The Bird Lady

Scaly-breasted munia

In this Buddhist kingdom, you will often find a bird lady just outside the gate when you go to a large wat, or temple. Bird ladies sell freedom. They sell birds in tiny cages – cages scarcely larger than the birds themselves, and certainly not large enough for those trapped creatures to spread their wings. You don't get to keep the birds, however. For 20 baht (about 40 cents), you get to pull a pair of bamboo bars to release two birds into the wild. One bird is 10 baht, but six birds are 50.

Thailand’s bird ladies give a discount for volume. It is Ahsalahabucha Day, a Thai celebration of Buddha’s first sermon to his first five followers. I pay to release two birds, examining them before I set them free. They are scaly-breasted munias – twittering finch-like birds common on fields in flocks. If they reach maturity, their breast-plumage will take on its trademark brown and white scale-like pattern. My birds are fledglings, however; they are not strong, and their survival in the wild will be perilous. I wonder about this transaction. A woman holds for ransom two small creatures, and then they fly free. She now has a small amount of cash. But what does the purchaser have?

A practising Buddhist might gain some merit toward getting off the eternal Mandela of life, suffering and death. What I have gained, I am not sure. I do know, however, that it needs investigation. There is a metaphor here. Let’s follow it. Buddha’s first sermon enunciated the four principles of Buddhism – the Four Noble Truths. All things are a source of suffering, he taught. Because it can never be fully satisfied, desire is the cause of suffering. Freedom from suffering can only be obtained through the cessation of desire. Lastly, moderation between the extremes of sensualism and asceticism – “the middle way” – can eliminate desire and therefore suffering. With these teachings, he set off a chain reaction that transformed much of Asian society.

Twenty-five hundred years later, Asian societies whose kindness and gentility owe much to these ideas are rushing headlong into market economies, thereby beginning a different kind of transformation. They are responding to market economics so effectively that they are beating the creators of capitalism at their own game. As the pennant of capitalism moves across Asia, however, it is being handed to peoples for whom some of its fundamental ideas are culturally absurd. For example, many scholars maintain that capitalism arose out of the oldest known environmental mission statement: ''be fruitful and multiply, and fill the earth and subdue it; and have dominion over the fish of the sea and over the birds of the air and over every living thing that moves upon the earth.''

Control over nature is woven into the fabric of western society as a moral imperative. In the prevailing view in much of Asia, however, mastery over nature can be nothing less than illusion. Moreover, the motor of market economics is the idea that maximum consumption leads to maximum satisfaction. This notion is fundamentally at odds with Buddha’s concept of the middle way. Even so, it is common intellectual currency in the vast cities of Shanghai, Mumbai and Bangkok to describe these years as Asia’s Century.

In this century, goes the thinking, the mainland's nations will continue to bring people out of poverty at record rates. In this century, previously impoverished countries will develop consumer economies to rival those of America, Europe and Japan. The countries of Asia have already become the workshops of the world; in this century, they will advance that position.

Outside my windows are two miles of lush green fields which end abruptly at the foot of a range of jungled mountains – distant foothills of the Himalayas. I live in a provincial outpost in Thailand – an economically insignificant country in the Third World. My home is in the northern periphery of Southeast Asia – a clutch of nations that shelter more than half a billion souls. To the north is China, with its huge population; to the west, India with its equally teeming cities, towns and villages. Together, these mostly prospering countries host more than half the world’s population. Justifiably, they all want to continue to prosper, and their demands upon the planet are rapidly increasing.

In Asia’s Century, countless bicycles are giving way to motorbikes. Water buffalo are still yielding to mechanized farm equipment. Bangkok's legendary traffic jams tell the continent’s story of rocketing automobile demand. The economic growth in this region will lead to resource depletion on an extraordinary scale in Asia’s Century. Suppose, for example, each Asian begins to demand four barrels of oil per year instead of less than two barrels today – a big increase, but per person consumption still dramatically below that of the rich countries. Suppose also that production and consumption elsewhere do not change.

Using those simplistic assumptions, new Asian demand would soon consume almost all the oil the OPEC cartel now delivers to global markets. Inside and outside the Arabian Peninsula, the world’s great basins of conventional oil are in steep decline. Seen against the few thousand years since civilization began, a century is a considerable time. However, it is almost nothing when compared to the epochs since cellular life debuted on primordial seas and oceans.

Life exploded onto the planet during the Cambrian period of geologic time, beginning 540 million years ago. Its organisms were the raw material for the first oil. Now the world’s most widely traded commodity, oil supplies about 95 per cent of all transportation fuels and 40 per cent of the world's commercial energy. Think of the ages since life and oil began to form as if they have been ticking by on the face of a grandfather clock, starting in the earliest moments of the morning.

It was not until early afternoon that dinosaurs evolved and began to roam. They dominated Earth until seven minutes after nine in the evening. While oil has been developing on this imaginary clock for almost 24 hours, the petroleum industry – now the world’s largest business – did not emerge until five hundredths of a second before midnight. Yet on the stroke of twelve, the last of the world’s conventional oil will be gone. That will be the case whether production lasts for another hundred years, or two hundred.

 We are clever apes indeed, but we cannot replace half a billion years’ accumulation of this vital energy. During the few hundredths of a second since we began consuming oil, we have become much wealthier. Indeed, our wealth is now so closely linked to oil consumption, and our lives are so dependent upon it, that Daniel Yergin’s magisterial history of the industry defined contemporary humanity as Hydrocarbon Man. As Hydrocarbon Man becomes wealthier, we eat more fish – mostly from the world ocean that gave rise to life itself.

 Consider the consequences. A recent letter to the respected scientific journal Nature rattled the academic and environmental communities when it described the results of a lengthy study of the world’s commercial fisheries. This dry report concludes that 90 percent of the raw mass of predatory wild fish in the world’s oceans has disappeared in the last half century. They have been fished out.

Even so, radar and satellite finding techniques and other tools are making the industry’s fishing arsenal more effective. Thus, the entrapment of species is intensifying, not diminishing. Will the world’s fishing fleets soon be trawling empty seas? In a widely quoted statement, the two authors – both academic marine biologists – made no secret of their concern. “From giant blue marlin to mighty bluefin tuna, and from tropical groupers to Antarctic cod, industrial fishing has scoured the global ocean,” said one. “There is no blue frontier left….This isn't just about one species. The sustainability of fisheries is being severely compromised worldwide.” Added the other, "These are the megafauna, the big predators of the sea, and the species we most value. Their depletion not only threatens the future of these fish and the fishers that depend on them, it could also bring about a complete reorganization of ocean ecosystems, with unknown global consequences."

Such stories make human societies seem like cancers on the body of the planet – clusters of cells gone wild, gobbling resources at rates that threaten the very systems that make life possible. But the image is flawed: the death of the creature does not spell the death of creation. During the last half billion years, there have been several great extinctions – geologically brief periods in which countless species suddenly died out. But life always went on, and it will.

We need nature, but nature does not need us. The difference between the extinctions of the present era and those of the ancient past is that today’s are being driven by species rather than act of God. For the first time since the paleontological clock began ticking, one species has grown strong enough to threaten much of the planet.

This is the case for humanity as the bird in the bamboo cage. Who is holding that cage? Call her Earth Mother. Call her Gaia. Call her Bird Lady. The cage she holds is one of our making. As far as I can figure, the base price we will have to offer for our freedom is an exit from the treadmill of ever-greater consumption – abandonment of the notion that greater consumption for greater satisfaction is the proper engine of growth.

Such an idea was sustainable during the millennia in which personal consumption was small relative to the richness of the planet’s wealth. This is no longer so, and soon Asia’s rapid growth will force the issue. To be sprung from our cage, we must collectively endorse the notion of wise consumption in the interest of greater well-being.

What form that will take, I do not know. But as those moments of crisis arrive, I am sure Asia will have the upper hand. If this is Asia’s Century, it is not only because the continent has comparative economic advantages – among others, cheap labour, land and infrastructure – compared to the rich world. It is also because these nations have a living history of modest consumption. They have cultural traditions that make it relatively simple for large numbers of people to quickly shift back into a subsistence economy: such behaviour saved Thailand after the currency crisis of 1997, for example. In addition, many Asians hold deep-rooted beliefs sanctifying moderate consumption in the interest of a life of greater depth and substance. The fourth noble truth is one such idea.

By contrast, in the rich world there is little sense of the large gap of irrelevance between consumption and happiness, despite a wealth of academic findings about the relationship between the two. Psychology says happiness does not appear to depend significantly on external circumstances such as wealth, which many economists define as the ability to consume. In the world’s most consumptive nations, happiness levels today are no greater than they were fifty years ago. Indeed, in some cases the contrary may well be the case.

Westerners have consumed greatly, but not wisely. My children still live in Canada, a resource-rich country whose small numbers have lived abundantly off Earth’s wealth for centuries. I worry because they will inherit a world from which so much of nature’s bounty has been drained. Because Canada and the other rich countries have lived so well for so long, their children have no collective memory of times or traditions in which greater consumption was not society’s primary economic goal, and may have great trouble adapting to a globe without many of the riches which always before have been so easy to exploit. Will they fledge into a natural world so impoverished that even the option of small cage versus perils of freedom is unavailable?

August 2003

Where it All Began

Equipment in the Underground Test Facility proved the effectiveness of  SAGD 

A quarter-century after the first Canadian horizontal well was drilled, the technology is the cornerstone of today's industry.

This article appears in the June issue of Oilweek

By Peter McKenzie-Brown
The world of oil and gas was quite a different place a quarter century ago. Production mostly came straight up out of vertical holes. Though the Texans had drilled the first horizontal well in 1929, in Canada horizontal drilling was still mostly an esoteric, unproved and untested technology.

In 1987, all that began to change – so much so that, during the last 25 years, it simultaneously emerged as a standard production technique and revolutionized production. One result is that many petroleum resources have become technology-driven plays. Another is that reserves are way, way up.

In a sense, the most important uses of horizontal drilling technologies are reverse images of each other. “What makes horizontal drilling for nonconventional resources (like shale gas and tight oil) so attractive to the financial community is the very high initial rate of return. In the beginning, production rates are extremely high, although they quickly taper off. You have to remember that these applications enable you to get highly desirable hydrocarbons out of really poor reservoirs,” according to Dave Russum, who is director of geosciences at AJM Deloitte, a consultancy.

The oilsands represent the mirror image of this situation. “You are drilling into tremendous reservoir rocks – highly porous and very permeable, so there’s plenty of oil in there. But until you process the stuff it isn’t a particularly attractive commodity.”

The Bitumen Story

It’s true that in April 1978 Imperial Oil drilled Canada’s first horizontal well into the Clearwater formation at Cold Lake – a storied well overseen by Dr. Roger Butler in an early test of a system of oilsands production now known as steam-assisted gravity drainage (SAGD). After that test and a less interesting effort by Texaco a couple of years later, in Canada the technique mostly languished until 1987.

Then the advent of improved down-hole drilling motors and the invention of other necessary supporting equipment, materials, and technologies – particularly down-hole telemetry equipment, which enabled rigs to drill straight on target – led to an explosion of new applications for this technology. Producers and the drilling and service firms that support them found endless new uses for directional drilling – especially as it is used for horizontal wells.

Appropriately, in Canada the first horizontal wells drilled after Imperial’s early test were part of the Underground Test Facility (UTF), which celebrated its official opening on June 29^th, 1987. Developed by the Alberta Oil Sands Technology and Research Authority (AOSTRA), the UTF involved a pair of tunnels driven into limestone 15 metres below the reservoir.

Within those tunnels, AOSTRA constructed large well chambers. “Pairs of injection and production wells were drilled upwards from the well chambers at a 17⁰ slant,” according to the mining engineer behind the project, Gerry Stephenson, “and deflected horizontally into the base of the reservoir. The mobilized bitumen drained by gravity from the steam chamber in the reservoir to the well head in the tunnel and all of the production was pumped from a central location.” Those tests proved Butler’s theories about SAGD beyond any possible doubt.

Over its 15-year life, the UTF also evaluated other recovery strategies, but nothing compared to its SAGD results. “AOSTRA’s staff had estimated that the recovery might be somewhere between 30 percent and 45 percent of the bitumen in place” during the Phase A tests, according to Stephenson. “We actually got 65 percent recovery. The steam chambers formed by mobilization of the bitumen spread way beyond the area we’d expected….Over the 10-year life of the well pairs, Phase B got a steam/oil ratio, the most critical figure of all, of 2.3 to one.”

The tests at the UTF forever transformed Canada’s oilsands industry. Today, SAGD is responsible for more than half of Canada’s bitumen production.

Ironically, Sceptre Resources drilled the first horizontal well in Saskatchewan to test a SAGD-like system at Tangleflags, just as the UTF began its definitive tests. Drilled into the shallow (450-metre) Lloydminster sandstone, this primitive application of a form of SAGD illustrated the kinds of problems horizontal drilling could overcome. With an active aquifer below and a gas cap above, the reservoir’s pay thickness was about 27 metres. The oil was heavy: about 13^o API. Primary production from the field had been meagre (0.6% of the oil in place), and the use of cyclic steam stimulation, which uses vertical production wells, had flopped when they tapped the aquifer and started producing 99% water.

That was when the company decided to try SAGD – not the technique we use today, but the primitive version Imperial had tried out nine years earlier. Sceptre injected steam through four vertical wells near the gas-oil contact, draining the mobilized oil through a horizontal well. At the industry’s leading edge, the company found itself with a technical and economic success.

Fast Production from Tight Reservoirs

More than any other series of innovations, the technology-intensive processes that now surround directional drilling have enabled the industry to get production out of otherwise unproductive rock. In August of that same transformational year, Alberta Energy drilled the first horizontal well into the Glauconitic formation at Suffield. This was the first time a Canadian operator drilled horizontally into a conventional oilfield.

Things then quickly sped up. In February 1998 alone, three significant projects based on horizontal drilling took off. Amoco began a 10-well horizontal drilling program at Athabasca, into the Wabiskaw formation. Canadian Hunter drilled gas wells at Ansell (Alberta) into the Cardium formation and at Helmet (British Columbia) into the Jean Marie. A few months later, Shell Canada drilled for Mississippian oil in Saskatchewan, at Weyburn. This early application of the technology was meant to connect isolated small reservoirs or improving contact within heterogeneous rocks to enhance the sweep efficiency.

“In the 1990s the big push was to explore conventional carbonate rocks, especially from the Mississippian in Saskatchewan,” according to AJM Deloitte’s Russum. “The idea was to develop known reservoirs where the rock quality was variable, using horizontal wells to extract more oil from those formations…. Many different companies hopped on to the horizontal drilling band wagon in Saskatchewan with more than 500 wells drilled into the Mississippian in 1997 alone.  In that year more than 1300 horizontal oil wells were drilled across the basin – a tally that was not beaten until 2007.”

Horizontal drilling also began to tap the heavier oils in Saskatchewan and southeastern Alberta in the 1990s, and there was a lot of experimentation in other reservoirs. Also, of course, in that decade SAGD began to be developed in its modern form.

As horizontal drilling became more commonplace, the petroleum industry began combining it with innovations in both drilling and well completion technologies and ideas. The result has been like a snowball rolling downhill. Horizontal drilling has been enhanced by geo-steering, measurement-while-drilling, coil tubing, down-hole motors and new bit design, for example. Also, producers can now drill multilateral horizontal wells from a single drilling pad.

Perhaps the important recent development on the drilling side is the monobore. Monobore drilling involves running a casing string, then forcing a steel cone down the well to expand it in the hole. This process is repeated with identical casing strings. Thus, monobore completions have the revolutionary characteristic of installing a string with the same interior diameter from top to bottom. “These are making a huge difference,” said Russum. “In the past you had to drill a vertical well, then run the casing to the bottom and wait for the casing to set before you could begin to drill the horizontal leg. Monobores help reduce those time-consuming steps.”

Although technologies like microseismic are also making a difference, the most important developments on the completion side have involved the increasing power and sophistication of hydraulic fracturing. Better fracking has developed because of new packers, better pumping equipment and better treatment fluids and proppants. “It’s now easier to isolate horizontal wells and to put fractures into certain points of the formation,” according to Russum. “In the early days, each stage of multistage fracking would take a whole day. Each frack would have to be tested separately before you proceeded to the next one. Today it’s a continuous process.”

These clusters of technological breakthroughs first created the shale gas revolution. Pioneered by an American, George Mitchell, in the Barnett shale in Texas, tight gas reservoirs began yielding highly economic volumes of natural gas – and, not incidentally, drove down the price of gas. Some observers now describe natural gas as a low-value by-product encountered in shale reservoirs in the quest for natural gas liquids.

From a production perspective, the other great outcome from this cluster of technologies has been the development of tight oil from shale – what Russum prefers to call “conventional oil from more shaley, low-permeability reservoirs.” One outcome is that both western Canada and the US are experiencing growing light oil production for the first time in decades – much of it coming from the Bakken play in North Dakota and Montana. After decades of decline in Alberta, for example, light oil production has recently risen to ten year highs.

An Explosion of Uses

These new technologies are changing almost everything about Canada’s petroleum industry. For example, horizontal wells are now a huge part of gas storage. “You can store gas very quickly into those wells,” said Russum, “and you can extract it quickly, too. Then there is the whole area of trying to reduce surface impact. I think we’re going to see more and more of that. Surface owners are more and more reluctant to have pumpjacks and other surface equipment on their land, and horizontal wells are less likely to disturb natural habitat. There is also extended reach, so you can reach under lakes and towns and cities. You can use it to reduce water production in a thin reservoir located over an aquifer.”

The economics of the horizontal well are also greatly improved, especially when you are planning production from a narrow reservoir – ten metres thick, for example. Horizontal wells provide much greater contact with the reservoir per dollar of drilling than do their vertical kin. And when they are drilled in search of unconventional resources like shale gas and tight oil, the producer gets a quick payback because initial production rates are so high.

Still not convinced? Then let the numbers tell the tale. According to an AJM Deloitte study which is complete to late 2011, more than 30,000 horizontal wells have produced conventional oil or gas in Western Canada over the past twenty five years.  Of that tally, 4,300 were completed in 2011.  This set a record for horizontal oil drilling: nearly 3,500 wells (led by the Cardium, Viking and Bakken), and an additional 800 wells focused on gas – mainly attracted by the high liquids content in the Montney and Middle Mannville. Today, half of Western Canada’s wells are being drilled horizontally.

Is horizontal drilling helping bring about any other changes? Perhaps it is even changing the way corporations work. “Companies that fail to adequately research the geology are putting themselves at considerable risk if they assume all resource plays are alike and that more and larger fracks are the solution to economic production,” according to Russum. Even so, engineers are increasingly replacing geologists in the executive suite.

Traditional geologists who spent entire careers looking for conventional reservoirs are now more interested in minor variations in rock properties, in stress regimes and in proximity to source rock. In terms of traditional petro-geology this is a difficult concept to grasp, but to a large extent it is a response to the revolution spawned by horizontal drilling.

Oilsands companies in particular, but also other companies involved in modern resource plays are basing their business plans on step-by-step, decades-long development of vast and well-defined resources. This means traditional wheeling-and-dealing is at least partly on the decline – to a large extent replaced by courting cash-rich foreign companies with deep pockets and the desire to support these capital-intensive activities.

Tell Your Banker to Buzz Off!

As lines of bank credit grow increasingly restrictive, royalty financing offers new options for operators. This article appears in the February issue of Oilweek

By Peter McKenzie-Brown and Richard Graham

Especially if you’re a natural gas producer, it can be tough to get credit these days. What are you going to do?

One possibility is to do what Compton Petroleum did last spring. Primarily a gas producer, the company sold a 5% royalty interest in 19,000 barrels of oil equivalent (BOEs) production per day, plus a 5% interest in 600,000 undeveloped acres to Caledonian Royalty Corporation, a company founded and managed by oil and gas financier Jim Kinnear.

In a way, royalty financing is filling a gap created by the elimination of energy trusts – at least, that’s what conventional wisdom would like you to think. However, as we researched this story, it became increasingly clear that royalty financing not only meets the needs of investors (especially heavy hitters), but it is also an excellent tool to meet the industry’s needs – natural gas companies like Compton Petroleum, for example, but other companies as well. While the industry traditionally associates the idea of royalties with government take, the new players in this area are promoting it as an effective alternative financing tool. While the jury is still out on whether it will be a preferred form of funding during the next boom, right now it has a lot of merit.

The Olden Days
Royalty funding is not new in Canada’s oil and gas sector, but the industry has to a large extent lost its collective memory of royalty financing. The founder of royalty financing in Canada was R.A. (Bob) Brown who, with his son – also named Bob Brown – later turned Home Oil into a major independent oil company.

During the Great Depression royalty financing played a critical role in the development of Turner Valley – at the time “the biggest oilfield in the British Empire.” On June 16, 1936, Brown senior’s Turner Valley Royalties #1 well began flowing 850 barrels of crude oil per day. Funded by royalty financing which guaranteed investors a percentage production from successful wells, Royalties #1 found Turner Valley’s oil formation two decades after earlier producers began stripping naphtha from wet gas discoveries there. This meant the first generation of producers had wasted much of the pressure needed to produce light oil from the reservoir.

Royalties financed 69 other wells in Turner Valley in the two years following Brown’s discovery. Since only two of those wells were dry, the primary constraint on new investment was the rapid saturation of local crude oil markets.

Royalties financing didn’t last, however. In 1938 the federal government decreed that income from oil production was taxable as profits in the hands of the producing company. In the investor’s hands it was taxed again as income, rather than return of capital. Although a producing company appealed this decision successfully, the incident shook confidence in the system. Indeed, in 1942 Ottawa amended the Income Tax Act to tax oil income from royalty trusts at wartime rates. Although the federal government repealed this provision in 1950, it was 70 years before petroleum royalties again became a significant alternative to traditional debt and equity.

Teams at Play
In recent years, at least four teams have suited up for the royalty game. Each team has its own style of play and a strategy that sounds like a winner. Brickburn Asset Management has the most passive style of play. Range Royalty Management is the brainchild of Clayton Woitas, founder of Renaissance Energy, and effectively combines royalty financing with E&P. Caledonian, founded and controlled by Jim Kinnear, is new while the fourth, Freehold Royalties Ltd. has roots going back to the creation of Canada.

Until it converted to a dividend-paying corporation at the beginning of 2011, Freehold was a publicly listed trust that issued distributions based on a large number of diverse royalty-generating properties (mineral rights and gross overriding royalties) and working interest properties. Its income comes from oil, gas, liquids and potash. Many of its properties are legacy assets – royalty rights which Ottawa granted to railroads and the Hudson’s Bay Company as part of the national effort to secure Western Canada. Freehold has interests in more than two million gross acres of land and 23,000 wells.

In a statement, the company’s president and chief executive officer, Bill Ingram, said that most “of our oil and gas production comes from mineral title lands and gross overriding royalties, which have no associated capital or operating costs; thus we have relatively low capital expenditure requirements. The strength of our royalties has allowed us to preserve a high payout ratio historically and should allow us to maintain a high dividend payout.”

The newest team is that of financier Jim Kinnear, who sees royalty financing as an extension of a common practice in Canada’s mining sector. When he started out in the securities business, says Kinnear, “we invested in small mining syndicates that had acquired claims – money returned plus a carried interest. I learned about returning capital to investors. People liked to see a return of cash or cash flow, and they still do.”

Last year, after retiring from Pengrowth Energy Trust – a business he founded and managed for over 20 years – Kinnear began applying this lesson in finance to oil and gas in an innovative way. So far he and his investors have placed $100 million in Caledonian Royalty Corporation. Their royalty investments – which represent registered interests in land and rank ahead of banks and other creditors – allow qualified investors to participate in cash flow based on production. Caledonian’s royalty interests include current production and potential future production from a large undeveloped land base in Alberta. At present, those assets are heavily weighted towards natural gas.

Range Royalty Management operates rather more like a traditional oil company, but also does financing through the issuance of royalties. The company was not willing to be interviewed for this story, but a source who asked to remain anonymous describes the firm as having “a great technical team. While they always want an overriding royalty, they get at it in a different way. They begin at the grassroots level” – by going to land sales, drilling and frequently operating oil and gas properties. Issuing royalties effectively gives the company financing that bears no interest, doesn’t need to be repaid and is free of commodity price risk.

The Problem with PUDs
Another newcomer to royalty financing is Bill Bonner, president of Brickburn Asset Management. Brickburn manages four partnership funds that invest in royalty interests under the WCSB brand name.

Although he has had a long career in oil and gas financing, Bonner only added royalty financing to his company’s portfolio in 2008. His system is both conservative and traditional. “We raise capital through prospectus,” he explains, “then make that capital available to experienced operators for the completion of development wells. In return, we earn a gross overriding royalty. One way to think about this is that we rent the operator’s wellbores. We are not concerned with any of the traditional costs, including the well’s ultimate abandonment.” He adds, “The sanctity of the royalty position is a very special place to get to.”

Bonner is adamant that royalty financing in its own right is an effective and robust form of finance rather than a replacement for the energy trust. When the oil industry goes into boom mode again, “we think there will still be opportunities for this kind of instrument, although candidly we don’t know for sure.”

He adds that “the main link between us and income trusts is that we pay out capital as we receive it. We provide a stream of income which the investor really likes. We are very much a distribution model as opposed to a model where you retain capital and grow. One of the advantages we have is that our investors get a tax write-off – a 30% Canadian Development Expense, which enables them to write off all of the money they have invested. It just takes time.”

He adds, “We have completed five partnerships totalling $82 million. We only take the money for three years. At that point our prospectuses say we will offer a ‘liquidity event’ to return the capital investment back to the investor. Our game plan is to somehow monetize the property after our investments have gone through a period of flush production – either by selling it outright or by somehow putting it into a going-concern business.”

Brickburn’s first royalty partnership came about in 2008. After the 2006 Halloween Massacre imposed a new tax on energy trusts, he says “it became increasingly difficult for smaller energy businesses to finance growth because for them the liquidation opportunity (selling their assets to energy trusts) had disappeared. So we moved in with this royalty instrument.” Complicating the tax problem was the financial crisis. Traditional sources of equity and debt financing for junior oil and gas companies seemed to have disappeared. Part of the solution was royalty financing.

Brickburn royalty partnerships have participated in more than 70 wells, 95% of which used horizontal multi-frac technology. “One of the reasons operators like us,” according to Bonner, “is that we extend their budgets. If we provide one and a half million dollars for a horizontal well, it frees up that much money for them to go do something else.” Royalties can add to the companies’ bottom lines in other ways, too. One of the main reasons is that operators tend to carry inventories of “proven undeveloped reserves,” or PUDs.

“The problem with PUDs,” says Bonner, “is that you get credit on your balance sheet for them as a proven resource, but now you have to throw a lot of money at them to turn them into developed resource. What we did was to come along and offer operators the opportunity to develop those PUDs in a way that was not dilutive to equity” since royalty interest investments equate to non-repayable loans. “Even though interest rates for the last couple of years have been close to zero, royalty financing is attractive because you don’t have to pay back the principle. When operators began to see this, they quickly realized that taking our capital was very accretive to the capital they had to spend themselves.”

Through its family of funds, Brickburn has acquired royalty interests through 11 operating companies, but is bound by agreement not to mention names. However, Delphi Energy and Bellatrix Exploration have both publically acknowledged that they use royalty financing from Brickburn.

Revolution Repeated

The Western Canada Sedimentary Basin. This article appears in the February issue of Oilweek.

By Peter McKenzie-Brown

First came the revolution in natural gas production – the shift to shale gas which, by bringing huge new stores of natural gas into the market drove prices down and made it necessary to fundamentally restructure Canada’s gas-prone petroleum sector. Now comes the revolution in the oilfield. Ironically, the same technologies that made shale gas possible are enabling the industry to begin the restructuring that the shift to shale gas made necessary.

“Oil doesn’t flow as well as gas,” Legacy Oil & Gas president Trent Yanko reminds us. “So in the oilfields of Alberta, especially, is a tremendous opportunity to recover unproduced oil. Original oil in place was in the billions of barrels, so if you can add only one, two, three percent to recovery there is quite an opportunity. You don’t have to be a wildcatter out in the jungle somewhere. All you have to do is better exploit what we already know is there.”

The technologies that made the shale gas revolution possible are beginning to have a similar impact in the light and conventional oil sector, which can now develop reservoirs that could not be exploited until energy prices and new technologies made production economic. For small companies in particular, this is presenting exceptional opportunities. From start-ups to mid-caps, companies like TriAxon and PetroBakken Energy are creating profitable enterprises from oilfields discovered 50 years ago. Already successful in similar enterprises, Legacy is taking on the big kahuna – the century-old field that put Canada’s petroleum headquarters on the map.
Juniors and the Treadmill

Since it became commonplace in the late 1980s, horizontal drilling has been enhanced by increased drilling efficiency. Much longer horizontal legs are now possible: many are two and three kilometres in length. This is possible because of improvements in bit design, the increasingly effective use of coil tubing and better down-hole motors. Other contributors include geo-steering and increasingly effective measurement-while-drilling (MWD) tools and techniques. Most important of all is multi-stage fracturing. The industry can now isolate many completion zones along lengthy horizontal wellbores: a two-kilometre horizontal leg can host up to 20 hydraulic fractures.

These technologies are making formations like the Bakken viable. Increasingly, the technologies that created the shale gas revolution – long horizontal wells and multistage fracturing – are being applied to aging light oil reservoirs in North America. This production phenomenon has also involved largely unacknowledged regulatory responses by the governments of Western Canada. These factors and other technologies are opening up important new opportunities for production from largely depleted reservoirs. For example, Gary Leach – executive director of SEPAC (the Small Explorers and Producers Association of Canada) – notes that “microseismic for the more precise design of frac jobs is a particularly important new technology.”

A year ago, TriAxon Resources represented a big success story among private junior oil companies. The company was created with what in 2006 was the novel idea of applying the cluster of new technologies to oil production. After screening available prospects, the company focused on the Bakken, Glauconite, Cardium, and Viking formations. The company raised $87 million in private financing; two and a half years later the partners sold out to Crescent Point Energy for $257 million.

Then, according to former president Jeff Saponja, he and his two partners – chief operating officer Colin Flanagan and operations vice president Rob Hari – took a two-week break before establishing TriAxon Oil Corp. – “TriAxon Two,” he calls it.

The opportunities come with a cost, of course. Saponja cautions that those technologies present unique challenges because they are so capital-intensive they. “Fifteen years ago, in the heyday of conventional oil exploration and production, you would put $150,000 to maybe $500,000 into the ground to get 200,000 barrels of oil,” according to Saponja. “Now you have to put maybe $4 million in the ground to get 200,000 barrels of oil, and you have a 50% to 80% initial rate of decline. To get these multistage frac wells to work you have to drill a lot of wells in these lower quality reservoirs.” This leads to what he calls the treadmill.

“To offset decline you have to be continually drilling, because the decline rate is so high. The main point of the equation is that these horizontal wells are very capital-intensive. Initially you get a very high rate of oil production but they will decline quite quickly. The economics are actually fairly marginal on a well to well basis, so you have to drill a lot of wells to benefit from scale. Except in the Bakken,” he says, “Most of these multistage frac wells really struggle if oil prices are below $60 or $70. For these wells to be really profitable, oil has to be over $80 a barrel.”

“You have to be continually drilling to offset decline. It’s called the treadmill. The main point of the equation is that these horizontal wells are very capital-intensive. Initially you get a very high rate of oil production but they will decline quite quickly. The economics are actually fairly marginal on a well-to-well basis, so you have to drill a lot of wells to benefit from scale. Except in the Bakken,” he says, “Most of these multistage frac wells really struggle if oil prices are below $60 or $70. For these wells to be really profitable, oil has to be over $80 a barrel.”

Does it make sense for private companies like TriAxon to stay public? According to Saponja, the economics of staying private are iffy. “These are very expensive wells. For a junior to stay on the treadmill becomes very difficult after you reach 3,000 or 4,000 barrels a day because you need a lot of capital to grow production and combat decline. The challenge that juniors face is that they have to either get their hands on more capital or be prepared to monetize their assets by selling them off. That’s the case for going public: it gives you access to low-cost capital. However, my partners and I are happy building basements, then selling them to the highest bidder.”

Midcaps in the Bakken
The highest bidder for TriAxon One was Crescent Point Energy – one of the two largest players in the Bakken, and the main competitor of PetroBakken, a midcap headed by Gregg Smith. “Our decline rates in the Bakken are about 60% in the first year, so we have to keep drilling to maintain production rates. You have to experiment a lot to be successful in plays like this. When you come into these plays your initial results are going to be mixed, but as you refine your drilling and production systems they improve.”

With considerable satisfaction, Smith notes his company’s success in drilling bilaterals from a single wellpad. “For PetroBakken to drill a single horizontal, the cost is $2.4 million. However, to drill two bilaterals from a single pad costs $3.6 million. It’s much more capital-effective, and it delivers an extra 50,000 barrels per well into the bargain.”

According to SEPAC’s Leach, the obviously improved economics of tighter spacing is generating “a regulatory response. The design of wellpads has to be different, and the new wellpads provide both environmental and economic benefits. Regulators are beginning to respond in all three western provinces.”

He adds, “The Cardium just began to take off in early 2009, and it was SEPAC companies – junior and midsized companies – that set the stage for this. Those sectors are looking to restructure because of the long-term poor prospects for natural gas, and this has played a role in that. It’s really turned around the fortunes of the industry, and generated a lot of investor interest.” With some satisfaction, he notes that multinational companies are coming back to North America to get back into the light and conventional oil resource plays. This involves a turnabout for some companies. for example, Talisman sold off a lot of its Alberta oil production just a few years ago.

PetroBakken’s Smith stresses that the situation in Canada is quite different than that in the United States. The Americans “are drilling shale oil plays. (By contrast) most of the horizontal wells with multistage fraccing in Canada are into reservoirs that were previously simply uneconomic or marginally economic (if you were trying to produce) oil from a vertical well.” This is all changing now, he says. “Now you’re seeing people try to tie up shale oil plays like the Alberta Bakken, the Duvernay and the Nordegg.”

Back to the Future
Of course, old hands in the oil industry are the first to tell you that technology has always been the key factor in expanding production. In fact, in this period of oilfield revolution the importance of technology is more obvious than ever before. According to Legacy president Trent Yanko, “Technology has always been an important part of oilfield development in Canada. I started out in Saskatchewan in 1980s, which was really Canada’s leader in horizontal drilling because of a major government incentive program.” After a few years the industry found itself drilling more horizontals in Saskatchewan than anywhere else in North America – “even the Austin Chalk” in Texas.

“Southeast Saskatchewan has been a classic case of the use of technology to extend the life of reservoirs,” Yanko continues. “Since the 1960s the industry has applied waterflood there, horizontal drilling, CO2 injection and other technologies, each of them extending the life of the province’s south-eastern petroleum reserves. As a result, in the late 1990s oil production matched what everybody thought had been the peak oil levels of 1966, and today the province is at record production.”

Almost all of the reservoirs now being developed with these technologies were discovered after 1947, when the Leduc discovery ushered in the industry’s modern age. Yanko, however, has plans to apply them in the petroleum industry’s birthplace. “Through the acquisition of a private company in July,” he says, “we acquired the Turner Valley oilfield. We control most of the production and all the facilities there.”

To understand Turner Valley’s significance, it’s worth noting that the field’s proximity to Calgary is the reason Canada’s petroleum sector is headquartered in the city. And, as SEPAC’s Gary Leach observes, Calgary now hosts the 45% of the world’s publicly traded oil and gas companies.

As he discusses this property, Trent Yanko becomes palpably excited. “There is still a lot of meat on the bone. There’s been less than 1% decline in (annual) oil production (from Turner Valley) over the last fifty years. The original oil in place was 1.3 billion barrels of 40° oil, and the historical recovery factor to date is only about 12%. So we think it has huge development potential. Before we acquired the property, the last vertical wells were drilled there in the 1940s. There was some horizontal drilling in the 1990s, but the field has been non-core for a long time.”

Although Legacy is proceeding cautiously, its president is thinking big. To begin with, Yanko believes Legacy has mapped a Cardium trend right on top of the field – “11 miles long and about 1½ miles wide,” with 10 metres gross maximum thickness. “In Turner Valley there’s a vertical well that just missed the Cardium and still produced more than 19,000 barrels. Otherwise, that trend hasn’t even been touched.”

“We believe the application of horizontal drilling and multi-stage frac technology can increase the recovery factor,” he adds. “So can infill drilling and reactivation of the waterflood. This property hits a lot of our hot buttons.” In the fall, the company drilled a number of vertical wells into the field. “We are going to frac them, and they will provide a great controlled environment to help us understand the horizons for future horizontal drilling. These wells will help us design that drilling program properly.”

When Turner Valley was first drilled in 1913, it was a wet gas field from which liquids were extracted and natural gas flared. A century later, with conventional gas again a marginally economic commodity, the prize sought in Turner Valley reservoirs is again its hydrocarbon liquids. The difference today is the toolkit.

Maintaining the Faith

Five visionaries who changed the path of the oilsands industry, and the wall over which the sixth must climb.Photo: Karl Clark

This article appears in the September 2010 issue of Oilsands Review

By Peter McKenzie-Brown

Oilsands development continually hits a wall of some kind, and obstacles to development seem insurmountable. However, at critical times in the history of the oilsands, a visionary leads the charge over the wall and an important new stage of development takes place. This is the idea behind an excellent presentation titled “Visionaries – Climbing the Wall” given by Dr. Clement Bowman. The present commentary develops that idea, but mostly uses different historical resources.

By the 1920s it was clear that the sands are not underlain by a huge pool of light, source oil. The oilsands are just what they appear to be: huge deposits of sand saturated with thick, gunky bitumen. Encouraged by government, some entrepreneurs tried paving roads with the stuff. No luck; now what?

Enter a research chemist Bowman’s first visionary. With tremendous determination and limited support from the newly fledged Alberta Research Council, his employer, between 1923 and 1930 Clark developed and demonstrated the bitumen extraction process which, with some tweaks, is in use today in oilsands mines. His work made it clear that oil can be extracted from the sands. His name was Karl Clark.

Over the next two decades a few small projects began producing. They were not commercially successful, however, and didn’t use Clark’s extraction process. Each was eventually destroyed by fire. After the Second World War there was no commercial interest in this intractable resource – especially after the 1947 Leduc discovery, which made it clear that large reservoirs of light oil were available in the province.

Despite the legacy of failed commercial efforts, a Canadian politician became the next visionary. He arranged for the province to commission the Bitumount demonstration plant using Clark’s hot water process, and had the entire legislature visit the plant in 1949. He also commissioned an independent evaluation by Sidney Blair – an oilsands expert who began his oilsands career as Karl Clark’s research assistant. Blair concluded that the oil sands were “a commercially viable source of crude oil that could compete on the world market.” The visionary’s name was Ernest Manning, Alberta’s longest-serving premier.

The industry acquired additional oilsands properties and undertook experiments in mineable oilsands development in the 1950s and 1960s. For his part, Manning maintained a life-long belief in the importance of the sands to Canada.

In the 1960s, Alberta announced that it would only approve small oilsands projects. Light oil production was still growing, and the province didn’t want too much competition between oilsands and conventional oil. The province’s insistence on small-scale projects led to thin private sector support.

The visionary who surmounted this obstacle was an octogenarian and a personal friend of Premier Manning. On his insistence, Sun Oil Company filed an application for a 31,500 barrel per day project (later amended to 45,000 barrels per day). In 1967, he told his audience at opening ceremonies for Great Canadian Oil Sands that “No nation can long be secure in this atomic age unless it be amply supplied with petroleum . . . . It is the considered opinion of our group that if the North American continent is to produce the oil to meet its requirements in the years ahead, oil from the Athabasca area must of necessity play an important role.”

The name of this visionary is J. Howard Pew, and he was then chairman of Sun Oil Company, Today, GCOS is known as the Suncor Oilsands Plant.

In 1973, a second commercial project was losing private sector support because of the alarming escalation of costs besetting major North American projects. The Syncrude budget had more than doubled to $2.3 billion, and a major corporate partner pulled out. One man more than any other saved the day. He kept the remaining partners onside while marshalling equity participation in the project from the Alberta, Ontario and federal governments. He set up the first lab dedicated to oilsands research, and developed a long-term plan for upgrading bitumen. He was Syncrude’s first president, Frank Spragins.

In the 1970s, multinational companies had few active development plans for in situ leases. While these deeper deposits represent 80 per cent of the resource, there were no viable in situ technologies for the Athabasca, Peace River, Carbonates, or Wabasca deposits. The major exception was Imperial Oil, which was making limited progress at its Cold Lake site.

Once again a provincial politician took the lead. In 1975, he created the Alberta Oil Sands Technology Research Authority (AOSTRA) to provide government support for private research. During its 15-year life, AOSTRA provided $670 million of funding for oilsands research. Roger Butler’s SAGD process was the single most important advancement from this program. The politician? Premier Peter Lougheed.

Visionary number six has the opportunity to change Canada over this decade, leading the shift to production of cleaner, higher-value products from the oilsands.

There are more major obstacles, they are here and now, and they are environmental. Water, air and land are no longer free; there is a powerful green consciousness demanding that they be protected. Many consumers do not want to use products manufactured from Alberta’s “dirty oil.” Financial markets are concerned about the burden of environmental risk.

Who will help the industry overcome these obstacles? According to Clem Bowman, the next visionary will be able to articulate energy as an integrated system with the oilsands, hydro, natural gas, coal, nuclear and renewable energy all performing key roles. As importantly, that person will have the skills to forge the national will to make Canada a sustainable energy superpower.

Bowman does not conjecture on who this person might be,but his or her name will be marked in history.

In Alberta, An Instinctive Understanding

This article appears in the August issue of Oilweek magazine

By Peter McKenzie-Brown
“Pipelines are us,” Bob Taylor reminded me one day over lunch. Formerly Assistant Deputy Minister of Energy (Oil) with the Alberta government and now a consultant who specializes in energy systems innovation, he was discussing the two-fold importance of pipelines to the oilsands.

Before moving to the punch line, however, he put the discussion into context. Because of environmental worries, “oilsands producers are facing steadily increasing resistance in the provincial, national and international arenas.” He continued: “Unless we address these issues, the industry risks losing the social license to operate.”

With that, our wide-ranging discussion turned briefly to a particular theme. One reason you need pipelines is to take production to market. Without new or expanded pipelines, production growth would be next to impossible. However, the oilsands also require specialized pipeline networks to reduce their environmental impacts and to produce more efficiently.

Several examples illustrate this theme, and each carries a budget of $400 million or so. One is Williams Energy’s Boreal Pipeline, which will run from just north of Fort McMurray to Redwater, Alberta. The other is Enbridge’s Waupisoo pipeline expansion. Waupisoo originates at a terminal on Enbridge’s Athabasca Pipeline, 70 kilometres south of Fort McMurray. From there it stretches southwest to a pipeline hub near Edmonton. In addition, Pembina Pipelines is building a pair of lines to serve producers operating near Slave Lake.

Boreal Pipeline
The proposed new Williams pipeline is part of a project which turns waste into commercial products. So doing, it reduces carbon emissions and feeds valuable feedstock to the petrochemical sector. Williams Energy’s cryogenic liquids extraction plant near Fort McMurray recovers natural gas liquids and olefins from a stream of off-gases produced at the Suncor plant. Located about five kilometres away, it returns a sweet, leaner fuel to Suncor, which uses the returned gas for generating industrial heat. This enables the plant to operate more efficiently and reduces its carbon dioxide emissions.

As importantly, this profitable project provides feedstock for the petrochemical industry. Williams transports the recovered gas liquids to a facility in Redwater, northeast of Edmonton, for processing into products such as ethane, propane, butane, condensate and the olefins of ethylene, propylene and butylene. Before Williams began this operation, the hydrocarbons were just burned.

Now eight years old, this business has been so successful that Williams is expanding it. The new 420-kilometre long, 12-inch diameter Boreal pipeline will initially transport to Redwater up to 43,000 barrels of liquids per day. Later, it will expand to 125,000 barrels per day. Pipeline construction will take three seasons – from this fall to spring 2012.

As part of this large project, the company is building up processing facilities at both ends of the pipe. For example, Williams recently raised a 70-metre fractionation tower at its Redwater plant. This allows the company to produce a higher-quality product from the existing 14,000-barrel-per-day plant by splitting the butane and butylene components. There is much more to come.

Waupisoo Expansion
As summer began, Enbridge announced that it had made commitments to producers to make available an additional 229,000 barrels per day of capacity on the Waupisoo Pipeline. The 380-kilometre pipeline system is designed to carry up to 600,000 barrels per day of oilsands crude.

Four additional pumping stations and upgrades to two existing stations are the basis for the expansion which will take Waupisoo to design capacity of 600,000 barrels a day. The expansion will take place in two phases. The first 65,000 barrel per day expansion will be complete in the second half of 2012. An additional 190,000 barrels per day will be added by the second half of 2013.

The actual capacity of the line will depend on the viscosity of the crude it is carrying. Heavier oils travel more slowly, reducing capacity. Lighter oil blends are faster, and will be the transportation product used when the line is operating at design capacity.

Regulated by Alberta’s Energy Resources Conservation Board (ERCB), Waupisoo links producers to their upgraders and to refineries in the Edmonton area. It also connects to some of Canada’s other oil pipeline systems.

Enbridge operates the world’s longest crude oil and liquids transportation system, with a network of lines in Canada and the United States. The Waupisoo expansion will strengthen Enbridge’s position as the largest pipeline operator in the oil sands region; also, it likely will cement the company’s position as the shipper of choice for new oilsands producers.

Pembina
Of course, no one will ever dominate that market, as another pair of lines now under construction by Pembina Pipelines illustrates. The company’s new Nipisi Pipeline – designed initially to transport 100,000 barrels per day of diluted heavy oil – will reach from north of Slave Lake to Judy Creek. From there it will connect to an existing pipeline system, delivering products to the Edmonton area. Ultimately, Nipisi’s capacity can be doubled.

As part of this project, Pembina will construct its Mitsue Pipeline, which will ship 20,000 barrels per day of condensate diluent from Whitecourt to producers operating north of Slave Lake. Mitsue could ultimately be expanded to 45,000 barrels per day. Cost of this package of pipelines? About $440 million.

Each in its way, the pipelines covered in this review represent different aspects of what’s going on in the industry. On the one hand, they support growth. On the other, they contribute to greater efficiency and reduced environmental impacts. In Alberta the understanding of these two purposes seems almost instinctive – probably because, for decades, within the province vast networks of these systems have been operated by tens of thousands of employees. As a result, new pipelines and pipeline expansions encounter relatively little public resistance. Pipelines are us.

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Redrawing Mining Boundaries

Alberta's Regulator increases the size of the province's surface mineable area by 40 per cent.

By Peter McKenzie-Brown
Last year Alberta’s Energy Resources Conservation Board report rebalanced the provincial agency’s estimates of oilsands reserves, shifting them somewhat in the direction of surface mineable reserves. This raises questions about environmental impacts, for which the inimitable Pembina Institute have happily provided at least one group of answers.

The oilsands are a vast geological mystery, but last year the ERCB put into place a piece of the underlying puzzle 14.5 townships (1,350 square kilometres) in size. Mineable reserves are those with overburden of 65 metres or less. Based on an analysis of more than 2,000 exploratory wells drilled in recent years, the Board’s analysis increased the boundaries of the mineable Athabasca oilsands by almost 40%. The mineable oilsands area of north-eastern Alberta now measures 51.5 townships.

The first change in the surface mineable area since the Board first drew the boundaries in the early 1980s, this change increases total established mineable reserves – in many jurisdictions called “proved” reserves – by 11%, or about 3.5 billion barrels; more than Britain’s total reserves. These are new reserves. Previously, the Board had not done a resource calculation for the area.

While the mineable sands did well, deeper sands did not. As part of its report, the Board reduced established in situ reserves in the Peace River area on the principle that some previously booked reserves in the Bluesky-Gething deposit were too thin to be economic. As a result, the ERCB reduced the in situ component of established oilsands reserves by about 5.5 billion barrels. The net outcome was that Alberta’s established reserves of bitumen totalled about 170 billion barrels. About 20% of that resource is theoretically mineable. The balance will require in situ recovery procedures like SAGD.

Rick Marsh, a senior geologist with the Board, stresses that this report makes no differences for planning by individual companies, although he observes that landowners have posted this new assessment on their websites. “The purpose of this is to determine on a global or provincial basis what the bitumen reserves of the province of Alberta really are. There is no connection between the regulatory side and the (ERCB’s) resource assessment side. Whether regulatory approval to develop is given will determine whether our resource estimate is correct or not. If development doesn’t take place for environmental or economic reasons, or for any other reason, then we will have to de-book some of those reserves, adjust them downward.”

Marsh notes that there are spots within the boundary expansion that are not appropriate for mining (they would require in situ development) and stresses that, in any case, the new ERCB boundary has no regulatory effect. Leaseholders in the surface mineable expansion area include Shell, UTS Energy, Total S.A. and Synenco Energy; they can propose whatever approach to development they want, whether surface mining or in situ techniques. It’s up to regulators (primarily the provincial Department of Energy) to approve developments.

Economic and Environmental Implications
It isn’t difficult to figure out the energy implications of this analysis. From an economic and technical perspective, the ERCB report enlarges the technically more accessible sources of bitumen. The availability of more mineable reserves, if developed, would mean a lot more economic activity in Alberta, more royalties to the province and greater energy security to the world. Greater production would contribute greatly to Alberta’s status as an energy power. It would enable the industry to develop larger export markets – whether in the United States or, if a pipeline to the west coast is ultimately constructed, to East Asia. And, of course, the Canadian balance of trade would benefit. In a higher-oil-price world, the economics of oilsands development are terrific.

But what are the environmental costs? Especially in respect to air pollution, the balance of costs is well worth considering. According to an important 63-page Canadian Energy Research Institute (CERI) study, Green Bitumen, SAGD production generates 1.3 times the emissions of conventional oil. By contrast, integrated mining and upgrading projects produce 0.6 times the level of emissions. (Emissions from older plants are much higher than these averages.) As we shall see, this could dramatically change.

First, however, consider the notions of the Pembina Institute, which will always have an axe to grind in respect to bitumen production. “The technologies used to mine, extract and upgrade bitumen to synthetic crude make the product among the most environmentally costly sources of transport fuel in the world,” the organization proclaims.

In May, Pembina issued a report summing up its view of the relative environmental impacts of the two oilsands production systems as follows. In situ oil sands production generates more greenhouse gases and sulphur dioxide emissions per barrel. Oil sands mining affects habitat more from land clearing, generates more nitrogen oxides and uses more water during production.

This report follows Pembina’s release in March of a “report card” on nine non-mining plants in the oilsands. In that report Pembina observed that in situ plants are responsible for greater air pollution than mining plants. “When the land disturbance and fragmentation effects associated with natural gas production are considered,” the authors added, “the influence on wildlife habitat of in situ operations can reach (environmental impact) levels that are equal to and sometimes greater than mining.” According to Simon Dyer, the institute’s oilsands program director, “both mining and in situ oil sands development produce significant cumulative environmental impacts and those remain unaddressed.”

Plain Facts
It’s easy to find yourself flinching at the organization’s messianic sense of its own rightness. However, the Pembina Institute plays an important gadfly role within the oilsands industry. As an advocate for better environmental performance, it brings public and governmental pressure to bear on the industry.

Pembina does confirm its raw data with producers before conducting its analysis and releasing its publications, and that is to the ENGO’s credit. However, the organization then invariably puts its collective boots to the necks of lesser environmental performers – or, when justified, damns exceptional performers with faint praise. In one presentation on its website, Pembina labels statements from the Alberta government and the industry as “Spin” but describes its own biases as “Plain Facts.” Perhaps a reality check is in order. To use just one example from the table above, in situ projects mostly use non-potable groundwater, 90% of which they recycle, and then re-inject that water into underground formations. In the interest of spin, Pembina forgets to mention this plain fact.

The good news about the ERCB’s expansion of the surface mineable area in the Athabasca sands is that it describes a huge volume of petroleum that can be developed safely and, as technology and production practices improve, in more environmentally sustainable ways. Especially if your biggest concern is air pollution, oilsands mines are the way to go. Where to go is a plain fact of the ERCB report.

According to the highly-respected Canadian Energy Research Institute, combining carbon capture and storage or using nuclear energy as a component of production could create oilsands plants producing fewer greenhouse gas emissions per barrel than conventional crude oil. In the study noted earlier, CERI describes an astonishing scenario. “The oil sands could pave the way as a bold new energy system,” CERI argues, “producing hydrocarbons to power our economy with almost zero GHG emissions being released into the atmosphere.” Looking forty years into the future, the institute suggests that “by 2050 the reduction from CCS coupled with nuclear energy would enable the oil sands to produce at 2030 rates with zero emissions being released, creating the cleanest sources of produced crude oil on the planet.”

The irony, of course, is that in this case the real visionary is a research institute with ties to the University of Calgary and funded by industry and government. Like the Pembina Institute, most ENGOs are just gadflies. They have a role in the ecosystem, but revolutionary change is taking place without them.

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Books on the Oilsands: A new cottage industry

Books about the oil sands were once few and far between; today they are part of a cottage industry, and often written by people with an axe to grind.

Such is the case with the latest installments, each of which boasts a green theme. However, it would be difficult to imagine three more diverse approaches to such a challenging topic.

• Alastair Sweeny, Black Bonanza: Canada’s Oil Sands and the Race to Secure North America’s Energy Future John Wiley & Sons Canada Ltd., 2010
• Satya Das, Green Oil: Clean Energy for the 21st Century? Sextant, 2009
• Gordon Kelly, The Oil Sands: Canada’s Path to Clean Energy? Kingsley Publishing, 2009

This article appears in the August issue of Oilsands Review

By Peter McKenzie-Brown

Black Bonanza
For a rollicking good read with a clearly defined message, Sweeny’s Black Bonanza really hits the mark. To get the flavour of his offering, consider two of many questions he raises in his preface. “Why are millions of people obsessing about carbon dioxide, a trace gas in the atmosphere, 3 percent of which is due to human emissions?... Why are government officials demanding that billions of dollars be spent to control this gas that is so essential to plant growth, while real pollution concerns cry out for solution and scores of our fellow citizens starve to death or die from preventable diseases?”

A historian by education and a writer by occupation, his chapters on the development of the oil sands are particularly worth reading. He captures people’s lives well, and has quite the instinct for the compelling quote.

Sweeny is on a mission, however. His message is that the oil sands present a tremendous strategic advantage to North American energy security, and they should be developed immediately. Canada would benefit enormously as it became an energy superpower, and North America would remain an ascendant geopolitical entity as it used a combination of crude oil security, economic strength and technical expertise to develop the inexhaustible energy of the sun. While the text is riveting, as the book winds up its message begins to fall apart. To make his case convincing, Sweeny must destroy the foundations of the climate change and peak oil debates.

He does pick holes in the conventions of climate change theory. Some of his arguments are historical: the Little Ice Age of around 1600, which followed the Medieval Warm Period of a millennium ago – and neither of which was connected to greenhouse gases. Others are statistical: carbon dioxide makes up 391 parts per million of atmospheric gases, of which 12 parts per million come from human activity. Other arguments use conspiracy theories to explain the sources of public concern: to a certain extent, he pooh-poohs climate change science as the work of people with vested interests in government grant machines. This is not exactly respectful of the scientific method and scientists, who together have contributed so much to contemporary civilization.

Sweeny’s efforts to dismiss peak oil are equally dicey. The gist is that there is plenty of oil in the world’s unconventional oil deposits, which of course is true. The point at issue is whether those deposits can be developed in time to replace depleting supplies of conventional production. On that question, the jury is still out.

The author successfully argues that Alberta’s oilsands have been demonized because environmental NGOs need easy, controversial targets to use in their annual fund-raising campaigns. Similarly, celebrities and politicians know they can get press by visiting Fort McMurray and proclaiming that the mines and plants look like something out of J.R.R Tolkien’s fictional Mordor, so they do.

The statistics Sweeny uses to defend the oil sands from the critics are compelling. He claims that each year America’s single-biggest coal-fired electrical generating plant spews forth 25.3 million tons of carbon dioxide contaminated with sulphur dioxide. That compares to about 40 million annual tons of relatively clean CO2 emissions from the Athabasca oil sands. Furthermore, Canada – the world’s poster child for dirty oil and GHG emissions – is responsible for 1.9% of global greenhouse gases. By comparison, green Europe emits 13.8%, the US 20.2% and China 21.5%. And so the argument goes.

Sweeny’s book is worth the read. As a gadfly, he counterbalances much of today’s conventional wisdom. Of equal interest for the bookworm, it’s an entertaining read from start to finish. The same cannot be said of the effort by Satya Das.

Green Oil
“Beyond a few purblind ravers,” says Das, “no rational person denies the reality of climate change.” Given the author’s background in journalism (notably with the Edmonton Journal), this mess of a book is particularly surprising.

He does not have a coherent message. In the absence of such a message, he parrots endless buzz-word laden passages from provincial government and ENGO reports – mostly on the importance of provincial stewardship of its resources, and strategies for governmental success. Painful to read, this book offers little except a sense of what higher-echelon bureaucrats conclude in their strategic planning meetings.

Self-published by the consultancy Das helped to found, this book’s main purpose is probably to drum up business. In fact, it is only in the context of his understanding of the roles of the public and private sectors that this publication makes much sense. “The principal role of government is to set a strong and effective policy framework,” he proclaims. However, “in every instance, the private sector role is to proceed robustly and vigorously to create wealth and value within the direction set by government.” As a private-sector entity advising government on policy issues, it’s safe to assume his firm is proceeding robustly and vigorously in the aforementioned direction.

This book is a stinker. Buyer, beware.

The Oil Sands

Gordon Kelly’s book is long, sometimes dry and technical, occasionally rambling. However, it’s also the most comprehensive and current study of the oilsands available. For anyone wanting a crash course in the oilsands, it’s a godsend. For anyone wanting a complete and current reference, it’s the only game in town.Kelly draws deeply from technical reports without taking shrill or ideological positions. For the most part he reflects the industry’s collective wisdom about the state of the oil sands. Fortunately, he also offers innovative ideas worth serious consideration.

Well into his 70s, Gordon Kelly had a long and diverse career in the petroleum industry – much of it as an ex-pat – and still works as a consultant. An engineer with an MBA by training, his understanding of the petroleum sector runs deep. It is therefore worth noting that his review of peak oil is comprehensive, and that he takes the issue quite seriously.

“A major theme of this book,” he says, “is that the world could run short of oil before new sources of mobile power are available. That is why the oil sands are needed and why it is important that Canada start the search for new alternative power sources now.”

Unlike most peak oil advocates, Kelly doesn’t see a probable decline in oil production as a function of scarcity. Rather, he sees it as a social problem. “Environmentalists are becoming more aggressive against oil and nuclear power because they really believe biofuels, windmills and solar panels can save the planet from GHG climate change. Politicians demand GHG curtailment because it makes them look ‘green’” he writes, “but it adds to the cost and time to build projects. Adding ‘Cap and Trade’ penalties to curb GHG emissions has reduced the money available for adding more capacity in Europe and may be expanded to North America. Project approval hearings drag on for months or years. Court challenges add to the delay....The world has lots of oil, but politics (will) block the (industry’s) ability to develop it fast enough.”

When we pass the peak in oil production (Kelly guesses the year will be 2015), “the shortages will be only a small percentage of demand, but for those who do not get the oil, it will be a crisis. History suggests it will be the poorest countries.”

Besides acknowledging peak oil as a reality, Kelly sees climate change from greenhouse gases as a threat. In that context, he puts forward some refreshing proposals on making Canada a leader in alternative energy.

In effect, he argues in his concluding chapter that Alberta should diversify from an energy-based economy into an energy-based economy. The oilsands and Alberta’s existing energy infrastructure provide a formidable base from which province and country can constitute a global clean energy superpower.

Concerned about the need to develop new sources of energy, Kelly conjures up the ghost of a creation of Alberta’s Lougheed years. Introduced in 1975, the Alberta Oil Sands Technology Research Authority invested $670 million over a 15-year period – all of those funds matched by private dollars. “AOSTRA was not government research but private research supported by the Alberta government,” says Kelly. “There is a big difference between the two. The private sector (had) to be willing to invest 50% of the cost in a project before Alberta (would commit) to the investment.”

According to Kelly, the program was so successful that it led to the construction of more than $100 billion in oilsands plants, so far. That is a stretch, perhaps. However, even if he is off by 75% (with rising commodity prices and associated inflation being mostly responsible for Alberta’s recent oilsands investment), the province’s AOSTRA investments generated highly leveraged results.

Today, he says, the province should introduce an AOSTRA-style program (Kelly calls it the Alberta Energy Research Project, or EARP) to encourage investment in alternative energy, arguing that research incentives could take advantage of the province’s existing expertise to create next-generation technologies. This is not far-fetched, he argues. BP is already “a large supplier of solar energy, while Chevron is the largest supplier of geothermal energy. Shell has a hydrogen division. Suncor has windmills and a biofuel operation.”

If you are interested in Alberta’s and Canada’s energy future, this is a fine tome. It’s too long, perhaps, and in some places could use a bit of cosmetic surgery. Even so, it is worth the time you invest in reading it.

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