Language Matters

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.

Keeping Electricity Competitive

2008-09-12T11:00:00.007-06:00

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

This article was carried in The Calgary Herald September 12, 2008.

By Martin Merritt

A few weeks ago, The Calgary Herald carried an item reporting that Alberta had just set a new summer record for power consumption, eclipsing last summer’s record by 2.3 per cent. The good news is that we had plenty of supply to meet this record. The concern is that as we continue to post records we may not have the transmission to ensure that the lowest cost supplies reach us as consumers.

As a consumer, I get the best deal for myself if I can buy things – cars, groceries, gasoline and other forms of energy – freely on the open market. In a market economy, our choices as consumers give a great incentive for sellers to keep their costs low. If we were constrained to buy from only a few sellers, we would have less choice and prices would likely be higher.

I also wear another hat. As Alberta’s Market Surveillance Administrator – the guy responsible for making sure our electricity market functions competitively – I understand that constrained markets can prevent low-cost sellers from prevailing in the marketplace. In the case of electrical power, we need more than the supply necessary to meet Alberta’s needs. We need a system that allows electricity to flow freely around the province. That requires adequate transmission capacity.

Alberta’s electricity market provides consumers with secure supplies and competitive pricing, but the transmission system is becoming undersized for the job in some places. Whether for home appliances or running business operations, consumers will only get the best deal on power when the transmission system can transport electricity from (almost) any generator in Alberta to (almost) any consumer in Alberta. This is why I am concerned about the tremendous hurdles facing new transmission projects these days.

Electricity generators are like stores, and the transmission system is like the network of roads that enables us to get to and from the supermarket. If major roadways became so congested that we had to buy all of our groceries from the local convenience store we all know what would happen to our family’s food bill.

This isn’t just theory. It’s already affecting us. Today we are moving a lot more electricity through the transmission system than we did when it went through its last major upgrade over 20 years ago. In constrained areas of our grid, this has dramatically pushed up the energy losses from transportation. For example, between the Lake Wabamun area where about 40% of Alberta’s generation is located and the Calgary area, losses average over 10%. According to the Alberta Electric System Operator, additional transmission capacity would save enough energy to power half the City of Red Deer. Losses on that scale are pure economic and environmental waste.

More recently, in the five years from 2002-2007, Albertans paid almost $300 million in subsidies to electricity generators for helping us get around our transmission bottlenecks. The subsidization rate is presently $40-$50 million annually. Some advocate expanding this practice – paying generators to locate in sub-optimal places in order to avoid investing in transmission infrastructure that the province badly needs. This amounts to renting band-aids rather than fixing the root problem. This band-aid approach might work well for the band-aid vendors but it’s certainly not in the best interest of Albertans if we expect to continue to realize the larger benefits of a broadly competitive electricity market.

In Alberta today, the wholesale electricity market is worth about $5 billion a year, less than 10% of this represents the cost of transmission. The economic challenge of trying to avoid or defer transmission investment beyond what we have already realized is that you put the competitive efficiency of a $5 billion market at risk, in order to chase questionable savings in the 10% piece – penny-wise, but pound-foolish.

Allowing growth in demand to outstrip the capacity of our existing transmission system puts the benefits and perhaps even the reality of a competitive electricity market at risk. Experience in other electricity markets has shown that the practice of subsidizing generators to locate in particular places can have expensive and unintended consequences. Once generation economics start to hinge on capturing subsidies rather than on efficiency and low-cost, the broader benefits of the competitive market become compromised. Consumers expect and need generators to compete with each other on the basis of efficiency and generation cost. Transmission enables this competition to occur. Subsidized generation distorts it.

Unless we invest in transmission, Albertans’ bills will continue to reflect the growing cost of rented band-aids, high losses and diminished competition. The longer we take to build the transmission we need, the more rent cheques go down the drain.

In southern Alberta, we have great sites for generating electricity from the wind. Investors are willing to build there, but we have a shortage of transmission. Similarly, northern Alberta is the logical place to locate fossil fuel generators. They are most efficient (both economically and thermodynamically) when they can be located at low altitude, in cooler temperatures and near a substantial supply of water. There too, we have a shortage of transmission. By bringing all electricity supply sources to all consumers across the province, transmission provides us with choice and forces suppliers to compete with each other. Subsidizing higher cost, less efficient generators to locate in the middle does neither.

These are powerful realities. Some advocates of gas-fired generation in southern Alberta will soon enough be asking for subsidies – for without them their projects are unlikely to be able to compete. About half of Alberta’s residential consumers live in the transmission-constrained southern part of the province, but the case for reinforcing our transmission grid is not an argument for southern consumers alone. All Albertans benefit the most from the most competitive market possible.

We must find ways to enable the fair and timely development of critical transmission infrastructure. We need more transmission capacity because that – not subsidized generators – is the best way to assure the competitive market that Albertans have come to expect.

Reaching the Peak

2008-09-02T12:27:00.011-06:00

As EnCana prepares to hive off its oilsands business, Brian Ferguson prepares for life atop Canada's newest bitumen mountain.

This article appears in the September 2008 issue of Oilweek; photo from here.

By Peter McKenzie-Brown

Brian Ferguson is almost perfectly decked out to play the part of the Stampede cowboy. Balding slightly but rugged looking, he’s wearing Wranglers and a yellow-and-blue checked shirt. Something’s missing, though: the big-buckled belt. With an easy charm he chuckles: “I’m travelling today, so my wife Cindy made me leave it at home.”

I am interviewing him at the Calgary International Airport. As I prepare for the interview, I recall the excitement at the beginning of 2002, when two of Canada’s most successful independent producers, PanCanadian Energy and Alberta Energy, pull off the largest merger in Canadian oilpatch history – a $27-billion deal. Overnight, EnCana becomes the world's largest independent petroleum company, the largest driller and explorer, the largest gas producer on the continent, and the third-largest industrial conglomerate in Canada. The merged entity is an energy powerhouse.

Beginning in 2006 and under the leadership of a new CEO, Randy Eresman (who promotes Ferguson to executive VP and CFO), EnCana goes through a series of equally dramatic changes. The company sells off the last of its properties in 22 countries overseas (including excellent assets in the North Sea). Then, taking the industry by surprise, the company announces an asset exchange with ConocoPhillips, through which the two companies form a 50/50 bitumen production and refining partnership. Now exclusively North American, EnCana announces that it will split into two companies, with the formal creation of the new entities taking place on New Year’s Day, 2009.

Plus ça change, plus c’est la même chose? Or, in English, is this another case of the cynical French epigram – “The more it changes, the more it is the same” – in action? Anything but, according to Brian Ferguson. He will serve as president of the provisionally named IntegratedOilCo (IOCo), which will have market capitalization of about $29 billion. Randy Eresman will serve as CEO of the other new company – twice as big, and provisionally called GasCo.

Although he is still EnCana’s executive VP and CFO, in practice Ferguson has already taken on his new job. I ask why EnCana is breaking up. “This is about focus,” he says. “This is the next natural step in EnCana’s evolution of continuing to increase our focus. The business drivers that are going to be necessary to be very successful for the exploitation of tight gas and shale gas are different drivers from those that are going to be required for exploitation of the oil sands.” For that reason, Eresman’s new company will focus exclusively on natural gas production, which will include liquids extraction. IOCO will be an integrated oil company with enough gas assets to make it a substantial producer – about 860 million cubic feet per day – in its own right.

“In 2003 we started focusing the company on what we did best, where we had competitive advantage and especially where we were generating really strong rates of return,” Ferguson continues. “At the time of the merger we were active in 22 countries around the world. When we looked at our portfolio we found that we were doing really well in the development of in situ oil sands and in the development of natural gas resource plays right here in our own back yard – in North America. We sold $13 billion dollars worth of assets, so that our reserves were focused in tight gas and shale gas and in situ oil sands” on this continent.

He adds, “Over the last few years the world has become a more difficult place. It’s become harder and harder to do business outside North America, which anyhow is the world’s largest energy market.” Before the split, EnCana’s competitive advantages include the largest land base in North America. Focusing on this continent gives the company lower political risk and greater predictability.

A chartered accountant by background, Ferguson is quick with numbers and financial concepts. “There is a preference for focused pure-play companies in the financial marketplace,” he says. “The split will allow for greater transparency and disclosure (in terms of) operating and financial performance and the value that is being created for these two businesses.”

The problem with EnCana as it is structured today, it appears, is that “the gas company has tremendous growth in it. It’s about 80% of our business today. It has tended to dwarf the success and growth of our integrated oil business, which we expect to grow at a compound rate of 20% over the next decade.” Under the new arrangement, “the market will focus on choosing the best companies in both groups – oil and gas.”

Integration: I ask him about the unusual decision – for a Calgary-based petroleum producer, at least – to become an integrated company. “We wanted to remove risk and get more predictability in the cash flow stream,” he says. Again, you can hear the accountant speaking. “We have a tremendous resource base – more than 40 billion barrels of oil in place on existing EnCana land. We wanted to reduce the risk associated with investing billions of dollars in the upstream and being just a pure bitumen producer. How do we manage that risk in terms of the volatility of the heavy oil differential to give us the confidence that we can go to full development of our resources? We decided that our best bet was to find a dedicated home and a very experienced partner in the downstream.”

The partnership’s refining assets are at Wood River, Illinois (153,000 barrels per day net to EnCana) and Borger, Texas (73,000). How will the decision to develop this partnership affect the company’s bottom line? “Each year, profitability will be different. Last year our 50% interest (in these downstream assets) generated more than $1 billion in operating cash flow, which was substantially higher than the upstream cash flow. That changed this year because crack spreads” – the margins that a refinery can earn by “cracking” (refining) a barrel of oil into such marketable products as gasoline, jet fuel and heating oil – “are narrower in 2008 and oil prices are higher. So we will probably generate a disproportionate amount of cash flow out of the upstream. However, this has removed risk from the upstream business.”

Ferguson is warming up to the topic of integration. “It gives us a lot of strength,” he says.”We are not only integrated in the sense of producing bitumen and taking that from the wellhead through the pipeline to the production of transportation fuels. Also in our oilsands operations we consume a lot of natural gas and our refinery consumes a lot too, so we are economically integrated in the sense that we produce a lot of natural gas as well. And if you take it one step further in terms of that integration we also have the sequestration project, so we are integrated in terms of carbon, too.”

The sequestration project he is referring to is the one at Weyburn, Saskatchewan – an EnCana asset. The 50-year-old Weyburn oilfield uses a 330-kilometre pipeline to transport carbon dioxide captured at the Great Plains Coal Gasification plant, which manufactures methane from coal near Beulah, North Dakota. The world’s largest carbon capture and storage (CCS) project, the Weyburn project disposes of about 1.5 million tonnes of carbon dioxide each year and keeps oil flowing from the field. North American policy-makers are increasingly asking energy companies to show their environmental commitment through such projects – whether they make economic sense (as this one does) or not.

I ask Ferguson about environmental issues. “There is no question that environmental concerns will continue to heighten, continue to grow,” he tells me. “There is no question that the environmental and reputational matters for the oil business and the oilsands in particular are going to be different from those in the gas business.” Now he gets back on message. The new business arrangement “enables us to focus on the business drivers, and one of those business drivers is environmental stewardship and environmental performance. I think it’s an area where we will be able to distinguish ourselves from virtually all of our competitors. All of EnCana’s oil sands operations are SAGD (steam assisted gravity drainage), and they are characterized by a smaller environmental footprint in terms of water consumption and land use. We also have our Weyburn oil sands project, which is the world’s largest carbon sequestration project.”

EnCana’s oilsands production has grown from virtually nothing to 30,000 barrels per day (net to EnCana, reflecting the arrangement with ConocoPhillips) in the last 13 years. I ask whether this is primarily because of technology or geology. In effect, he says, both. “Our projects at Christina Lake and Foster Creek both have two extremely high-quality reservoirs. Foster Lake has no top gas and no bottom water and it’s a very thick formation – 30 or more metres thick. Christina Lake approaches 40 metres in thickness. We acquired these assets many years ago.” On the technology front, “we have the longest history of commercial SAGD production, about 12 or 13 years. We’ve had a lot of time to understand and pilot and perfect the techniques we need to develop the reservoirs.”

Since Foster Creek began commercial operations in 2001, its production has grown to about 60,000 barrels per day. It should reach 65,000 barrels by the end of this year and 100,000 barrels next. Christina Lake is expected to climb from about 7,500 barrels per day now to about 18,000 by year-end. Foster Creek and Christina Lake are owned 50-50 by EnCana and ConocoPhillips. Ferguson expects the partnership’s total production from these two assets to approach 400,000 barrels per day by 2015.

The Price of Planning: There has been a lot of speculation in the business press that, by splitting the companies, IOCO will quickly become a takeover target. What does Ferguson think about this? “There is a very low probability that either of the entities would be taken over. The smaller company is going to be a larger company in terms of market capitalization than EnCana was when it was first formed in 2002. It’s not something I spend a lot of time worrying about. One of the reasons we are doing this now is that we want to do it from a position of strength, both operational and financial.”

What does Ferguson think about today’s high commodity prices? He’s clearly given a lot of thought to why they stand at such lofty levels. “The key thing is that reserves that were relatively easy to produce have been found and developed. The big thing as we go forward will be continuing advances in technology. This applies to both the demand side and the supply side: anything that makes things more efficient will reduce demand and anything that helps us commercially develop reserves will help supply. What you are seeing today is a demand-driven expansion of commodity prices in an environment where there is relatively little ability to expand supply to meet the demand growth. It’s just about supply and demand. Asian countries like China and India are becoming very energy thirsty. The new demand coming out of Asia is something virtually everyone in the oil industry had underestimated.”

Will these prices last? “We think for planning purposes $8.50 gas prices and $85 WTI for longer-term planning purposes is reasonable.”

We have completed the formal interview, so we spend a few minutes shooting the bull. Brian Ferguson is a pleasant and friendly sort, but I am curious about his personal life. “What’s the last book you read?” The answer surprises me: Angels and Demons – Dan Brown’s prequel to The Da Vinci Code. It turns out that Ferguson is a science fiction fan; his favourite author is Stephen King.

He’s also fit. He does snowboarding and downhill skiing in the winter; cycling, jogging, hiking and waterskiing in the summer. Any exciting plans for the summer? “My wife Cindy and I are hiking the skyline trail near (Banff Park’s) Maligne Lake this weekend, with some friends.” And another thing: The family, which includes daughter Lindsay and son Brett, are going to Tanzania to climb Kilimanjaro. Just another peak for Ferguson to conquer.

A New World Order?

2008-08-23T10:02:00.012-06:00

Hugo Chavez says Venezuela's way of doing things is the wave of the future. But is there a place for large international oil companies that are NOT government-controlled?

This article appears in the September 2008 issue of Oilweek magazine.

By Peter McKenzie-Brown

“Alberta became the Bolivarian province of Alberta when you decided to take more royalties from the oil companies,” Luis Vierma told a scowling crowd from Calgary’s petroleum community last June. “This made Venezuelans very happy.” The reference, of course, was to Simon Bolivar – the 19th century revolutionary whose leadership helped to liberate much of South America from the Spanish monarchy. The speaker was the E&P vice president of a national oil company – specifically, that of the Bolivarian Republic of Venezuela.

Vierma’s cheeky comment garnered a few chuckles from his audience, but not many. This articulate man – he was educated and for some years worked in the United States – described a world order which at first blush doesn’t seem to suggest a happy future for western-style international oil companies. However, this commentary suggests that it may not be all that bad for private-sector oil companies, and that the changing world has huge implications for the oilsands.

The United States is clearly worried about Venezuela. The CIA’s 2008 World Factbook, for example, offers a litany of indignant complaints about the South American nation. “Hugo Chavez, president since 1999, seeks to implement his ‘21st Century Socialism,’ which purports to alleviate social ills while at the same time attacking globalization and undermining regional stability. Current concerns include: a weakening of democratic institutions, political polarization, a politicized military, drug-related violence along the Colombian border, increasing internal drug consumption, overdependence on the petroleum industry with its price fluctuations, and irresponsible mining operations that are endangering the rain forest and indigenous peoples.”

Vierma’s audience was also concerned, but their concerns were much narrower. They were well aware that Petróleos de Venezuela S.A. (PdVSA) was the beneficiary of Chavez’s large-scale nationalization of assets held by international oil companies. They were also aware that the company holds the keys to Venezuela’s Orinoco heavy oil belt. Named after the nearby Orinoco River, these deposits are roughly comparable in terms of in situ volumes to those in Alberta’s oilsands. On the global stage, they are the province’s only serious competitor.

New World Order: This commentary explores Vierma’s suggestion that recent decades have seen the creation of a new world order that is now entrenched and becoming more pronounced. It is an idea that is getting ever-wider acceptance. “In the new international energy order, countries can be divided into energy surplus and energy-deficit nations,” writes Michael Klare, an American academic who specializes in the geopolitics of energy. “Deficit states like China, Japan and the United States are compelled to pay ever higher prices for imported fuels as they compete with one another for those materials the surplus states are prepared to supply. The surplus states, on the other hand, are sure to become richer as they parcel out their increasingly valuable commodities at whatever prices the markets will bear.”

As Klare observes, national oil companies (NOCs) are increasingly dominating global oil supply. Of the 15 oil producers with the greatest reserves, only two are privately owned – Russia’s Lukoil (#9) and Chevron (#15.) Between them, they control 2% of the world’s proved conventional reserves – compared to 77% for the other 13 companies, combined.

PdVSA’s Vierma – his company is the beneficiary of a highly contentious nationalization of the petroleum industry by the Venezuelan government – is a strong believer in the new world order. “The whole industry of the last century is completely different from the industry of today. In the 1970s, 85% of the (world’s) oil reserves were managed by international oil companies, the Seven Sisters. Today the situation is completely different. Most reserves are now managed by national oil companies, and everything now gravitates around (them). At the beginning of the 21st century, national oil companies turned into the principal actors in the petroleum sector.”

Petroleum “is the backbone of the economy in Venezuela,” he added. And according to the vision of Venezuela’s socialist government, the country’s NOC has a responsibility “to ensure our shareholders get enough of our revenue, and we have 27 million shareholders, the Venezuelan people. We have a responsibility to develop our reserves to allow them to have a better life. This is the main difference between how the industry was managed in the past and how it will be managed in the future.”

Being a national oil company brings a lot of responsibilities. Perhaps the most important of these are social responsibility and how we take care of the environment. Last year PdVSA invested $14 billion in social programs, and after paying taxes and royalties still made US$6.27 billion in profit. “This proves that we can be a profitable oil company with a lot of social responsibility.” This is the vision of the future, he said: “Oil companies around the world will do the same.”

Competition and Cooperation: “We believe the work here will involve cooperation instead of competition,” he said. “Even though some competition will be there, but cooperation is an important issue to be considered.” By his analysis, national oil companies fall into three groupings. The first are those that can meet their own needs plus export – for example, Saudi Aramco, PdVSA and the National Iranian Oil Company. Another category includes national oil companies in consuming countries, like China’s CNPC and India’s ONGC. These companies can’t meet internal demand, and are looking for opportunities overseas. Finally, there are NOCs in countries that can satisfy internal demand and could, with development, become important exporters; these include Mexico’s Pemex and Brazil’s Petrobras. This latter group of countries, Vierma suggested, “are going to become important sources of primary energy” to the rest of the world.

PdVSA has formed alliances with NOCs throughout the world, and owns a substantial American subsidiary – CITGO, an integrated oil company in its own right, and the vehicle through which PdVSA exports oil to the US. “All these companies are participating in projects with us either upstream or downstream,” said Vierma. “The magic word is how we can establish cooperation with their regimes so these companies can be successful and sustainable over time. We believe cooperation (not competition) is the key word to establish business relationships with these companies.”

Oh, Canada: According to academic Michael Klare, PdVSA is number six among national oil companies, with control of 6.6% of the world’s proved reserves. However, that number does not take into account the vast potential of the Orinoco oil sands.

When you factor in the oilsands, the numbers become staggering. Start adding the resource potential of bitumen and heavy oil from Canada and extra-heavy and heavy crudes from Venezuela and, Vierma said, “(between us,) Canada and Venezuela will have more than half of the oil reserves around the world.”

How can Canada benefit by working in Venezuela? The country is looking for foreign partners to develop offshore properties that are prospective in terms of both oil and natural gas. In the oilsands, the two countries need to share oilsands technology. According to Vierma, “Venezuela now has 1.3 trillion barrels in situ. With 20% recovery we believe 235 billion barrels of heavy and extra-heavy crudes are now (technically) producible from (our oilsands area), and 17 NOCs are working with PdVSA in that area. By October 2009 we plan to certify those 235 billion barrels that are going to be recovered.”

In a proposal that is unlikely to draw much interest from Canadian firms, PdVSA suggests using cooperation rather than competition to create global market efficiency. “In terms of heavy oil production and heavy oil markets we need to share our learning lessons, experiences and challenges with Canadian companies. Canada and Venezuela will share the same markets as well as the same challenges. Why not cooperate to make the markets more efficient?” He suggested, for example, that Canadians focus on developing markets in Asia, while Venezuela develops markets in the Atlantic basin.

How else could Canada and Venezuela cooperate to develop those resources? PdVSA obviously wants access to Canada’s oilsands technologies. But the country’s conventional resources are also considerable – don’t forget that PdVSA controls 6.6% of the world’s oil reserves – and these resources also need to be developed in a hot global economy – hot, at least, in terms of petroleum exploration and development. Like other producers around the world, Venezuela needs infrastructure, including rigs for conventional oil and gas drilling, and that “provides tremendous business opportunities for Canadian companies.”

The Human Factor: As he closed his presentation, Vierma made a plea for help in education and training. “We need human resources, skilled people, and we are here to tell you this is another area where there are opportunities for the people of Alberta,” he said. “We are aware that the level of education in this province is very good, and we want to retake the bridges that we have burned in the past.”

The irony of this comment, of course, is that Venezuela’s 21st century socialism has helped reduce the talent available to Venezuela while increasing that in Canada. Last year both Exxon Mobil (the parent of Imperial Oil) and Petro-Canada fled Venezuela because of the shenanigans of Hugo Chavez. Both companies were investigating extra-heavy projects in Venezuela, and both transferred technical expertise and field workers to Alberta as a result.

According to CEO Ron Brenneman of Petro-Canada, “We are finding that some pretty good technical people are coming available (directly) out of PDVSA as a consequence of what’s going on down there.” He adds, though, that “I don’t think this will affect (Alberta’s) labour pool to a large extent.”

But what about the new world order? The argument that the world has fundamentally changed is very strong. NOCs are unquestionably dominant in the politically risky parts of the world, and that trend is unlikely to change. In addition, geopolitical considerations (including human rights issues, corruption and worries about Venezuelan-style nationalization of assets) are keeping international oil companies away from many of the regions that are left.

Does this mean the future belongs to PdVSA and other NOCs, as Hugo Chavez and others have suggested? The answer is almost certainly no. Rather, international companies will increasingly focus on development in areas where risk is minimal and potential is large. Clearly, much of that activity will take place in Alberta’s oilsands.

To use Shell as an example, its Canadian oilsands potential is in the 40-billion-barrel range – volumes that dwarf the rest of its oil assets world-wide. Remember that list of oil reserves of the world’s top 15 companies? Such a resource would place Shell in seventh place – ahead of the National Oil Company of Libya, behind PdVSA.

This reality suggests another vision of the new world order. Increasingly, perhaps, international oil companies will need to retreat to low-risk, high-potential areas like Alberta in North America, Europe, Australia, India, parts of Southeast Asia and South America and other “safe” parts of the globe. In a future of declining conventional production, they will prosper by applying their considerable intellectual, technical and capital resources to oil sands and shale oil development, and to the production of gas from tight sands, shale and hydrates.

The service sector could also do well in such a world order. Unconventional development requires a lot of support from service providers. Supplying expertise to inefficient national oil companies could offer (just as Vierma suggested) “tremendous business opportunities.” Indeed.

China: Panda or Dragon?

2008-07-25T09:12:00.024-06:00

This article appears in the August 2008 issue of Oilweek.

By Peter McKenzie-Brown

A symbol of unrivalled wisdom and power, China’s dragon is a long, scaly, snake-like creature with the paws of a tiger and the claws of an eagle. This chimera is an emblem of ancient imperial power. Indeed, the dynastic emperors were known as dragons.

The revolutions of the twentieth century made a break with the past, and the present regime does not think the dragon is a proper symbol of China. Instead, the country’s rulers prefer to use the giant panda – that loveable, bamboo-eating member of the bear family – as the national emblem. By tradition a rare and noble creature, the panda has been part of diplomacy since 685 CE, when an emperor of the Tang dynasty sent a pair to his counterpart in Japan.

As the world sets its eyes on Beijing, where the Olympics will showcase progress since the death of Mao Zedong two decades ago, this commentary asks a simple question. Is the panda in charge of Chinese energy strategy, or is it the dragon? From the security of its bamboo forest, the gentle panda would stress comparative advantage. The dragon would rely on cunning, speed and power.

The charts below show growth in China’s oil consumption (top) and the country's oil production - both since the death of Chairman Mao

Until 15 years ago, China exported oil to neighbouring countries. Today, it has an almost insatiable appetite for the stuff. Since the Great Helmsman’s death in 1976, the People’s Republic has become the world’s second largest oil consumer (behind the U.S.) During those years Chinese consumption has quadrupled to about 7.7 million barrels per day while production – about 3.7 million barrels per day – has barely doubled.

The International Energy Agency thinks China will burn 16.5 million barrels per day by 2030, after buying 13.1million barrels abroad. Think about it: Saudi Arabia’s total output is now less than 11 million barrels per day.

Thrift: This article suggests that such parabolic growth requires the skills of the dragon to survive. In that spirit, China is now applying its extraordinary energy in four ways to meet its petroleum and other resource needs. The first is domestic resource development. Diplomatic manoeuvres on behalf of its petroleum industry are the second. The third involves partnerships with Western companies. Last is what the mandarins call “thrift.”

Based on efficiency, conservation and innovation, thrift is sometimes called the fifth form of energy.

China’s rise is making the world a more energy-efficient place. The country’s energy intensity – the amount of energy it uses per unit of GDP – has dropped by about 75% in the last 20 years, largely because of more efficient industry. Its energy intensity higher than America’s but lower than Canada’s, in 2006 China adopted the slogan “Save energy, cut emissions” as part of a drive to cut energy intensity even further. The country is thus improving its energy efficiency while increasing its energy-intensive role as workshop of the world. So don’t blame the Chinese for the world’s energy woes. They are doing an effective job of managing energy.

A latecomer to the world’s petroleum stage, China is now simultaneously the world’s second-largest oil consumer, the third-largest net importer, and the fifth-largest producer. In the last 15 years the dragon has been sending its agents into the world to secure the new energy supplies it desperately needs. Compared to the West’s international producers, China’s national oil companies arrived late to the petroleum Olympics, and they are not large contenders. The prizes left in play are expensive, and often in countries where Western companies refuse to operate because of human rights issues and geopolitical risk.

Through petroleum-related state-owned enterprises (SOEs) – China National Petroleum Corporation (CNPC), China National Offshore Oil Corporation (CNOOC) and China Petroleum and Chemical Corporation (Sinopec) – China started investing outside the country in 1993, just as the country became a net oil importer. China’s first petroleum acquisition was in Thailand, but CNPC acquired exploration acreage in Canada and Peru the same year. The amount of equity oil generated by those projects was relatively insignificant, and this remained the case for several years.

In terms of Canada’s ties with China, 1997 was an important year. As the British were preparing to return Hong Kong to China, Sir Li Ka-shing, the colony’s richest man and chairman of the Hutchison Whampoa conglomerate, became the owner of Husky Energy. Husky’s headquarters continued to be in Calgary, and the acquisition did not affect the company in the short term. However, Husky has since expanded its assets offshore China, and is now the largest foreign owner of exploration blocks there. All its holdings there are in the South China Sea.

Since 2001 Husky has signed eleven production sharing contracts in collaboration with the China National Offshore Oil Company (CNOOC) – now publically listed, but 70% owned by the government of China. Husky can participate in these projects up to 51%, and the company describes its entry into China as part of a strategy to develop conventional oil and gas outside North America. Certainly the company is also part of Chinese strategy, also. It is one source of capital for mandarins focused on securing energy supplies by developing the Middle Kingdom’s domestic resources.

The Venezuela Card: China cannot secure Canadian oil supplies as long as the only export pipelines from Alberta lead into the United States. Especially after the two countries announced in 2005 an agreement on energy cooperation, it was therefore astonishing when CNPC announced last year that it had pulled out of an agreement to take a 50% stake in the proposed Enbridge-operated Gateway Pipeline. When completed, the pipeline will transport 400,000 barrels of oil per day to Kitimat BC for overseas export. According to the terms of the original deal, CNPC would take 200,000 barrels per day of throughput, with the balance being exported to refiners in California. If the line had been expanded to 800,000 barrels per day capacity, CNPC could have acquired a larger stake.

For a country with rapidly rising oil demand, what’s not to like about this deal? When PetroChina vice president Song Yi-wu announced the dragon’s decision, he put it in the political context of a nation re-evaluating its commitment to Canada’s oilsands.

Projects take too long to get off the ground here, he said, and the political environment “frustrates” Chinese investors. Song said China would slow down its involvement in the Canadian oilsands business, give up its involvement in the Gateway pipeline project and wait for better investment policies and politically friendly opportunities in the future. Translation: Chinese policy-makers were frustrated over the unwillingness of Canadian producers to partner with CNPC in a production/refining venture that would see Canadian bitumen and heavy oil sent to Asia for processing.

Forecasting that CNPC couldn’t begin to produce bitumen from the oilsands for at least another decade, he made it clear that China’s near-term heavy oil strategies were pointed directly at Venezuela, where a “warm-hearted” President Hugo Chavez has taken steps to nationalize oil operations. Song said China is building energy security for its people in “politically friendly” countries, which include Venezuela, Saudi Arabia, Russia and a host of Asian and African nations – Burma, for example, and Sudan. Call it the Venezuela card.

The Venezuela card suggests a competitive advantage for China that Western countries often will not play. The dragon sees oil security as an urgent need, and is willing to exert whatever cunning, speed and power it must to meet its future needs. Not surprisingly, given its political structure and domestic situation, China will not let issues like liberal democracy and human rights stand in the way of its quest for energy.

Do Western oil companies let political and human rights niceties stand in the way of business? It’s a matter of degree, of course, but it is not difficult to find examples of North American and European companies pulling out because of political risk and public pressure based on human rights abuses. In Canada the most famous case is that of Talisman.

Ten years ago the company acquired a 25 percent interest in a developing oil project in Sudan. The production facilities, pipeline and offshore loading terminal were being built and the wells were being drilled. By the summer of 1999, oil was flowing and being exported. By 2002, the project was producing 240,000 barrels of oil a day, with the equity oil being distributed to the project’s participants, three of which were subsidiaries of state-owned oil companies from China, Malaysia, and Sudan. The only privately owned company in this consortium, Talisman bowed to public pressure based on Sudan’s human rights record and sold its 25% interest to an oil company owned by the government of India.

The pattern is clear. The Asian players were unconcerned about human rights. There is a subtext here about Asian strategies toward energy. Especially in the face of a high-profile divestment campaign like that launched against Talisman, Western companies will buckle in the face of pressure related to human rights, environmental integrity and so on. Chinese and other Asian companies will not. For example, all three of China’s oil and gas SOEs are active in Burma. Latecomers to the petroleum Olympics, they measure petroleum victory in terms of land, reserves and production.

Comparative Advantages: Chinese industry’s willingness to overlook “soft” issues like human rights gives it a distinct comparative advantage. China’s willingness to bring diplomacy to bear on behalf of its SOEs gives it another. These advantages are rebalancing the planet toward East Asia. The dragon is rising.

Chinese energy policy is directed by government, and some 70% of the world’s petroleum resources are now controlled by national oil companies like Saudi Aramco and Petróleos de Venezuela. State-to-state negotiations are especially important when one of the participants is an emerging superpower.

Much of China's efforts are directed to the energy-rich nations of Central Asia, which can deliver energy overland instead of by tanker. For example, a trans-Kazakhstan pipeline is already delivering oil from the Caspian Sea.

Two other factors in China’s favour deserve mention. One is that Southeast Asia is home to many in the Chinese Diaspora – the descendants of the many waves of migration from China over the last millennium. Particularly as colonialism collapsed after the Second World War, they came to control great assets and even some national economies. By some estimates the third largest economic entity in the world, the Overseas Chinese began repatriating capital to China in the 1990s, thereby igniting the Chinese miracle. Today they occupy key positions in Southeast Asian business and government, and strengthen local ties with China.

Another factor working for China began during Cultural Revolution – that decade of social, political, and economic madness from 1966 until the arrest of the Gang of Four. Despite mutual fascination and incomprehension, during those years black African governments and African revolutionary movements were the recipients of Chinese aid (both military and economic) and other diplomatic efforts. African governments – many of them successors to those revolutionary movements – remember China’s efforts during that time. That diplomacy is now paying off with preferential access to petroleum leases and production sharing contracts.

A classic example is Angola, in West Africa. Mainly because of the expansion of its oil industry that country has the fastest-growing economy in the world, and its growth is mainly driven by Chinese explorers and producers. China’s SOEs got access to Angola’s offshore as a ‘Thank you’ to the People’s Republic of China. Despite desperate poverty at home during the Cultural Revolution, the dragon still found the wherewithal to support Angola’s independence movements during those critical years.

China’s Peaceful Rise: A final point deserves comment. In the late 1990s, China’s central government developed what it called “the new security concept.” The idea is that the Cold War mentality of antagonistic blocks no longer makes sense. In a globalizing world, nations can increase their security through diplomatic and economic interaction. This notion has become part of a foreign policy doctrine known among diplomats as “China’s peaceful rise” – a policy that, for example, encourages Chinese businesses to form partnerships with Western firms. For Canada, which is one of the few countries likely to increase production in the coming decade, it has important implications.

Consider, for example, that Enbridge is undeterred by CNPC’s decision to pull out of the Gateway Pipeline. “The appeal (of this pipeline) to Canadian producers is that you would get another bid on the crude oil from somewhere other than the United States,” said Enbridge’s executive vice president, Steve Wuori. Also, of course, pipeline costs would be less.

“When (Enbridge) first started we were aiming (to complete the project in) 2011,” Wuori says. “But now we are targeting 2012-2014.” Will Canada be able to supply new markets with heavy? Wuori thinks so. “Production forecasts up to 2020 for the oil sands support that kind of growth potential, even if you risk it for economics and environmental concerns.”

Although China has placed less than 1% of the $50 billion investment in the oilsands since the early 1990s, it is still part of the equation. China’s most significant direct investment has been the SinoCanadian Petroleum joint venture, through which Sinopec owns a 40% stake in Synenco’s Northern Lights project. CNOOC made its presence known with the acquisition of a small interest in MEG Energy, which is focusing on a project at Christina Lake.

Obsessed with diversifying its oil sources and avoiding dependence on a single supplier, Beijing sees Canada as a country in the U.S. sphere of influence, a country where oil could be held hostage to political concerns. It has little enthusiasm for multibillion-dollar oil deals in a country whose relations with China have been soured by human-rights disputes. Think Tibet.

“China doesn’t want to make a multibillion-dollar commitment to a country where the political contacts are constrained,” says Jiang Wen-ran of the University of Alberta’s China Institute. Professor Jiang adds that the Middle Kingdom worries about Canada’s business practices. Canadians can’t explain how they will triple production from the oilsands given environmental constraints. The costs of environmental protection seem out of control. Labour costs are reaching the moon.

The Panda Speaks: This article has focused on the areas of Chinese petroleum development where Westerners are more likely to see a dragon than a panda. Of course, in modern China it is the giant panda that speaks for the neo-imperial court. To conclude, let’s listen to what this species has to say.

According to China’s State Council, a policy-making arm of the People’s Republic, “The basic themes of China’s energy strategy are giving priority to thrift, relying on domestic resources, encouraging diverse patterns of development, relying on science and technology, protecting the environments, and increasing international cooperation for mutual benefit.”

The panda adds that its energy development is based on “the principle of relying on domestic resources and the basic state policy of opening to the outside world.” In its efforts to ensure a stable supply of energy, the country wants “a steady increase in domestic energy production.” It also wants to “promote the common development of energy around the world.” China’s energy development “will bring more opportunities for other countries.” It will “expand the global market, and make positive contributions to the world’s energy security and stability.”

All this will help perfect the national system of “socialism with Chinese characteristics.”

Genesis of a Giant

2008-07-05T19:40:00.008-06:00

Thirty years ago this month, Syncrude produced its first barrel of oil. This article appears in the July 2008 issue of The Oilsands Review.

By Peter McKenzie-Brown

Syncrude triumphed over an era which was eerily similar to the one we’re in today.

Many commentators have remarked upon the likenesses between then, the 1970s, and now. A financial crisis in the United States led it in 1971 to end the link between the dollar and gold and to adopt a wave of protectionist policies. America and its allies were mired in interminable and expensive Asian wars. Because of high liquidity in capital markets, price inflation became endemic. Stock markets flattened and employment in non-resource sectors slumped. Rapidly rising food costs contributed to great suffering in the Third World, as it was then known, and to the poor in the richer countries.

After a 20-year decline, in 1973 real oil prices rose rapidly because of new demand, declining supply from key producers, and geopolitical events focused in the Middle East. The oil industry boomed; drilling, development and construction costs skyrocketed. As the decade wore on, the belief that oil was about to “run out” became widespread. So did the view that humanity would soon choke on its own pollution. By the end of that spooky period, forecasts of oil prices tripling from their already high base were common.

Given the similarities between that era and this, it is ironic that the early 1970s were a threat to Syncrude’s existence. The giant seemed doomed until three governments agreed to serve as midwives. This largely forgotten tale is an important part of the plant’s heritage. Few people remember that today’s world beater was nearly the victim of a breached birth.

Origins: For oilsands development to make any sense at all, Alberta needed appropriate policy. This is not a new idea. A hundred years ago Canada’s Senate held hearings on how to develop them.

Having established itself in 1930 as the rightful owner of the resource (by appeal to Britain’s Privy Council), Alberta’s government intensified its efforts to create a long-term policy just after the Second World War. The effort was short-lived, however, because of important discoveries of light oil at Leduc and elsewhere, beginning in 1947. Why develop the sands when high-quality crude was there for the pumping?

The province has always understood that its long-term future lies with the sands, however. Despite gathering volumes of conventional oil production, in 1962 the government announced an oilsands policy for the long term. In response, two proposals came forward. Cities Service Athabasca Inc. proposed a 100,000 barrel per day plant at the site of its Mildred Lake pilot project – the site of the Syncrude project. Including a pipeline to Edmonton, the plant was to cost $56 million, with construction beginning in 1965 and completion in 1968.

In that round the winning bid was for the much smaller Great Canadian Oil Sands Limited (today’s Suncor plant), which initially received approval for a 30,000 barrel per day plant. By the original terms of its license, production from the plant could not exceed 5% of total volumes in markets already supplied by conventional oil from Alberta.

For its part, Cities Service got a rejection letter. Undeterred, in 1964 the company assembled the Syncrude consortium, which later applied for a much larger (140,000 barrel per day) plant. The proposal received approval in late 1969. But before the plant shipped its first barrel of oil nearly ten years later, the project experienced a financial crisis.

Crisis: The reason for the long gap between approval and completion was an alarming escalation of costs besetting major North American projects. High inflation multiplied budgets for practically every aspect of the Syncrude project.

Reviewing project costs in late 1973, the Syncrude consortium found that costs had more than doubled, from $1 billion to $2.3 billion. One of the partners, Atlantic Richfield, needed cash to develop its Prudhoe Bay interests and frankly saw its Alaskan bonanza as a far more attractive bet than investing in the oilsands. In December 1973, the company withdrew its 30 per cent participation in the project. A few days later, the three remaining partners – Gulf Oil, Imperial and Cities Service – informed the Alberta government that they were unwilling to risk more than $1 billion on the project. They would need another $1 billion of risk capital if the project were to go on.

The prospect of Syncrude collapsing was a political and economic nightmare. The world was reeling from the oil crisis of the day. Policy-makers in the rich Western countries considered it a matter of national urgency to develop stable, secure energy supplies. The rich world was experiencing the worst recession since the Second World War, and Canada desperately needed economic stimulus. Because the oilsands were so large and development was so clearly possible, getting Syncrude back on track looked like Canada's best bet for both coherent policy and economic stimulus. From coast to coast to coast, Canadians came to believe the project must not falter.

Alberta reviewed the cost estimates given by the Syncrude consortium. When it found those estimates weren’t out of line, the province helped convene, in February 1974 in Winnipeg, a historic meeting between consortium members and governments.
Three governments joined the consortium as commercial partners, thereby salvaging the project. The federal government took a 15% interest, Alberta 10% and Ontario 5%. Alberta also took full ownership in the no-risk pipeline and electrical utility. The private partners agreed to take a $1.4 billion interest in the project, but gave Alberta the option to convert a $200 million loan to Gulf and Cities Service into equity.

The Billionth Barrel: Syncrude went into operation in the summer of 1978 and produced 5 million barrels of oil within a year. World oil prices leaped skyward in 1979-80 and remained high for the first half of the 1980s. This helped Syncrude become successful financially as well as technically. The collapse of oil prices in 1986 – followed by 15 years of lower prices – intensified the organization’s incentive to reduce costs per barrel while increasing production. Production rose steadily in the ensuing years and, on April 16, 1998, the plant piped its billionth barrel down the line – five years ahead of schedule.

Ten years later, a counter on the Syncrude website zips along at a rate of four barrels a second, estimating the volume the plant has produced: as this magazine goes to press, about 1.9 billion barrels. A giant since inception, Syncrude is too big and complex to easily conceptualize. The largest producer of crude oil from oilsands, 350,000 barrels of oil pour from its processing vessels every day. Every twenty-four hours, the sands wear the metallic equivalent of two full-size pickup trucks off the plant’s mining equipment.

One of the most complex industrial operations anywhere, Syncrude operates the largest network of open-pit mines. It is Canada’s largest single source of oil, producing volumes equal to 15% of total national requirements. It extracts the raw oil known as bitumen from the sand and then turns it into the sweet light crude oil known as Syncrude Sweet Blend by processing it in vast upgrading vessels. The plant’s “synthetic crude” (hence the name) moves by pipeline to refineries in Canada and the United States.

Syncrude plans to increase production to about 500,000 barrels of crude oil per day within the next decade. As it does so – and as it has done for the last three decades – the consortium will continue to introduce new technologies and processes. These will improve the plant’s efficiency and reduce its per-barrel impact on the environment. During the next decade, the consortium estimates, its sulphur dioxide emissions will decline by 60% from today's levels. Reflecting efficiencies of scale and better technology, per barrel energy consumption will drop by 1% annually.

Today the technology is proved, and oilsands development is of global rather than national interest. Many policy-makers now view oilsands development as a critical source of relief for straining international supply. Sitting in the opposition benches are environmental and public health issues. Mainstream in a way they weren’t 30 years ago, they will threaten some of tomorrow’s giants.

Athabasca Chronology

2008-07-05T19:38:00.009-06:00

By Peter McKenzie-Brown

• 1714. Hudson’s Bay Company (HBC) fur trader James Knight records in his journal at Fort York (in what is now Manitoba) that Indians told him of a “great river” far inland where “there is a certain gum or pitch that runs down the river in such abundance that they cannot land but at certain places.”

• 1719. Henry Kelsey of HBC’s York Factor (near the western shore of Hudson Bay) notes that Cree Indian Wa-Pa-Sun has brought him a sample “of that gum or pitch that flows out of the banks of the river.”

• 1778. Fur trader Peter Pond reports “springs of bitumen that flow along the ground.”

• 1788. Famed explorer Alexander Mackenzie writes, “at about 24 miles from the fork (of the Athabasca and Clearwater Rivers) are some bituminous fountains into which a pole of 20 feet long may be inserted without the least resistance….The bitumen is in a fluid state and when mixed with gum, the resinous substance collected from the spruce fir, it serves to gum the Indians’ canoes. In its heated state it emits a smell like that of sea coal.”

• 1894. Dominion Government sends rig to drill for oil along the Athabasca River, hoping to find light oil below the oilsands. In 1897 the second well strikes gas and blows wild. The Pelican Rapids well burns an estimated 20 million cubic feet per day until killed in 1918.

• 1907. Alfred von Hamerstein, who claimed to be an immigrant German count, tells a Senate committee “I have all my money put into it (the Athabasca oil sands), and there is other peoples’ money in it, and I have to be loyal. As to whether you can get petroleum in merchantable quantities . .. . I have been taking in machinery for about three years. Last year I placed about $50,000 worth of machinery in there. I have not brought it in for ornamental purposes, although it does look nice and home-like.”

• 1913. Federal Department of Mines assigns Dr. S.C. Ells, an engineer, to investigate the sands’ economic potential. He proposes using it for road-paving, which becomes a marginal cottage industry.

• 1923. Assigned by the Alberta Research Council to study the oil sands, Dr. Karl Clark and his associate, Sid Blair, build the first bench model of Clark’s hot-water separation plant at the University of Alberta.

• 1925. Alberta Research Council constructs a pilot project using the process near Fort McMurray.

• Bitumount:

• 1925. R.C. Fitzsimmons founds International Bitumen.
1930. The company uses a combination hot water and solvent method to produce bitumen at a location called Bitumount. Plant soon falters.
• 1943. Alberta government makes plans to build an oil sands plant at the Bitumount site.
• 1948. Constructed for $725,000, plant goes on production. Operations end after Leduc discovery.

• Abasand:

• 1930. Max Ball and B.O. Jones of Denver organize Abasand, buying the Alberta Research Council's Fort McMurray plant.
• 1935. Company begins construction of a new plant, scheduled to go into operation by 1936. Forest fires and equipment supply delays hold up plant construction.
• 1941. Mining begins, and the plant processes 18,475 tonnes of oil sand to produce 17,000 barrels of oil. Fire destroys the plant, which is rebuilt.
• 1943. Federal government takes over plant as part of war effort.
• 1945. Fire destroys operation.

• 1950. Alberta government issues report on oil sands potential by S.M. Blair, who proposes that development could be economic for 20,000 barrel-per-day projects. He envisions such a plant costing $43 million and generating a 5 to 6 per cent annual return on investment.

• 1951. Alberta sponsors a conference on oil sands geology, mining, recovery, transportation and refining. Nathan Tanner, Alberta's Minister of Mines and Minerals, outlines provincial policy on oil sands leasing and royalties. A dozen companies take out 20,000-hectare exploration permits.

• 1959. Cities Service Athabasca constructs a 3,000 barrel per day plant at Mildred Lake. Plant extracts bitumen at a field facility, then upgrades at a pilot refinery.

• 1962. Great Canadian Oil Sands Limited receives approval for 30,000 barrel per day, $122 million plant. Financial difficulties ensue.

• 1964. Sun Oil Company takes over GCOS project, receiving approval to construct 45,000 barrel per day plant for $190 million.

• 1967. GCOS goes into production; final cost: $250 million.