The Organization for Economic Cooperation and Development has urged Canada and its oil-sands province Alberta to invest in a Norway-style sovereign wealth fund to curb the killer effects on local industry of an oil-inflated Canadian dollar.

The Canadian government is already considering the idea of putting commodity royalties into a Norway-style pension fund, however Canadians have preferred local investment in their giant country rather than investments in financial and physical assets abroad, as with the Norway model.

The Norwegian “Oil Fund” was created to pass wealth to post-oil generations of Norwegians.

In an interview with Bloomberg News on his away to Japan, Canadian Finance Minister Jim Flaherty said he was “intrigued” by the Organization for Economic Cooperation and Development proposal this week that Canada save its oil revenues.

The dangers, the Organization for Economic Cooperation and Development said, was “Dutch disease”, an affliction named in the 1970s, when offshore gas stymied The Netherlands' economy by stirring a hunger for its currency.

Alberta, meanwhile, was told to change its Heritage Fund into an oil-based foreign asset fund, “as Norway does, spending only smoothed yearly fund income”.

As for the rest of Canada: Tax policies for the oil and gas sector must be updated for the era of high oil prices by removing some federal deductions for exploration; royalties should be streamlined to capture “pure economic rents” and “removing the exploration/production requirement for tenure rights”.

Refinery expansions in the U.S. focused on processing crude from Canadian oil sands show an entrenched reliance on fossil fuels even as concerns grow about the effects of oil sands production, an environmental group said Wednesday. Such multibillion-dollar investments illustrate a long-term shift in refining toward so-called heavy oil, which requires more energy-intensive production and prompts worries about emissions and waste runoff, the report's authors said.

"The first step is to start with awareness of what it means," said Eric Schaeffer, a former Environmental Protection Agency lawyer who is director of the Washington-based Environmental Integrity Project, an advocacy group that produced the report.

"This is an intensely wasteful way to feed an oil habit," Schaeffer said.

Canada is the biggest exporter of oil to the U.S., sending more crude than Mexico, Venezuela and Saudi Arabia. And with an estimated 173 billion barrels of reserves, Canada's bounty is second only to Saudi Arabia's.

The oil sands now produce 1.3 million barrels a day, which could ramp up to 3 million barrels a day by 2015, according to the Canadian Association of Petroleum Producers.

More and more companies have jumped into the oil sands game as high oil prices have made its costly production economical. The world's five largest oil companies, as well as Canadian producers and some independent explorers and producers, have sands operations or joint ventures.

But as oil sands production has increased, so have concerns about increases in emissions and possible releases of toxic waste into waterways.

Emissions from oil sands production far exceed those from conventional crude production. Waste in some operations sits in so-called "tailing ponds" visible from space, the report said.

In late April, nearly 500 migrating ducks died after landing in a Syncrude Canada tailing pond. Such ponds are required to have noise devices to scare off birds, but Syncrude's devices weren't working in the aftermath of a snowstorm. The Canadian government is investigating.

Schaeffer acknowledged that pushing to cease oil sands production isn't practical.

The report noted that refinery expansions and new construction are long-term investments, indicating that the U.S. intends to receive and refine Canadian crude for many years to come.

So instead of recommending an end to production and refining of oil sand crude, the report calls for the U.S. to reduce oil consumption by improving efficiency standards for vehicles; raise emissions control standards; consider alternatives to oil derived from the sands in Clean Air Act reviews of proposals for refinery expansion and construction; and account for sulfur, nitrogen, and other impurities in heavy oil when issuing construction permits.

Expansions are expected to add 800,000 barrels a day of refining capacity by 2011, according to the American Petroleum Institute.

A new refinery hasn't been built in the U.S. since 1976. A proposal to build one is under consideration in Arizona. Another proposal for a plant was approved this week by voters in Union County in South Dakota.

Bill Holbrook, spokesman for the National Petrochemical & Refiners Association, said 22 expansion projects are ongoing, though not all are related to adding Canadian oil capacity.

Cindy Schild, manager of refinery issues for the American Petroleum Institute, said Canada is stable, friendly and open to outside producers. It stands apart from resource-rich countries like Venezuela or Russia that have squeezed access, or ones in the Middle East and West Africa that are vulnerable to geopolitical tensions or civil violence.

"We view the Canadian oil sands as a reliable source of energy," she said.

She added that refiners have little choice but to revamp plants to handle heavy oil like that produced in Canada and other countries, including Venezuela. Heavy oil contains more impurities than light, sweet crude from the Middle East, and requires more complicated processing to turn it into gasoline and other fuels.

Also, Schild said, if U.S. refineries eschew Canadian oil, China and other energy-hungry emerging countries will take it.

"Do you want it to be processed in a country with standards in place to address environmental impacts maybe more stringently than others? It's going somewhere," she said.

Gazprom moved a Canadian liquefied natural gas terminal ahead yesterday by taking a stake and agreeing to supply all of the gas needs from the Russian company's huge Shtokman project, the companies said yesterday.

Gazprom is joining Enbridge Inc., Gaz Metro and Gaz de France in developing the $840 million Cdn Rabaska LNG project in Quebec.

It would be the Russian firm's first major investment in North America, said Gazprom's Alexander Medvedev.

Canadian oil and gas giant EnCana Corp. said Sunday it's splitting into two companies, but operations in Colorado are likely to remain "business as usual," a Denver-based spokesman said Monday.

EnCana is based in Calgary, Alberta, Canada. Its U.S. division is based in Denver.

"It's driven by shareholder value," said Doug Hock, spokesman for Denver's EnCana Oil & Gas (USA) Inc. "It shouldn't affect our operations at all. It's business as usual in terms of exploring for and producing natural gas."

EnCana is one of Colorado's largest natural gas producers, with operations in the rich Piceance Basin on Colorado's Western Slope and north of Denver in the Denver-Julesburg Basin.

The parent company announced Sunday that the board of directors had unanimously approved a proposal to split EnCana into two energy companies -- one a natural gas company with assets in Canada and the United States, and the second a fully integrated oil company focused on producing oil from oilsands in Canada and running refineries in a joint venture with ConocoPhillips in Texas and Illinois.

The natural gas company is expected to retain the EnCana name, while the oil company will operate under a new name, tentatively called "IntegratedOilCo." or IOCo.

The natural gas company represents about two-thirds of EnCana's current production and proved reserves.

Shares of EnCana rose in early trading Monday in response to the news.

Is nuclear power the answer to the energy crisis? The world's first large-scale nuclear power plant opened at Calder Hall in Cumbria, England, in 1956 and produced electricity for 47 years.

Nuclear power is generated using uranium, a metal that is mined as an ore in large quantities, with Canada, Australia and Kazakhstan providing more than half of the world's supplies.

Nuclear reactors work in a similar way to other power plants, but instead of using coal or gas to generate heat, they use nuclear fission reactions. In most cases, heat from the nuclear reactions convert water into steam, which drives turbines that produce electricity.

There are different kinds, or isotopes, of uranium, and the type used in nuclear power plants is called uranium-235, because these atoms are easiest to split in two. Because uranium-235 is quite rare, making up less than 1% of natural uranium, it has to be enriched until the fuel contains 2-3%.

Inside a nuclear reactor, rods of uranium are arranged in bundles and immersed in a giant, pressurised water tank. When the reactor is running, high-speed particles called neutrons strike the uranium atoms and cause them to split in a process known as nuclear fission. The process releases a lot of energy and more neutrons, which go on to split other uranium atoms, triggering a chain reaction. The energy heats up the water, which is piped out to a steam generator.

To make sure the power plant does not overheat, control rods made of a material that absorbs neutrons are lowered into the reactor. The whole reactor is encased in a thick concrete shield, which prevents radiation escaping into the environment.

In Britain, nuclear power stations provide 19% of our electricity and account for 3.5% of our total energy use. All but one of those reactors are due to close down by 2023. Some groups oppose nuclear power stations because they produce radioactive waste and could release radioactive material if there was an accident. But nuclear power plants do not release greenhouse gases, which cause coal and gas-fired power plants to contribute to global warming. Without nuclear power stations, UK's carbon emissions would be 5% to 12% higher than they are.

In 1957, the world's first nuclear power accident occurred at Windscale in west Cumbria. A fire in the reactor caused a release of radioactivity, which led to a ban on milk sales from nearby farms. The site was later renamed Sellafield. Modern reactors are designed to shut down automatically. The worst nuclear power accident in history took place in Chernobyl in 1986 when a reactor there exploded, killing tens of people instantly and exposing hundreds of thousands more to radiation.

In January, the government reaffirmed its plans to expand nuclear power in Britain to help it meet stringent targets to reduce carbon dioxide emissions.

Nuclear weapons
There are two main types of nuclear weapon: atomic bombs, which are powered by fission reactions similar to those in nuclear reactors, and hydrogen bombs, which derive their explosive power from fusion reactions.

The first atomic bomb was produced at Los Alamos National Laboratory in America under the Manhattan Project at the end of the second world war. An atomic bomb uses conventional explosives to slam together two lumps of fissionable material, usually uranium-235 or plutonium-239. This creates what is known as a critical mass of nuclear material, which releases its energy instantaneously as atoms inside it split in an uncontrolled chain reaction.

Atomic bombs unleash enormous shock waves and high levels of neutron and gamma radiation. In atomic bombs, uranium is enriched much more than fuel, to about 85% uranium-235.

On August 6 1945, an atomic bomb called Little Boy was dropped on the Japanese city of Hiroshima, followed three days later by another, called Fat Man, on Nagasaki.

Hydrogen, or thermonuclear bombs, work in almost the opposite way to atomic bombs. Much of their explosive power comes from fusing together hydrogen atoms to form heavier helium atoms, which releases far more energy than a fission bomb. Two types, or isotopes, of hydrogen are used - deuterium and tritium. A deuterium atom is the same as a hydrogen atom, except the former has an extra neutron in its nucleus. A tritium atom has two extra neutrons.

A hydrogen bomb has a built-in atomic bomb, which is needed to trigger the fusion reaction. Hydrogen bombs have never been used in war and are thousands of times more powerful than atomic bombs.

The first test of a hydrogen bomb was at Enewatak, an atoll in the Pacific Ocean. It released a three mile-wide fireball and a mushroom cloud that rose to nearly 60,000 feet, destroying an island in the process.

Nuclear waste
One of the biggest problems the nuclear industry faces is what to do with the radioactive waste it produces. Some of it will remain radioactive and hazardous for hundreds of thousands of years.

High-level waste is the most dangerous because it can melt through containers and is so radioactive it would be fatal if someone was near it for a few days. This type of waste makes up just 0.3% of Britain's total volume of nuclear waste, which is mostly waste from spent fuel rods. The largest amounts of radioactive waste are made up of nuclear fuel cases, reactor components and uranium.

Today, high-level waste is dealt with by cooling it in water for several years and then mixing it into a molten glass, which is poured into steel containers. These canisters are then stored in a concrete-lined building.

This is only a temporary measure, though. Scientists know that eventually they need to find a way of storing nuclear waste safely for thousands of years. Some countries, such as America and Finland, plan to store nuclear waste in deep underground bunkers. For this to be safe, scientists have to be sure the material could never leak out and contaminate water supplies or rise up to the surface.

Britain already has more than 100,000 tonnes of higher activity radioactive waste that needs to be stored. Large amounts of low-level waste are already stored in concrete vaults in Drigg in Cumbria. Other plans for disposing of nuclear waste have included dumping it at sea and blasting it into space.

With French and German companies lining up to build new nuclear power stations in Britain, the die now seems cast for nuclear. Or is it?

The government's goal is certainly ambitious. Ten countries - primarily the UK, US, France and Canada, but also including Japan, Korea, Brasil, Argentina, South Africa and Switzerland - have set up the Generation IV International Forum. It will develop a successor nuclear energy system to the previous Generations I (Magnox) and II (advanced gas-cooled reactors and the Sizewell B light water reactor) and follow the Generation III systems now being built. The latter includes the French Areva evolutionary pressure reactor (EPR), the prototype of which is being constructed at Olkiluoto in Finland, with another being built in France.

Improved versions
It is intended that these Generation III models, plus (hopefully) improved versions in future, will lead reactor orders through to 2030, after which it is hoped that Generation IV will kick in, with the goal of nuclear sustainability.

However, the roadmap to get there is beset by practical problems that may prove insurmountable. Generation II and III nuclear plants operate in a "once-through" mode, which means that only half the 0.7% fissionable uranium 235 content of natural uranium goes into the fuel, while most of the heavy metal ends up in enrichment tails and in spent fuel as waste. This, therefore, requires a constant and increasing supply of natural uranium to meet the rising demand for electricity, while intensifying the already unresolved problem of what to do with vast accumulations of radioactive waste.

Even the International Atomic Energy Agency and the optimistic Organisation for Economic Cooperation and Development put the total world uranium reserves at 4.7m tonnes, and that assumes a purchase price of at least $130/kg. In fact, prices are currently nearly twice as high, yet primary uranium production is falling. But even if the figures were roughly correct and not significantly inflated, the total of known uranium resources is expected to be exhausted by 2030. If fast reactors were to be introduced by then, which is the centrepiece of the strategy, a further 10m tonnes - twice the known resources - would have to be ready for production, and this could only come from "speculative and undiscovered resources".

The nuclear power industry answers this by referring to the universality of uranium in the Earth's crust and in sea water. But the enormous energy needed to extract it from these low-concentration sources would exceed the energy output of the fission of the fuel provided.

These pressures are already being felt. The USA gets half its nuclear fuel from diluted former nuclear weapons' highly-enriched uranium from Russia. And even Russia, with insufficient primary production, will be forced to rely on ex-weapons material to power its planned expansion. The UK's aim to secure energy supplies will not be aided by importing 100% of nuclear fuels, and that's on top of increased dependence on imported fossil fuels, notably gas.

Meanwhile, Japan has closed seven nuclear power stations built on an earthquake fault line. The Olkiluoto reactor is already two years behind schedule after just two years' building and has a £1bn cost overrun so far, and there can be no reliable evidence on the economics of nuclear power until the new designs of the Westinghouse AP1000 and European EPR water reactors have been fully tested over many years in service. Contrary to claims by the industry, unresolved questions of cost and the looming shortage of uranium are the biggest challenges to the nuclear revival.

To overcome the fragility of this recovery, the industry looks to Generation IV development of the fast reactor by 2030 as the key to ultimate nuclear sustainability. However, if for this purpose the fast reactor were adopted in "breeder" mode, an even greater quantity of highly radioactive actinoids (plutonium, neptunium, americium and curium) would be generated, exacerbating still further the waste management problem. If, on the other hand, the fast reactor were adopted in "burner" mode, as currently seems likely to prevail, the waste problem is alleviated, but there is no sustainability.

The Generation IV fuel systems offer at present six types, of which two are emerging as likely candidates. One is the very high temperature thermal reactor (VHTR), which can be used for coal gasification as well as thermo-chemical hydrogen production. The US government favours this because a hydrogen economy is seen as the solution to the exhaustion of oil reserves, and the petrol derived from it.

The main problem with VHTR, which has a coolant system outlet temperature of about 1,000C, is likely to arise from irradiation characterised by the Wigner effect - the displacement of atoms in a solid caused by neutron radiation - and from progressive disintegration by neutron bombardment. Indeed, a similar problem with the Wigner energy in Pile 1 at Windscale (now Sellafield) caused the fire in 1957 and melted the fuel elements. Given the very high temperatures needed for this complex and quite likely unstable process, its viability would need rigorous and exhaustive testing before such a problematic reactor were ever adopted.

Repetitive cycle
The second favoured Generation IV candidate is the sodium-cooled fast reactor system (SFR). The idea here is that as the supply of natural uranium declines, it is replaced by a plutonium-based fuel that is incrementally augmented by fresh plutonium in a repetitive cycle, providing claims of sustainability. It is envisaged that there is a gain in the plutonium in a surrounding "blanket" of uranium 238 over and above the plutonium consumed in the reaction, with a doubling time of 15 to 20 years.

Again there are two key problems. It is a burner reactor, not a breeder, so that while reducing waste management problems, it does not provide for sustainability. Second, even if fast reactors of this kind could be successfully deployed - a big if - the doubling time of 15 to 20 years would require supplies of natural uranium to be maintained for decades, if not centuries, until the fleet of "once-through" reactors can be progressively replaced. And the uranium simply is not available for that timespan.

So, a nuclear renaissance? Forget it.

According to the pessimists, the rigs off Britain's coast could cease pumping in a decade's time.

The sight of a convoy of giant tankers last week carrying emergency petrol supplies to the UK is a glimpse into the future. Last weekend's strike at the Ineos refinery at Grangemouth, which helped push up oil prices to a new record of $120 a barrel, reminded us how dependent we have become on North Sea oil - and how we will have to cope in the not-too-distant future when it's all gone.

When the refinery closed, BP also had to shut down the Forties pipeline that supplies it with oil. This pipeline carries about 700,000 barrels of oil - or almost half of the UK's daily production - from the North Sea. The strike has ended but oil production from the North Sea, which now barely meets UK demand, is declining much more quickly than predicted.

By 2020, oil and gas production could be one-sixth of today's level, according to the most pessimistic forecasts - enough to meet only 8 per cent of UK demand. Despite the soaring oil price, companies are drilling fewer exploration wells in the North Sea and investment levels have also started to fall.

Malcolm Webb, chief executive of the trade association Oil & Gas UK, warns that unless these trends are reversed, some nine billion barrels of oil and gas - about nine years' worth of production at today's levels - could be left at the bottom of the sea forever. This would cost the cash-strapped Treasury billions in lost tax revenue - and more importantly would hasten Britain's total dependence on countries such as Russia and the OPEC members for its oil and gas.

Oil was discovered in the North Sea in the late 1960s, with production peaking in 1999 at about 4.5 million barrels per day. The oil fields have yielded 36 billion barrels to date. Since then, production has declined every year. Currently it stands at about 3 million barrels per day and is forecast to decline about 10 per cent by the end of the decade.

The decline has long been forecast. But what no one knows is how steep it will be - nor when the oil will finally run out. The government estimates that there are still between 16.5 and 25.5 billion barrels of oil to be recovered in the North Sea. Based on current production levels, that equates to 16 to 25 years of production left. But these figures include oil yet to be discovered, so are unreliable. Using companies' plans, fewer than 10 billion barrels would be delivered. That would see the North Sea run dry within a decade. It seems the government has finally woken up to the fact that the industry itself will determine how much longer the North Sea lasts.

The UK Prime Minister, Gordon Brown pleaded with BP and Shell last week to spend some of their combined £7bn record first-quarter earnings on pumping more crude out of the sea bed off Britain's eastern coast. 'I hope that these profits are going to be invested in getting more oil out of the North Sea,' he said.

It's likely his pleas fell on deaf ears. BP has already sold its Forties field - one of the largest in the North Sea. Shell, too, has been selling off its fields there so it can concentrate on bigger, higher-growth projects like its oil-sands projects in Canada.

The oil majors have been replaced by smaller pure exploration and production companies, which have a greater incentive to squeeze the remaining oil out of mature North Sea fields. One such company is Tullow Oil, which spent £200m in 2005 buying two fields from Shell and Exxon Mobil.

John Caskie, Tullow Oil's asset manager for the Caister-Murdoch System area of the North Sea, says: 'Places like West Africa offer high-impact exploration and potential company-changing discoveries. The North Sea, on the other hand, is where we look for steady production within a relatively well known commercial and fiscal environment. The North Sea, if you like, pays the mortgage for guys to explore in places like Africa.'

In other words, companies use the North Sea as a cash cow to fund exploration elsewhere. But companies are spending less time and money looking for new fields in the North Sea itself. They drilled 15 per cent fewer development wells last year compared with 2006. You can't blame them: Oil & Gas UK estimates 96 per cent of future discoveries will be smaller than 50 million barrels. As Global Insight points out, they pale into insignificance compared with giants like the Forties field, which produced over 2.5 billion barrels.

The fewer new discoveries coming on stream in the North Sea to replenish the rapidly maturing fields means the decline in production will increase even more quickly. As one executive of an oil company admits: 'The reality is that these fields are in decline as soon as production begins. Everyone is running just to stand still.'

The way the government taxes oil companies is also coming under the spotlight. The tax rate is 50 to 75 per cent, depending on the age of the field. It is hard to compare this with tax regimes around the world. In Norway, the government levies a slightly higher tax rate of 78 per cent. But, crucially, it allows companies to offset the entire cost of exploration as tax relief, even if that exploration does not yield any oil. In the UK, companies can only claim tax relief against exploration if the newly explored field starts generating revenue.

Costs for every aspect of exploration and production are also soaring. While this is the case across the world, higher costs - combined with high taxes - discourage companies from sinking huge amounts of money in the North Sea for relatively small rewards. As Caskie says: 'The UK is competing against places where the potential to make big discoveries is much higher compared with the North Sea. When costs and the tax take are so high, exploration drilling often makes more sense elsewhere.'

Webb says much of the extra 9 billion barrels of oil that could be extracted from the North Sea lies in fields next to those coming to the end of their lives. Unless companies have stronger incentives to start tapping these new fields, they will soon start decommissioning their platforms - leaving those 9 billion barrels out of reach. 'Current investment behaviour will materially affect whether all those extra barrels are recovered,' he warns. 'Unless there is a steady flow of new projects to make use of the existing infrastructure then companies will have to start decommissioning it.'

Last week, Frank Chapman, the chief executive of BG, one of the biggest producers in the North Sea, called on the government to provide greater incentives to develop more fields. Requests for government help may jar with the public when energy companies like BG are enjoying record profits on the back of soaring oil and gas prices. But the reality is that oil companies - even British ones - have no obligation to stay in the North Sea if richer pickings can be had elsewhere.

Schlumberger, the world's biggest oilfield contractor, and First Reserve, an energy industry buyout fund, agreed to acquire Canada's Saxon Energy Services for about $582.1 million to expand in South America.


Saxon Energy Services shareholders will get seven Canadian dollars a share, Calgary-based Saxon said in a Canada Newswire statement today. That's a 1.9 percent premium to Saxon's closing price May 2. Saxon, had 84.59 million shares outstanding as of April 30, according to Bloomberg data.

Schlumberger, based in Houston and Paris, is seeking a bigger stake in the growing market for oilfield-services companies as oil prices surge to records.

"The C$7 a share price is a bit skinny," said Irwin Michael, who helps manage $1.25 billion at ABC Funds in Toronto including about 6.25 million shares in Saxon. "We think it's worth C$7.50 or more."


Saxon Energy Services gained 13 cents, or 1.9 percent, to C$7 as of 10:24 a.m. in trading on the Toronto Stock Exchange. Schlumberger rose $1.86, or 1.9 percent, to $101.49 in composite trading on the New York Stock Exchange. Saxon Energy Services is worth more because of record oil prices, according to Michael.

"We have a lot of faith in (Chief Executive Officer) Dale (Tremblay)," he said in an interview. "The earnings have yet to come through but the potential is there."

Saxon said on May 1 its first-quarter profit fell 36 percent to $5.1 million, or 6 cents a share, from $8 million, or 10 cents a share, a year earlier. Revenue climbed 31.5 percent to $72.2 million.

Crude oil futures traded in New York have risen 91 percent in the past year. They touched a record $119.93 a barrel on April 28.

Saxon Energy Services has 21 rigs in South America, 11 in Mexico and 19 in the U.S., according to Sanford C. Bernstein & Co. analyst Ben Dell in New York.

"We are seeing a trend of the services building out their rig fleet so they can offer truly integrated project management from drilling to completion," Dell said in an e-mailed statement.

Stephen Harris, a Schlumberger spokesman, didn't return a telephone call for comment. A spokesman for First Reserve couldn't be reached. Saxon was advised by Thomas Weisel Partners Canada Inc.