some 9,000 of the 45,000 factories in the cities of Guangzhou, Dongguan and Shenzhen are expected to close down in the next three months according to the Dongguan City Association of Enterprises with Foreign Investment estimates. Those closures would see up to 2.7 million jobs cut as overseas demand for consumer goods and clothes fades, that’s more than 50,000+ a day if you believe official figures, which I do not, and I believe the number is actually higher. The association says that, by end of January, demand will shrink by 30 per cent, and these are just mainland factories. The Federation of Hong Kong Industries said that about 25 per cent of the 70,000 Hong Kong-owned companies in southern China "could go to the wall by the end of January". Yet on the very next page I read an article quoting the Ministry of Commerce as stating “Although it is likely to cause a decline in China's external demand, our stock market and financial system will not be fundamentally affected.”

I can understand the flip-flopping stories as a means to keep a population from panicking, after all the Shanghai A-shares have declined more than 60% from their bubbly peak at the beginning of the year. The Hang Sang in Hong Kong and the Shenzhen indices are not doing much better. Real estate prices have slipped 20% in the last six months, all of the recent factory closings with many more to come and this is just the beginning of a prolonged feedback loop.

The central government's plan to reverse a foreign trade decline is to increase domestic consumption, restructure industry and boost innovation to change its economic development mode, that’s fine but first you need to have an expanding domestic economy to do that.

Priority Number One: Number one on the priority list is domestic unrest caused by factory closures and owners declaring bankruptcy, thereby avoiding the troublesome task of paying the employees. In the last three weeks Dongguan Weixu Shoe Company collapsed and laid off 2,000, Chong Yik Toy Company shut leaving 1,000 payless. The largest, Smart Union, locked its gates on 7,600 workers. Protesters descended on government buildings in Dongguan where hundreds of police were called out to quell violence. So far local public funds have been used to cover the back pay owed to workers, $7.6 million dollars so far. This was to cover three factory closures, imagine the bill when factories close across China in the tens of thousands. By the time you read the article “Govt foots collapsed shoe firm's wage bill”, from Xinhua News Agency many more factories will have closed along the east coast.

"Big deal", you say. "The workers are paid and will return to the countryside where they can grow vegetables." That is true, but the few thousand RMB in their pockets will run out after a few months and with very few other opportunities to secure an income, China’s stability is in question. These workers originally came to the city to support the family by sending back money every month, now they are returning to the countryside by the tens of millions across China. My question is, "When the money runs out what will they do?" I’m sure crime and violence will skyrocket; to what degree I can only guess; but most importantly to what degree can security be guaranteed by the central authorities outside the cities?

If there is a repeat of anything like the Great Leap Forward, where 40 million starved to death, or the Cultural Revolution, which ended barely two decades ago, it will become a society restructuring event. China is quite different compared from the 1950s as the current pollution problems have made 98% of water sources above ground unusable and the amount of arable land has shrunken dramatically as factories and cities now cover what was once farmland.

These bankruptcies and massive layoffs are not just single events in isolated locations; it is beginning to happen countrywide. The lag time between the events of the western banking system and the fallout here is approximately two months. With that said more trouble is on the way. If there is no contingency plan by the communist party for the global downturn within their own society and if they are reacting to each event rather than planning for such events, then the China we have seen over the last ten years will be an entirely different place in another two.

Second Tier: The second order of business will be restructuring to a non-export driven economy for the next three years until the world works itself out of this financial mess. The only one to speak out so far against the grain of positive news is Fu Ziying, Vice Minister of Commerce, who with some common sense said “It would be more difficult to maintain stable export growth next year because of the global financial turmoil.” As I stated before, most of the fixes for the slowdown seem to revolve around expanding domestic demand, which is the catch 22; demand for exports slows, so if citizens have no job and less money selling them goods and getting them to spend won’t work. These pipe dreams of China's economic flexibility and macro-control guaranteeing economic stability is exactly that, a dream.

I think a message is beginning to get through with this unfathomable event requiring Government Agency spending be frozen in 2009, halting the average annual 5 percent increase of the past five years. The Ministry of Finance said on Tuesday. "The budgets for next year should be capped at the same amount as this year's and every project would be looked at"

Agency spending includes staff salaries, lavish gatherings and official state business. Expense budgets of all 107 central government agencies will be analyzed and related departments asked to tighten their budgets.

Wang Chaocai, vice-president of the ministry's research institute for fiscal science, said “The spending freeze will be achieved by reducing the number of meetings and conferences, reception activities and business trips, and by cutting transport costs.” This truly astonishing in the land of showing off wealth and status, that’s like asking the Emperor to reduce the party and banquet budget during the Tang Dynasty - unthinkable, unless there is a crisis.

The way I understand it, each department is compartmentalized and deals with that departments business only, the idea of ripple effect is not widely understood in China even at the highest ministry levels. Exports directly effect factory production and workers lose their jobs: that is widely understood.

Trying to explain that the copper mine in Jiangxi will need fewer workers and that leads to lower need for rail transport, which leads to a reduction of rail cars and that industry, plus the maintenance crews and repair parts involved to keep it all running, this is a bit more difficult task. How about the food vendors at the factory gate, the nearby stores and delivery drivers who drive fewer miles and buy fewer tires. There is less vehicle maintenance which requires far fewer mechanics and spare parts to keep the transportation network by road moving, which is also its own separate industry. This example filters right through ports, construction, real estate, logistics etc… and it’s all based on producing or transporting something for manufacturing, export and indirectly imports.

Power generation is one of the biggest industries in China, and according to the China Electricity Council “power demand in August fell 5.8% from the slowdown in export-oriented consumption along coastal areas.” This directly connects to China’s largest steelmaker, Baoshan Iron and Steel and the nation’s biggest aluminum producer Aluminum Corp of China cut prices for December by as much as 20% in a bid to attract more orders amid a slowing economy, and are considering further cuts because of falling metal prices and weak domestic demand.

Premier Wen Jiabao said on Saturday that fiscal revenue in the fourth quarter of this year will continue to drop after falling from more than 33 percent in the first half to 10.5 percent in the third quarter. The World Bank followed with a downward revision for China’s GDP growth next year at 7.8% or lower on reduced spending in consumer markets.

As many areas of the world enter a recession 7.8% sounds great, but in China the working age population is still growing, China needs at least 8% growth to maintain the current employment rate. Where will the three million new college graduates find work this year, after all they are fighting with the surplus of five million diploma holders that still have not found work over the last two years.

Third Time is the Charm: The third obstacle will be restoring confidence in the average citizen’s mind. As the cycle of distrust between employee, supplier and factories intensifies, factories may close because workers leave for fear of not being paid; suppliers will not deliver unless paid cash on the spot at delivery, no more credit. This cycle will lead to an exodus of workers from coastal provinces. I believe that Shenzhen, a city of somewhere between 10-14 million will shrink by maybe half by the end of next year

In a reactive approach as situations occur around the mainland, there have been several new laws introduced, The Communist Party of China (CPC) issued a landmark policy document on October 20 allowing farmers to "lease their contracted farmland or transfer their land use right to boost the scale of operation for farm production and provide funds for them to start new businesses.” This is the first firm confirmation that tens of millions are going back to the countryside.

The Ministry of Finance shortly thereafter announced that the property contract tax had been lowered to 1 per cent from 3 per cent, on purchases of properties that are smaller than 90 square metres. Also, the down payment requirements will be lowered to 20 percent, from 30 percent. Real estate was where a lot of “new” money came from in the last ten years. Spending was up because property values were up, just as in the US from 2000-2007.

Starting from November 1, the Ministry of Finance said in a statement “The government will raise export tax rebates for 3,486 products including textiles, clothing, furniture and toys. The tax rebate was raised from 11 to 14 per cent to help exporters cope with lower demand” which is a stealthy way to boost container loading since cargo volumes are down 20-50% depending on the port.

These measures are like a doctor treating the symptoms of a patient, not treating the cause of the disease. The trend of shrinking foreign demand is unlikely to reverse, and the new policies are to create domestic consumption and encourage spending. Disposable income from the real estate and manufacturing sectors has dried up in the country. You cannot spend something that you do not have.

Trade Fairs and the Future: Trade fairs throughout China set the tone for the following year’s production and export market, the largest in the country being Canton Fair in Guangzhou, concluded November 06. The number of buyers from Europe and the United States dropped by more than 30% from last year's levels. Trade volume at the annual event dropped by about 15%-17% from last year amid global recession worries.

The Yiwu International Commodities Fair and China-ASEAN Expo reported similar results. These shows are a showcase of Chinese Commodities focusing on Machinery & Equipment; Electronics & Electrical Appliances; Building Materials & Household Ware; Agricultural Materials, Produce & Foodstuffs.

The downward trend is obvious, and now manufacturers are trying to save themselves, with decreased orders, rising production and labour costs, manufacturers are cutting more corners wherever possible.

As well as cutting staff, companies are trying to use energy and raw materials more efficiently, and seeking out alternative, lower-cost suppliers. From my own experience, Chinese firms already seek out the lowest cost supplier and purchase one-off lots to reduce costs; I really don’t see how they could achieve cost reduction using this method. One unique approach is promoting and selling products online, a virtual store with no office rent to cover and downsizing the office into your own apartment is another tactic.

Just as overseas and domestic demand slacks off, I wonder when the multinationals will start trimming their China office staff as a way to save money in the head office abroad.

Economic Fallout: The fall-out will be highly concentrated in provinces such as Guangdong, Zhejiang, Jiangsu, Shandong and Fujian all the way up the east coast stretching back the production and supply chain to the Special Economic Zones (SEZ’s) in the western provinces. Nothing will go untouched as this export driven economy is a tight spider web of endless links to supply the greatest economic growth in history, and now perhaps the greatest reversal.

To an unprepared reactive country the crisis will come in many ways that are not directly financial but societal as well. The question is not whether the crisis will come to China, but rather how China is prepared to deal with it.

As I recently read in a blog, “China has been a country littered with crises of large scale. They have dealt with crises before like the Cultural Revolution which ripped the fabric of society, several famines and the Japanese invasion in the last century.”

That was then this is now. Around Guangdong Province impromptu protests by disgruntled workers left jobless and without pay are becoming more common; they have resorted to petitioning local government officials for back pay because they have few other ways to be compensated. They will complain more and they will protest at local government offices, you will see more demonstrations and picketing. In the last few years riots related to land grabs, bank failures, forced relocation and protests to close polluting factories were estimated at 70,000 last year, now add in this new “wave” of social movement and anything is possible.

Chinese Crude Demand: Just when you thought there may be a let-up in Chinese oil demand because of the slowing global economy! Think again. This China Daily article, “Calls to pump up nation's oil stockpile,” states that the country should take advantage of the record drop in global crude oil prices to build up more reserves. “Compared with the highest prices in July, crude oil prices have dropped by 50 percent. We should take advantage of the low prices to build more oil reserves.”

If you have been asking yourself throughout this article, "Why don’t they just spend part of their two trillion dollars in foreign currency reserves to keep things going?", keep in mind Chinese currency reserves are 80% US dollars and 20% euros and the government can’t purchase items priced in different currencies at will. They would first have to sell dollars and then re-buy another currency, and that’s bad for China. If the dollar drops than the effect will be intensified as fewer US orders will come in. The most obvious choice is to buy something useful and already priced in US dollars; I think you know the answer.

Restructuring the Future: The parallels between China’s precarious social and economic future based solely on exports and our own societies entirely dependent on fossil fuel as a driver for growth are striking. China now needs to focus on what’s beyond expanding its economy through exports and manufacturing, while all of us need to focus on what’s beyond growth in a crude oil based economy. Peak oil is occurring now, the economic repercussions are a symptom, China is affected, the world is affected, we are all affected. Now the emphasis needs to be more on what to do after the peak.

We have come to the end of the line in terms of endless economic growth based on cheap, readily available crude oil, China has come to the end of their growth in this phase if industrialization for the same reason. The world has been the economic driver for China and China the economic driver for the world, both were based on cheap energy and disposable income derived from cheap energy, that time has passed. We need to find ways to be proactive for the future instead of reactive. My gut feeling is that within 3-6 months we will begin to see events on a level no one has anticipated. When it becomes impossible to find work in China during the “economic miracle” we will have truly entered the end of the age of oil.

David DuByne is from the United States and is presently working in Shenzhen, China, as a business consultant. He also hosts Dave's ESL Biofuel, a teaching website devoted to bio-fuel and oil depletion for those around the planet studying English.

The Carbonate Question

2008-10-24T11:51:00.010-06:00

This article appears in the November, 2008 issue of Oilsands Review. Graphic shows Alberta oilsands in yellow, major heavy oil deposits in blue, Grosmont bitumen carbonate formation in red and bitumen triangle within dashed line. Source of map here.

By Peter McKenzie-Brown

According to one view, planet Earth has two energy super-provinces – one in the Old World, the other in the New. The Old World super-province stretches from North Africa through the Middle East into Siberia. Rich with conventional oil, it’s the source of most of the petroleum traded on global markets.

The New World super-province reaches from northern Alaska and the Beaufort Sea through Alberta’s oil sands down to Venezuela’s Orinoco heavy oil belt, and continues south between the Atlantic coast and the eastern Andes. Richer in oil than its Old World sibling, its conventional resources are mostly in decline. However, this vast region has great volumes of untapped unconventional resources – notably Alberta’s oilsands, Venezuela’s Orinoco heavy oil belt and America’s oil shales.

This article focuses on the least known of those unconventional resources. Bitumen carbonates are common reservoir rocks totally saturated with very heavy oil. They are also the hydrocarbon resource in which Canada leads the world by an almost incomprehensible margin.

Canadian deposits contain 96% of the entire world’s supply of this black, barely mobile oil. That would be just a statistical oddity if not for the volumes of hydrocarbons involved. There are nearly 450 billion barrels in the ground in Alberta. Seventy-one percent of that total (318 billion barrels) is in the Grosmont formation – a massive structure underlying much of the Athabasca oilsands deposit. Another 65 billion barrels of bitumen can be found in the Nisku carbonate, which is associated with the Grosmont. In Peace Country, the bitumen-saturated carbonates contain as much oil as the Peace River oilsands deposit – once again, about 65 billion barrels.

Here’s another way to put those numbers in perspective. Alberta’s bitumen deposits comprise the largest petroleum resource in the world. One fourth of that resource is in carbonate reservoirs.

There is a catch, of course. Like the oilsands many years ago, there are no economic ways to produce oil from these deposits yet. However, in early 2006 a numbered company shelled out C$465 million for oilsands leases in the Grosmont. When the owner of that mystery company turned out to be Shell – not known for taking high risks when large amounts of cash are at stake – many previously skeptical observers began to see these carbonates as a resource whose time was nigh. Is that optimism justified?

Nature of the resource: Carbonates are minerals that contain the carbonate ion, CO3. Probably most of the world’s conventional oil resources are in traps made of these rocks. While the most common reservoir carbonates are limestone (a calcium carbonate) and dolomite (a magnesium and calcium carbonate), reservoirs typically include many other carbonate minerals.

On the surface, Alberta’s bitumen carbonates have the makings of an oil producer’s nightmare. The rocks themselves are full to saturation with huge volumes of highly viscous, heavily biodegraded bitumen – the most viscous bitumen carbonate in the world, in fact. The resource is thicker than molasses. In general, the carbonates have little permeability so the bitumen is in a reservoir that won’t easily let it escape, and for other reasons the reservoir rocks can yield as much trouble as oil. The resource is in the middle of the bush. Once you get the bitumen out of the rock, it isn’t transportable without lots of diluent, and it isn’t commercial without extensive upgrading. For all this Shell paid nearly half a billion dollars?!

What Shell paid for was the potential. The volumes in the ground are so huge that a relatively small amount of production from a sweet spot in the Grosmont could be hugely profitable. In a number of cases worldwide, some bitumen carbonates have gone on production with reasonable results – notably Iran’s offshore Zaqeh field (no longer producing) and France’s Lacq Superieur. As we shall see, Shell’s ace in the hole is technology.

In the 1970s and 1980s, a number of companies conducted experiments on the Grosmont formation, mostly in cooperation with the long-defunct Alberta Oil Sands Recovery and Technology Authority (AOSTRA). Although no commercial oil resulted from these experiments (production was pumped back underground), the technical community began to understand the resource, and to dream about bringing it into production.

According to Roy Coates of the Alberta Research Council (ARC), bitumen carbonates are now at the place where non-mineable oilsands were some decades ago. Commercial development is in the future – maybe 20 years. “That’s when carbonates will be at the stage where SAGD developments are now,” he said. “I don’t consider SAGD really commercial yet. (Producers) are still trying to optimize the process.”

Coates is program manager for the Carbonate Research Program, a 3-year, $2.3 million per year initiative of major companies plus two agencies of the Alberta government. He seems fascinated by the challenges of the Grosmont bitumen carbonate, beginning with the matter of where the stuff came from. “That’s something we’re looking at. I would venture to say that it is the same oil as in the oil sands. We don’t know where the bitumen originated. It could have originated in the carbonates and flowed to the oilsands or vice versa. We don’t know the answer to that. But the properties are so similar that you should consider them to be the same oil.”

Matrix, vugs and fractures: The fact that it is the same oil as the oilsands is one of many problems presented by this resource. Its viscosity is such that it doesn’t flow naturally. Like bitumen from the oilsands, you have to make it thinner to make it flow. That is only the beginning of the problems, however. For example, the bitumen formations are 200 to 1,000 metres deep, which means they are not mineable. Gas drive in the reservoirs is insignificant. The problems get even worse when you consider reservoir permeability and porosity.

According to Coates, the Grosmont carbonate “almost has three systems of permeability and porosity.” The matrix of carbonate rock is very tight, with low permeability. Yet over eons it has somehow become saturated with bitumen. That’s the first system: low-permeability, low porosity rock full of bitumen so viscous it won’t flow without treatment.

The second system harbours other problems. Within those carbonate rocks are large cavities, called vugs – often the diameter of your arm or bigger. For the most part, these structures are leftovers from eras when water ran through the rock, dissolving caverns and other crevasses in it. They fill with rock debris (often overburden), but they also fill with bitumen. These structures can have good permeability and porosity, but they do not always form good producing reservoirs and they cause drilling problems. According to one report, during drilling “the drill bit has been observed to drop several feet as it passed through a large tunnel filled with bitumen...and these irregular tunnels...lead to a loss of mud circulation during drilling.”

The third permeability/porosity system consists of long fractures in the rock. “When you try to heat a reservoir or inject a fluid into it,” said Coates, “because of the fractures you can’t be sure where the steam is going to go.”

These difficulties notwithstanding, in the early years of experimentation on the Grosmont, there were some great successes. According to an AOSTRA report, in the late 1970s Unocal (since absorbed into Chevron) and Canadian Superior (absorbed into Exxon Mobil) conducted a series of field tests to assess steam stimulation, steam drive and combustion on the structure. In one instance, “results were spectacular. Bitumen production rates from a single steam stimulation well of up to 550 barrels per day were obtained”.

Despite these results and those from further trials, the companies abandoned these pilots in the mid-1980s, for two reasons. One was the problem of logistics-related high costs (the Grosmont is in a remote area, without roads and other infrastructure). More importantly, the companies had serious technical concerns about the viability of production – especially in the lower-price environment that followed the oil price shock of 1986.

In situ refining: Of course, that was then and this is now – a world of high prices and improved technologies. In recent years, other companies have been testing Alberta’s bitumen carbonates. One notable player is Husky Energy, which has accumulated substantial holdings in the Grosmont, for relatively small amounts of cash. Husky estimates its Saleski bitumen carbonate properties contain 19.5 billion barrels of original oil in place. You don’t need to coax a large percentage of that oil from the rock to find yourself with a valuable asset. Husky’s tests so far have used technologies that are advances on the methods tested long ago by Unocal and Canadian Superior, but similar in concept.

Shell, however, is different. When Shell made its startling $465 million bid for part of the Grosmont, the company clearly had in mind substantial production volumes. The industry wondered what was going on, until a hint of company thinking came out in a recent interview with Jan van der Eijk, Royal Dutch Shell’s chief technology officer (CTO). The occasion was a wide-ranging discussion of technology, but largely centred on Shell tests at a bitumen carbonate deposit in the Peace River area. New Technology magazine reported the story.

According to journalist Pat Roche, “In what could lead to one of the most revolutionary innovations in the history of the oil and gas industry, Shell has been testing a way to upgrade bitumen in the reservoir for more than two years. Electric heaters raise the subsurface temperature to the point where the reservoir, in effect, acts as a refinery. ‘The product that you produce is almost water white, and it is as mobile as water,’ says van der Eijk.”

This “in situ upgrading process”, as the company calls it, has been more than a decade in the making. It began with tests on oil shale in Colorado. In its oil shale tests, Shell recovered 1,700 barrels of light oil from a 10 by 13 metre area at its Mahogany test site. The company used underground electric heaters like those introduced at Peace River to induce chemical pyrolysis underground. This “in situ conversion process” distilled shale-bound kerogen (a precursor to oil) into synthetic crude oil. A by-product of the tests was shale gas.

The Peace River test was the first to use electric heaters to upgrade oil in the ground.

Journalist Pat Roche continued, “As happens in a refinery, the lighter products are boiled off, leaving the heavier components behind in the reservoir. The upgraded oil can be further refined into products such as gasoline and jet fuel. ‘The product is really impressive,’ [says van der Eijk].

“‘In a refinery,’ he explains, ‘you need to have a certain throughput through a vessel. And that drives you to a certain reaction rate; otherwise, you just don't have enough productivity.’ But in the subsurface, the reservoir serves as a gigantic vessel. ‘And in that sense you can allow much lower reaction rates. The vessel is much larger and you can let it go for a year rather than a minute throughput [in a refinery].’”

Late last year, Shell filed a regulatory application to test its in situ upgrading process in the Grosmont bitumen carbonates. Perhaps its tests in that massive formation will help transform Alberta’s bitumen carbonates from vast stores of puzzling gunk to one of the hydrocarbon jewels of the New World. You can never tell.

Shell's Take on Carbon Sequestration

2008-10-22T10:26:00.014-06:00

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

By Peter McKenzie-Brown

Is human activity influencing climate change or not? Indeed, is global warming even taking place? There is widespread disagreement within academia about the causes of increased global average air temperature, especially since the mid-20th century. Some argue that the observed “trend” is a normal climatic fluctuation. Others claim it isn’t even happening. These issues are the source of rip-roaring arguments in Alberta. Perhaps because of the impact of geological thinking on a province with a petroleum-based economy, the arguments here are both heated and informed.

Geologists, who think in terms of Earth’s periods and epochs rather than its decades, are well aware that climate always changes. Perhaps they also have an innate scepticism about whether human behaviour can meaningfully alter the powerful natural forces continually changing our planet.

While the debates rage, the scientific “consensus”, as it is delicately called, supports the idea that greenhouse gas emissions from human activity are increasing Earth’s temperatures and thus speeding up climate change.

For many environmental groups the problem seems critical, and they call for urgent action.

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

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

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

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

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

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

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

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

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

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

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

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

How it would work: CO2 will remain in supercritical form if stored more than 800 metres below ground. Shell is targeting structures 2,000 or more metres deep.

The injection wells would use several casings of steel pipe to ensure the CO2 entered the deep rock formations alone, and would not enter shallower areas of the ground. This would prevent leakage to the surface or into drinking water aquifers.

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

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

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

“We believe governments should take action on regulation to control CO2 emissions,” Seeley said. “If they do that, it will create a level playing field in which big industrial polluters can innovate to reduce emissions.” Seeley thinks big: “If we can have regulation that is complementary from country to country then we have a better chance of reducing these emissions internationally.”

Seeley noted that CCS faces numerous risks that will require government involvement. These projects “are sitting waiting for regulation. The rules for greenhouse gas regulation in Canada are still not certain. You have to settle regulatory issues such as Canada and Alberta harmonisation before those projects can go forward.”

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

“Capital costs will be in the hundreds of millions of dollars, but operating costs will also be high. It could be that over the life of a project the operating costs (present value basis) would be about the same as the capital costs. There are also technological costs.”

Although CO2 has long been used in enhanced oil recovery, Seeley observed that “EOR doesn’t save the day on this. Historically, for EOR you get paid maybe $20 per ton for CO2. With higher oil prices, maybe you will get $30 to $40 per tonne. This is still well short of the $100/tonne cost to capture, compress and transport CO2. Only higher carbon pricing (by government) or the market will make this viable.”

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

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

This seems like a map other oilsands producers should study.

Centre of a Storm: The Canadian Petroleum Association during the energy wars

2008-10-09T16:53:00.014-06:00

A reflection of the trauma of Canada’s energy wars; cover courtesy Maclean’s Magazine. This cover is now a life-size, feature exhibit at Calgary’s Glenbow Museum. Left to right: federal Energy Minister Marc Lalonde, Alberta Premier Peter Lougheed, Prime Minister Pierre Trudeau and Alberta Energy Minister Merv Leitch.

From the book Barbecues, Booms and Blogs: Fifty Years of Public Relations in Calgary, this chapter is excerpted in the November, 2008 issue of Oilweek magazine.

By Peter McKenzie-Brown

The oil price shocks of 1973, 1979/80 and 1986 echoed and re-echoed around the world. Here at home, they aggravated the conflicts that historians now call Canada’s energy wars. As the drums of battle deafened public debate and affronted an industry whose allies were few, federal and provincial partisans clashed for petroleum wealth.

Through the Canadian Petroleum Association (CPA), oil and gas producers gradually developed a coherent public voice and eventually played a role in policy reform. They also opened their eyes to the critical importance of good environmental practice.

This chapter tells those stories.

Energy wars
The battles began with a shot from Prime Minister Pierre Trudeau. Inflation had become a national problem and oil prices were rising, and on September 4, 1973, he asked the western provinces to agree to a voluntary freeze on oil prices. Nine days later, his government imposed a 40-cent tax on every barrel of exported Canadian oil. The tax equalled the difference between domestic and international oil prices, and the revenues were used to subsidize imports for eastern refiners. At a stroke, Ottawa began subsidizing eastern consumers while reducing the revenues available to producing provinces and the petroleum industry.

This outraged Alberta, which had fought long and hard for control of its natural resources. Britain’s Privy Council didn’t award resource ownership to the province until 1930, after a drawn-out legal battle between Edmonton and Ottawa.

Premier Peter Lougheed soon announced that his government would revise its royalty policy in favour of a system linked to international oil prices. His timing was impeccable. Two days later, on October 6, the Yom Kippur War broke out – a nail-biting affair between Israel and the Arab states. OPEC used the conflict to double the posted price for a barrel of Saudi Arabian light oil, to US$5.14. Saudi and the other Arab states then imposed embargoes on countries supporting Israel, and oil prices rose quickly to $12.

These events aggravated tensions among provincial, federal and industry leaders. The rest of the 1970s were marked by rapid-fire, escalating moves and counter-moves by Ottawa, western provinces and even Newfoundland. The atmosphere was one of urgency, alarm and crisis, with global conflicts adding gravity to the federal-provincial quarrelling.

Alberta, British Columbia and Saskatchewan (the latter two headed by NDP governments) took steps to increase their revenues from oil and natural gas production and to protect provincial resource ownership from federal encroachment. The federal government announced a series of national policies founded on the basic notions of federal/provincial revenue sharing, made-in-Canada pricing, increasing Canadian ownership of the industry and a quest for self-sufficiency in oil through development of such non-conventional resources as oilsands and the frontiers.

A single voice
The logical voice for the petroleum industry was the Canadian Petroleum Association, a trade association mainly reflecting the interests of large, foreign-owned companies that together produced around 90 per cent of Canada’s oil and gas. Formed in 1952, the association’s primary function was to compile technical data for the industry – drilling statistics and reserves estimates, for example.

The CPA asserted itself as the industry’s voice and quickly found itself in the centre of a storm. Its Executive Director was John Poyen, a capable manager with a technical background. According to Jack Gorman, who later became the association’s Director of Public Affairs, “When the feds announced the export tax on oil, from his chair in the CPA office Poyen made some fairly blunt comments, without any reference to the CPA’s Board of Governors.”

Hans Maciej – at that time the association’s Technical Director and economist – didn’t think so. “John used to call a spade a spade and the feds may not have appreciated his plain talk, but the organisation continued to put the industry’s case forward.”

Harold Millican soon took the top job at the CPA, and Gorman joined him. “It was a happy arrangement,” said Gorman. “Our focus at that time was to be conciliatory, especially because of the way Poyen had shaken the beehive and got a lot of people upset. So we developed our messages, and talked about how oil was getting harder to find and told people about different approaches to the problem. Jim Rennie joined us and we developed an educational approach, producing booklets about the ABCs of the oilpatch.”

As an aside, the CPA library became an important centre of PR learning for CPRS members, beginning with Rennie’s brief tenure there. Monthly “Library Nights” featured bottles of port and thoughtful discussion about every imaginable aspect of public relations practice. Library Night thrived until 1983, when it reappeared as Shop Talk at another venue. It soon disappeared from the historical record.

“With some difficulty,” Gorman continued, “I was able to sell the CPA on a program of journalism awards to get the media to take more interest in our industry. I thought it was also important to hold seminars for reporters and separate seminars for editorial writers. So we brought them into town and set up seminars hosted by experts from the oil industry. It was a warm and credible way of working with the media.”

Perhaps, but it was powerless in the face of the worsening political struggles. As Maciej put it, “When politics entered the picture, PR people alone could not play the major role.”

The National Energy Program
In 1979/80, further crises in the Middle East led to panic-driven pricing. The Iranian Revolution came first. War between that country and Iraq soon followed. Oil prices more than doubled, to US$36 per barrel.

Such high prices multiplied the amount of money at stake. Pierre Trudeau led the Liberals to electoral victory in 1980, promising vaguely to create a federal energy policy in response to rising oil prices. The result was the National Energy Program, Canada’s most controversial federal initiative in peacetime. It ended an era of great prosperity in Alberta.

On October 28, 1980, I worked for Gulf Canada, and that evening I sat glued to the television as the budget speech described the federal government’s latest energy initiative. In a beautifully produced book prepared for the occasion by the federal government, Energy Minister Marc Lalonde said, “This is a set of national decisions by the government of Canada. The decisions relate to energy. They will impinge, however, on almost every sphere of Canadian activity, on the fortunes of every Canadian and on the economic and social structure of the nation for years to come.”

Right he was, although no one could have imagined the rancour that followed. A fuming Peter Lougheed compared federal actions to those of a rude invader blundering into Albertans’ living rooms. The province made plans to cut oil production by 15 per cent over three months, threatened to withhold approval of new oilsands projects and launched court actions. British Columbia and Saskatchewan mounted furious protests of their own.

The NEP pitted vital interests against each other. Supported by eastern consumers, the federal government took one corner of the ring. Supported by regional voters, the western provinces took the other. The petroleum industry was a spectator wishing it could score points against either combatant – or better, both.

In the beginning, compromise seemed impossible. After a year, however, the two levels of government did reach a revenue-sharing agreement – memorialized in the press by photos of Peter Lougheed and Marc Lalonde toasting the deal with Champagne. Left out in the cold, the petroleum industry didn’t share in the celebrations. Under the terms of the new deal, the sector could only realize additional revenue if oil prices, which had already begun to erode, continued to rise.

Operating under new rules in a declining oil price environment, corporate cash flows dropped precipitously. In response to federal efforts to “Canadianize” the sector, foreign interests sold their assets and headed home. The Canadian sector became mired in debt – a development that contributed to the bankruptcy of once-mighty Dome Petroleum. Drilling slid into a deep funk, and rigs began a highly publicized exodus across the border. Confidence in the industry plummeted.

As the decade wore on, bankruptcies in Alberta reached new highs and real estate prices crumbled. Although exacerbated in 1982/83 by what was then the worst global slowdown since the Great Depression, the severity of the decline was unique among the world’s petroleum-based economies. Norway, for example, boomed throughout the NEP years.

New leadership
At the beginning of this period, in 1979, the CPA’s leadership changed again. Ian Smyth became Executive Director.

Perhaps reflecting his civil service background but with the active support of the CPA’s Board, Smyth quickly began to enlarge the association. He began by creating an office in Ottawa to supplement divisional offices in Regina and Victoria. ‘Before long, the organization also had offices in St. Johns, Halifax and Montréal. Smyth’s ambitions, and his plans, were vast. “CPA staff often provided access to ministers in Ottawa and the provinces, but we never lobbied in the sense that lobbying is a dirty word,” he said. “We’d do show-and-tells. There would be half a dozen ministers around the table, and we would say: ‘Here we are, the industry, and we want to tell you what we’re doing. If you have any questions, Minister, we will be glad to answer them.’”

Gorman tells a story about this period with a combination of humour and derision: “The next thing you know they hired Allan Gregg, who had just founded Decima Research, to conduct a nationwide survey to find out what Canadians think about the oilpatch. I said to Ian, ‘I can tell you what the people of Canada think about the oilpatch. They think it is run by a bunch of Yankee fat cats who are exploiting Canadians and making high profits and sending most of the money back to the U.S.’ So they launched their campaign and surveyed Canadians and that’s exactly what they found out.

“Then they decided to let the research drive a campaign to convince the Canadian people that this really wasn’t true, that the oil industry was really working in the best interests of the country. So they began this big, expensive advertising campaign, but I don’t think it was very effective.”

Norm Elliott and I joined the CPA in 1981, just before the advertising campaign began. Norm was Director of Public Affairs; I was his number two. Our day-to-day work consisted of analysing news and planning communications; preparing news releases and backgrounders; organizing news conferences; arranging publicity and media events (including the National Journalism Awards); managing publications, including a monthly magazine and the annual report; speech writing; meeting and meeting some more. Despite technological innovation and the evolution of new forms of media over the last three decades, these functions are still the PR professional’s stock-in-trade. They are less art than craft.

My role gave me a unique vantage point from which to observe the industry’s response to the NEP. The balance of this chapter describes how the CPA led the charge.

The leader
Ian Smyth was a big, wall-eyed man with a large ego, a superb mind and, when he turned it on, a huge amount of charm. Few people were able to dominate a social

occasion, a meeting or an organization as completely as he did. As Norm Elliott put it, “Ian was the leader. He set the rules, he set the thinking and he knew what was going on. I never saw a better mind than his. It was unbelievable to watch him, to see how people responded to him. He came into Calgary not knowing a soul, and within a year he was right on top of things.”

Smyth was a quick study, and his commentary was continual grist for the media’s mill. “He could completely take over an interview,” said Elliott. “The best media people in the country took him on, but he always controlled the interview. No one could acquire that talent. He was just born with it.” Technical Director Hans Maciej continued to answer questions about many economic and most technical matters. On matters of policy, though, Smyth became the industry’s spokesman. The CPA was the industry’s voice, and he was the CPA’s.

When I asked him to describe the advertising campaign, Smyth began thus: “We set out to use opinion polling to find out what concerned people. What we quickly found out was that Canadians were not worried about Canada running out of oil. It was a period of high unemployment and high inflation. People wanted to have a job a year from now. That was their number one concern. As we worked through the research, we realized that we had a theme. That theme was that when the petroleum industry is at work and has the funds it needs to do what it does, it provides jobs and employment right across the country. So we began to run a series of TV commercials and print ads telling that story, and it worked.”

He added, “That was the most researched campaign in the history of advocacy advertising. It became a case study in some MBA programs. We researched carefully everything we did. If something didn’t work we junked it and if it did work we did more of it. And so we gradually progressed to a stage where our campaign had a significant impact on public opinion. Partly because of what we did, voters threw out the Liberal Party in the next election.”

Hans Maciej was skeptical about the research, but supported Smyth’s conclusion that the campaign helped people understand the damage caused by the NEP. “I always questioned the numbers we were getting back from our advertising and polling people,” he said. “We would hear that something in public opinion moved by 0.2 percentage points and that was a major improvement. But Allan (Gregg) was an effective snake oil salesman, and it was always interesting to listen to his interpretations.”

“Anyway, I believe we were effective in putting forward the other side while the NEP was collapsing under its own weight,” Maciej maintained. “To their credit, the political opposition (Mulroney’s Conservatives) saw what was happening. It took them a long time to rectify all the wrongs of the National Energy Program, but they eventually did it.”

Emerging issues
Just before the NEP died, the CPA shifted its focus toward the natural environment. The emergence of environmentalism as a public issue illustrates an important rule for the petroleum industry: A crisis for one is often a crisis for many. Take the cornerstone years of 1977 and 1982.

On June 9, 1977, Justice Thomas Berger issued Northern Frontier, Northern Homeland – the report of the Mackenzie Valley Pipeline Inquiry, and a surprise bestseller. This document raised environmental and social rather than technical objections to an industrial project. In so doing, it killed a proposal to construct a natural gas pipeline from the Arctic. The industry didn’t see this as part of a sea change, but responded with a cacophony of complaints about the “left wingnuts” in Ottawa. Wingnuts or not, 30 years later 1.7 billion barrels of oil and about 25 trillion cubic feet of natural gas remain stranded in the far north.

Five years on, two calamities struck in a single year. The Ocean Ranger disaster off Newfoundland and the Lodgepole blowout in Alberta precipitated more than gripes and grumbles. The Ocean Ranger tragedy involved a semi-submersible drilling rig going down in a winter storm. She took 84 hands into the frigid sea, and none survived. The Lodgepole catastrophe involved an Amoco-operated, high-pressure sour gas well. Out of control for 68 days, it took the lives of two blowout specialists and sent another 16 people to hospital. On days with strong westerly winds, residents of Winnipeg (1,500 kilometres away) could smell the rotten-egg odour of the gas.

Regulatory opprobrium and public anger were intense. Inquiries went on for years, and the resulting new regulations were as tough as nails. More importantly, in Canada’s national consciousness these headliners reinforced budding concern about public health, industrial safety and environmental integrity.

The CPA was the first trade association to take action on these growing worries. According to Smyth, this, too, arose from research. “We were continually out there taking the public’s pulse. We had noticed from the beginning that the first few top-of-mind issues were always economic – jobs, taxes, inflation and so on. But after a while, people started volunteering the environment as a top-of-mind concern – the only issue that wasn’t bread-and-butter. So I said to the CPA’s Board that we should be, and be seen to be, the most environmentally responsible industry in the country, and they said, ‘See what you can do.’ We began by developing the first industrial environmental code of practice in the country, and soon set up an environmental department.”

Third price shock
As the CPA began its environmental labours, the country’s energy wars were ending. Then oil prices collapsed – a 1986 market phenomenon known as the third oil price shock. The industry’s core issue became survival in a world of lower energy prices.

Environmental policy remained a focus, but big-budget ads were suddenly out of the question. The CPA responded with its first and only community relations initiative. With the CBC and The Calgary Herald as media sponsors, the association’s Share the Earth Triathlon helped brand the CPA green. It was a sporting event with an environmental theme – the first, perhaps, in Calgary.

Why triathlon? It was a new sport and the city (gearing up for the Olympics) was sports mad. The demographics were excellent: a mean age of 36 and surprisingly large cohorts of professionals. Costs were minimal, and volunteers (led by volunteer Race Director Pete Strychowskyj) took care of planning and race-day operations. This early-season event quickly became the most popular in Alberta.

The CPA’s wisdom in championing the environment became apparent as the Mulroney government began passing tough new environmental legislation. This included million-dollar fines and five-year jail terms for offending executives.

Smyth twice earned honours with The Globe and Mail’s front-page “Quote of the Day.” On the first occasion he said, “I have never seen a CEO who was prepared to trade five years in the slam for a better bottom line.” On the other he said, “We have plenty of environmental sticks. We need more carrots.” In large part because of the CPA’s efforts, Ottawa nominated the petroleum industry for a prestigious United Nations award.

In 1992, the CPA merged with its former shadow – the much smaller Independent Petroleum Association of Canada – to become the Canadian Association of Petroleum Producers (CAPP). The new organization axed the triathlon which, though still popular, had outlived its usefulness.

Legacies
The oil shocks left enduring legacies. One was an increase in industry organizations focused on telling the industry story. For example, the respected Centre for Energy is the successor to the Petroleum Resources Communication Foundation, and the SEEDS (Society, Energy, Environment and Development Studies) Foundation has been producing energy information tools for Canadian schools for more than 30 years.

In addition, companies and trade associations are now far more fluent in government and stakeholder relations than when the CPA’s pioneering efforts began. The alphabet soup of industry associations and organizations – CAPP, PSAC, CEPA, CAODC, SEPAC and the rest – are better staffed with or have access to public affairs professionals. They share key messages and backgrounders with their members, so all can respond quickly with the same basic messages. As importantly, senior managers now receive training in how to deal with public issues, and they understand that good environmental performance is the only acceptable business practice.

These developments owe much to the reverberations of the oil price shocks and, later, to the greening of Canada.