Q&A with Marcel Coutu

Syncrude's Chairman of the Board delves into operations, the environment and the demise of oil around the world. This article appears in the July 2008 issue of Oilsands Review.

By Peter McKenzie-Brown
Canadian Oil Sands Trust owns the biggest single share of Syncrude (37%), and the firm’s CEO is also Syncrude’s chairman. Oilsands Review asked Marcel Coutu about operating and environmental issues at the oil sands giant. His edited comments follow.

OSR: Developing new technology has been part of the business from the beginning. To what extent is that still the case?

MC: The first few years of this business were about survival, because oil prices were low and costs were high. When oil prices were low and margins were thin the driver for this business was always lowering costs. That really hasn’t changed much.

Both Syncrude and especially Suncor have been major developers of new technology. Suncor, for example, developed hydro transport – technology that enabled us to move oil sands ore by pipeline rather than truck. So all of a sudden we were operating satellite facilities, without having to truck ore to the processing site. That was a major innovation.

The tailings ponds are a major challenge area. It’s an important functioning part of our operations, and enables us to recycle our water. It’s a major challenge. We need to find ways to separate clay from the water more rapidly. This will help us reclaim land better.

OSR: Oilsands inflation has been high in recent years. How has that affected you?

MC: The one inflation component that has dwarfed all the others is the price of natural gas, which has moved up in parallel with the price of oil. We buy eight-tenths of an MCF of natural gas for every barrel of light sweet product we produce. The rest of our costs are increasing by low double-digit to high single-digit numbers, and over the years those costs add up. Fortunately, oil prices have more than offset operating-cost inflation.

OSR: How much energy do you consume for every barrel of oil you produce?

MC: About 1.5 gigajoules (1.5 MCF of natural gas equivalent) per barrel. That’s higher than 0.8 MCF, the number I mentioned earlier; that refers to purchased energy. The total energy we consume in our operations includes energy we generate as a by-product to our upgrading processes. It is largely electrical energy, in which we are more than self-sufficient.

We produce a lot of waste gas from our processes, and use that to fire gas turbines. We also have a lot of waste heat from our operations, and we raise steam with that heat and put that steam into steam turbines. This makes our operations more efficient.

Beyond that we arbitrage against the price of electrical power around the clock, sometimes selling electricity into the Alberta grid, sometimes buying it, depending on how those conditions align. We arbitrage those markets in both directions. We do the same with natural gas. It’s one of the businesses we do to make ourselves as energy efficient as possible.

OSR: How are you managing carbon dioxide emissions?

MC: We’ve been reducing them from the time we opened the plant gate. Carbon dioxide emissions are all about energy consumption – they are exactly the same thing; reciprocals, if you will. You only create CO2 emissions by burning fuels. We have always been incentivized to keep our energy consumption as low as we can, and lowering consumption means lowering CO2 emissions. We have always been focused on reducing CO2 emissions because they represent a direct cost to us.

OSR: You are a member of ICON, the Integrated CO2 Network. Any thoughts on carbon sequestration?

MC: The plants at Fort McMurray are the largest collectible source of CO2, but it is an expensive proposition. You have three levels of major expenditure there. You could sequester a lot of CO2, but I’ve seen numbers that you are actually generating more CO2 than you are sequestering by going through this process. First you have to construct equipment to extract the CO2, then build a pipeline, then pump the carbon dioxide into the saline aquifers, salt domes, old reservoirs or whatever you use to host the stuff.

OSR: The notion that crude oil supply is about to peak or has peaked is gaining a lot of currency. What do you think?

MC: Natural gas is in vast supply around the world but oil is not. Crude oil production in most of the producing countries in the world is in decline.

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

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

OSR: How serious a problem is maintaining global production?

MC: Very. World oil production is generally in decline. You can assume that out of global production of 87 million a day, productivity will come off by 5-10 percent every year, so you have to replace that production each year before you can even begin to satisfy global demand growth. So what we are seeing is the demise of the commodity, since we are never really going to be able to meet the demand. Prices will be volatile, but the trend in my view is that prices will continue to climb. The demand will be fully there regardless of anything that happens to the US economy. The decline is real and cannot be arrested, at least not in the short term. One hundred and fifty dollar oil is within striking distance.

OSR: What is the role of the oil sands in this environment?

MC: Oil sands production is close to a million barrels a day, a little more than 1 per cent of global production. It’s going to take a huge amount of effort, capital and time, maybe ten years, to double Canadian oil sands production. It’s true that the Canadian resource is huge, but accessibility is long and slow. Our impact will be very slow.

One thing we need to bear in mind is that the size of our resource goes up with the price of oil; the higher world oil prices grow the greater our resources become. We have re-evaluated Syncrude’s leases, and that re-evaluation has taken us way up from 9 billion barrels, which was our traditional resource base. That’s good for Canada and Alberta and the rest of it.

OSR: How are you dealing with the labour shortages around Fort Mac Murray?

MC: To answer that, you have to think of labour as being in two buckets. The people in the operational bucket are there for the duration. They have great careers, pension plans and so on. Everyone puts their shoulder to the wheel, and we get the job done. We lose some people, but the situation is manageable.

Then there is the contract bucket – construction workers, pipefitters and so on, who are mostly there to work on expansions. They are there on a temporary basis and they are hard to hold onto. They are the challenging part of the work force. The labour problems we face are focused in that area.

OSR: Having waterfowl fly into the tailings pond brought international attention to Syncrude. Do you want to comment on it?

MC: We’ve extended apologies to everybody. It was really a heartbreaking incident for us. Why did it happen? Because we didn’t have our equipment deployed before the ice thawed. It’s something we have been managing for decades with success, but we got caught by the weather. We didn’t have our deterrents in place.

OSR: What are some of the other environmental issues you face?

MC: In general, our environmental story has been glowing. Where we have done a poor job has been in telling the world about it.

I’d like to comment in three areas – water, air and land. Let’s start with water. At Syncrude we consume two tenths of 1 percent of the water from the Athabasca River for our operations. We recycle as much as we can. If you extrapolate from that, the whole oil sands industry consumes less than 1% of the Athabasca’s flow.

Air is a more serious issue. We reduce our CO2 emissions because it makes economic sense, as I said earlier. But there are nastier things that we have been managing for years and they cost us a lot of money, and the nastiest of them all is sulphur dioxide. Our SO2 emissions peaked at 250 tonnes per day when we were producing around 250,000 barrels a day. In our last expansion we moved from 250,000 barrel per day to 350,000 barrels per day, and we invested about $1 billion in SO2 scrubbing equipment. We not only stopped the growth of SO2 emissions but reduced them slightly from our peak levels. Now we are spending another billion dollars to reduce those emissions to about 150 tonnes per day.

On the land side, in March we were the first company in the whole industry to get certification for land reclamation. We have returned that property to the province. It’s really impressive. You would never know there had been a mine there.

Losing The Arctic Edge

This article appears in the July 2008 issue of Oilweek.

Canada needs to move quickly to join international rivals exploiting the potential of the Arctic

By Peter McKenzie-Brown

Canada began to explore the far north for oil almost a century ago. In 1911 Jim Cornwall, a northern businessman, saw oil on the Mackenzie River and hired an Aboriginal named Karkesee to look for seepages. Karkesee found several. Later analysis showed the oil to be medium in gravity and low in sulphur.

Cornwall formed a syndicate with two Calgary businessmen and the group engaged T.O. Bosworth, a prominent petroleum geologist, to study the area. During his 1914 expedition, Bosworth staked three claims on behalf of his backers and reported enthusiastically on the area’s prospects. Ironically, given later events, Bosworth stressed that his supporters should take every effort to control pipeline transportation from the North to southern markets.

World War I put a halt to the group’s exploration plans, and by Armistice Day Imperial Oil owned Bosworth’s claims. The company began exploratory drilling along the Mackenzie in 1919, first drilling two salt water wells near Great Slave Lake. Farther down the Mackenzie, near Fort Norman, the third showed oil.

Led by Ted Link, who later became Imperial's chief geologist, the crew drilled the successful well with a cable tool rig. Legend has it that Link chose the site by waving his arm and saying, “Drill anywhere around here.” In August 1920, at a depth of about 1,240 metres, the world's most northerly oil well came in; Imperial put it on production the very same year.

Although just south of the Arctic Circle, the Norman Wells field established Canada as the world’s undisputed leader in northern exploration and production, and she retained that title for more than 60 years. Led by Dome Petroleum and a series of attractive federal grants, the industry’s golden age of Arctic exploration in the 1960s and 70s delivered huge natural gas discoveries and a number of small oil finds.

Let’s fast forward to the present. In petroleum terms Canada has become a second-tier Arctic nation. The US, Norway and Russia are all Arctic producers. In recent years, Denmark has done some drilling off the eastern shore of Greenland. Canada is clearly the laggard. Despite skyrocketing oil and gas prices and the many successes of Canada’s golden age, exploration in our Arctic is almost at a standstill.

As if to rub our collective nose in it, Enbridge Inc. and Gaz Metro recently announced that their proposed Rabaska liquid natural gas terminal in Québec had found a secure source of LNG. The source will be Russian energy giant Gazprom, which will deliver cargoes from an Arctic facility in the Barents Sea due to begin deliveries in 2014. By the terms of the agreement, Gazprom and Gaz de France will become equity partners with the two Canadian companies in the $840-million regasification plant.

The Great Abandon: In a sobering presentation to the Canadian Society of Petroleum Geologists, Dave Russum (VP of geosciences for AJM Petroleum Consultants) made a compelling case that Canada has fallen behind its rivals in the development of Arctic oil and gas, and that she needs to catch up. Only five countries have claims to mineral rights in the Arctic – the others are the United States, Russia, Norway and Denmark.

The United States became a major oil producer at Prudhoe Bay in 1977, and continues to produce from that supergiant field. Last year Norway began producing LNG from its Snøhvit field. Russia, which already has Arctic production in Siberia, will begin producing from Shtokman in the Barents Sea in 2014.

And Canada? This country’s most northerly oil production still comes from the 88-year-old Norman Wells field. A tiny amount of gas production serves a few small towns and villages in the Mackenzie Delta, but this service has as much to do with local development as petroleum economics. When energy prices crashed and Dome Petroleum collapsed in the mid-1980s, the industry decamped from Canada’s Arctic with great abandon.

Why? Several concerns have discouraged Arctic exploration for a generation. The main issue is geology. “In the Arctic most of the expected resources are gas,” says Russum, “and they are devilishly expensive to develop. Except for Prudhoe Bay, (the Arctic basins) have pretty much been gas plays, and we expect about 75% of the resource there to be gas. Oil has been the prize. If you couldn’t find oil, you didn’t want to develop there.” During the last two decades the expense and difficulty of Arctic development was worsened by surplus natural gas supplies in North America.

The situation has greatly changed in recent years, says the executive director of the Arctic Institute of North America. Benoît Beauchamp agrees that the Arctic is gas-prone, but says this is no longer an obstacle to development. In recent years natural gas has become recognized as a premium source of energy, although it generally serves continental rather than global markets.

This continental character raises the spectre of Canada’s tradition of bitter disputes over northern pipelines. It now appears that the joint federal and provincial panel evaluating the social and environmental impacts of the present Mackenzie Valley Pipeline proposal – this one put forward by Imperial Oil in 2004 – will delay the environmental decision on the $16.2-billion project by at least another year. This adds to a string of such problems that date back to the mid-1970s.

Like previous proposals, Imperial’s pipeline project has been dogged by setbacks. The company has yet to resolve Aboriginal land access issues or come to an agreement with Ottawa on how to finance the project. According to Beauchamp, construction of this pipeline is critical for renewed exploration in the North. “The announcement of the Mackenzie Valley Pipeline will be the gunshot that starts the race up there. Then there will be a bonanza.”

Beauchamp is more sanguine about Canada’s place in the North than Russum. “It’s true that there hasn’t been much drilling in the Arctic Islands since the 70s, but there is a great deal of interest now in the Mackenzie Delta – no drilling, but seismic and other preliminary work. A few years ago an ExxonMobil/Imperial partnership acquired a large land parcel in the shallow Beaufort, on an extension of the Delta. That’s likely an oil prospect, and three parcels adjacent to that property will be up for grabs in June. It will be extremely interesting to see how strong the interest is.” As it happened, BP acquired one of those properties for $1.2 billion. The other two went for a mere $10 million combined.

Beauchamp expects an Arctic boom. “Interest in the Arctic is mounting. There are very few places left in the world with the potential of the Arctic, and companies need to develop reserves in order to grow. Canada is likely to be a focus because we are a stable country. Corruption is not a problem here, unlike Russia. We aren’t likely to abrogate signed agreements, as the Russians did at Sakhalin Island, for example. The problems in Canada are mostly related to the approval process.

Canada Rules! Russum sees the issue as being somewhat more urgent. “For security, sovereignty and economic reasons, Canada should take an active role in Arctic development.”

That’s an opinion shared by Federal Natural Resources Minister, Gary Lunn, who met in May with leaders from the United States, Russia, Norway and Denmark to sort out how best to deal with conflicting sovereignty claims in the Arctic, including Canada’s.

“It is critically important that it’s under our sovereign control so that we set the parameters for the environment and that we make the decisions whether or not even to allow exploration,” Lund said on the eve of the meetings, which were held in Ilulissat, Greenland. “We are going up to reaffirm our commitment on defending and protecting our sovereignty in the Arctic.”

On an immediate front, Russum notes that depletion rates have been accelerating in all of Canada’s gas-producing regions. “In every area, particularly those in Alberta, we have seen declines. This is not particularly surprising, given the drop-off in drilling,” but it is an important reason to move back into the Arctic. “Estimates suggest that there might be 10 billion barrels of oil and 181 trillion cubic feet of gas in the Canadian Arctic. With high production rates depleting gas reserves across Canada, we need to be considering all opportunities.”

“Conventional and unconventional gas in southern Canada will not satisfy future North American needs,” he adds. “We have to recognize the need to develop a wide range of energy sources.” Energy is the vital commodity, he says; it equals power. In a rather unCanadian way, he argues that “countries with abundant energy (like Canada?) will control the world. Net consumer countries (like the United States?) will be at the mercy of world economics and politics.”

In the case of natural gas, the Arctic will soon become a particularly important source of supply. According to Russum, a quarter of the world’s undiscovered gas is likely to be there. Looking at the entire transpolar region, 26 geological basins make up the Arctic. Of those, 21 have had some exploration activity, and explorers have found oil or gas in ten. There is commercial production in four basins (two in Russia, one in Norway and Alaska’s North Slope). Two - Canada’s Cameron Island and the Mackenzie Delta – have been the source of minor production volumes. Given the small number of wells drilled and the Arctic’s challenges to development, these results are impressive.

Imagination Beckons: Given the prospects for huge Arctic gas discoveries and the controversy over gas pipelines to the large North American markets – in addition to the Mackenzie Valley line, there have been disputes for 30 years over a line from Prudhoe Bay through the Yukon into the Alberta network – Russum argues that Canada should consider LNG production from the Arctic. “Although there are big problems with sea ice in the winter, these are problems the Norwegians have solved” he says, “and which the Russians obviously believe are solvable. Certainly one ‘benefit’ of global warming is ice shrinkage, which means more open water in the Arctic and a more easily passable Northwest Passage.”

Another advantage of LNG is that producers have more market options – especially since “world demand is now driving gas movement.” This point harks back to the geographical maps that Dome Petroleum made famous in the early 1980s. As those maps pointed out, the Beaufort Sea is roughly in the geographic centre of the developed world. If sea ice were no problem, LNG tankers loading up in the Arctic would find themselves about equidistant from London, New York, San Francisco and Seoul. Destination decisions for cargoes from that region could be based purely on best price; the calculation of transportation costs would be largely redundant.

By contrast, traditional pipelines have a number of drawbacks quite apart from political wrangling. One of those is greater terrorist risk. Others include long timelines, the enormous capital required and the fixed destination. Pipelines from stranded resources don’t have much market flexibility.

Whether developed through traditional pipelines or LNG or both, Russum believes it needs to be done. “In the Canadian Arctic, the long-term costs of frontier gas production are going to be similar to the costs of producing unconventional gas – shale gas, coal bed methane – in large volumes. Imagination will be required for development, and we will need to apply out-of-the-box thinking to all aspects of E&P. If we do this, there is no reason our Arctic production can’t be economically viable in the global market place.”

The resources are there and the technology is available. The world’s hydrocarbon markets have never been stronger. According to Russum, “We used to be the leader in exploring the Arctic, along with the Americans. Now we have a real opportunity. We have to move beyond discussing development. We have to pursue it in an economic, environmentally sensitive and socially responsible manner.”

He pauses for effect. “We only have four competitors. Three of them have already proved that Arctic development is viable in this environment.”

Gas Goes Global

This article appears in the May issue of Oilweek; image from here.

By Peter McKenzie-Brown

Last year was awful for Canadian natural gas producers. Development and production costs were at record levels, yet the average Canadian price at AECO was $7.66 per thousand cubic feet – seventy-four cents lower than American producers received at Henry Hub. But then, as suddenly as they had ebbed, prices began to flow. At time of writing, spot prices for natural gas are much higher than their 2007 average, and climbing.

To a surprising degree, these changes reflect global changes in the natural gas business. Historically, natural gas has been a regional business, and North America continues to be somewhat isolated from gas developments elsewhere in the world. According to CEO Robin Mann of AJM Petroleum Consultants, North American markets are presently somewhat isolated from the situation. However, he has no doubt that “gas is becoming a global commodity. Whether we like it or not, we are going to be caught up in it” – and, probably, sooner than you think.

The globalization of the world’s natural gas industry is being driven by a combination of economic and geopolitical forces. For example, consider the world’s second-largest gas-consuming region, Europe.

Geopolitics of change: Democracies around the world celebrated this decade’s revolutions in Eastern Europe. Serbia’s overthrow of its strongman in 2000 was quickly followed by the Orange Revolution in Ukraine and the Rose Revolution in Georgia. In each case the western world applauded.

Their biggest neighbour didn’t, though. Not known for its democratic credentials, the Russian bear responded to each revolution by clawing at the gas taps. It also apparently equipped saboteurs with explosives and sent them inside the country to destroy Georgia’s distribution link from the giant Russian gas monopoly, Gazprom. On instructions from Moscow, Gazprom even stopped deliveries to tiny Belarus for hesitating to “reunify” with Mother Russia. Belarusians had to quickly get used to being Russia’s 90th region.

These countries aren’t members of the European Union. However, expansion to 27 members has increased Europe’s dependence on Russian natural gas, so this pattern of behaviour has become a matter of deep concern. Now reliant on Gazprom for more than 60% of its gas supply, Europe is scrambling to find new sources.

Europe’s mad scramble is one driver behind the globalization of gas. Another is rapidly growing gas demand in the developing world – another trend with geopolitical overtones. The author of a best-selling book (A Thousand Barrels per Second) recently issued in Japanese and Chinese translations, ARC Financial’s Peter Tertzakian used China to illustrate the shift.

Coal and oil have played themselves out as easily harnessed and accessible fuels in that country, he says, and the country has to diversify into other fuels. “China’s pattern of energy usage is following the pattern of all other already industrialized countries. First you dam up all your rivers, then you move on to coal, then you start using oil as a booster rocket for the economy. Once you’ve done that, increasing your use of those fuels becomes unsustainable and you have to make a rapid shift to alternative energies – and the alternatives for China and other industrializing countries are natural gas and nuclear energy.”

Here, more geopolitical overtones enter the scene: The growing markets of East Asia and the nervous markets of Europe do not have a great deal of domestic gas supply. The planet’s greatest reserves are in the Middle East and the former Soviet Union – both of them diplomatically touchy regions. And most of the world’s other stranded supplies are in remote countries with access to the sea. These factors are helping drive a surprisingly rapid transformation of the global gas business.

A geophysicist by training, AJM’s Mann is bullish about the global gas market for the long-term. To a large extent this is because so much of the world’s gas potential is either undeveloped or stranded. This means a great deal is there to be developed for sale as LNG or, as in much of Southeast Asia, by subsea pipeline.

In terms of untapped potential, top of his list is West Africa. “We’re doing some work in Congo, where a few years ago you would be crazy to go, and that’s making me optimistic. There’s a chance that some West African governments will get their act together and stay true to their word, and if that happens that stretch of the continent could become a real hotbed of activity. There’s a lot of potential there.” However, he cautions, “we’ve been to this movie before. They could go back to their old ways, and this thing could blow up in their face.”

The biggest arbitrage: In Peter Tertzakian’s office is a meeting table with a single ornament in the centre: about the size of two fists, a wooden model of the globe. When you talk to him about the world gas business, he caresses this artefact, frequently turning it on its silent axis to demonstrate his points.

There are, of course, only two commercial ways to transport natural gas: by pipeline, and as LNG. Pipelines are being built with abandon, including vast networks of undersea lines that are, for example, connecting the vast Southeast Asian archipelago. For the most part, though, pipelines connect regions; they cannot connect the world.

For that, you need liquefied natural gas (LNG) – methane under such high pressures and deep cold that it forms into a liquid that can be shipped by tanker. To create a global market you also need a motive. Try this one on for size: “Natural gas,” says Tertzakian, “represents the biggest arbitrage opportunity in the world.”

Arbitrage is the practice of taking advantage of a price differential between two or more markets. A combination of matching deals that capitalize upon the imbalance, the difference between the market prices generates the profit. There isn’t much arbitrage opportunity in oil, because the global oil market is very efficient market, from hub to hub. There are lots of tankers on the seas, so arbitrage can easily be worked out. But for natural gas, which can sell in Chile and North Africa for as little as $1-2 per thousand cubic feet, arbitrage isn’t yet easy.

How do you get it from those sources to the high-priced markets of Europe and Japan and, increasingly, North America? The answer is LNG – although, says Robin Mann, “The major issue for LNG development seems to be in the development of liquefaction plants. They are expensive to build and two of them were recently cancelled. Increasingly right now we have regasification terminals that can receive (LNG) but we don’t have enough overseas exporters” to deliver production to overseas markets. That is changing. “The globalization of the gas business is happening much faster than I thought,” says Tertzakian, but he believes it’s a phenomenon Canada needs to embrace.

He lists a number of key reasons. For one, “every energy commodity today is under stress and tension, and the world is jockeying to figure out what energy mix they are going to use.” The competition for available energy is intense, and this is driving up prices worldwide. Contrary to the notion that “cheap LNG is going to come in and clobber us,” Tertzakian argues that LNG is the “friend” of North America’s gas producers. “It’s the most expensive molecule that sets the price,” he says, “not the cheapest molecule. That’s Economics 101.”

Another reason global gas markets have become so much more efficient is that LNG contracts have shifted from the old “port to port” model. A buyer can now redirect a shipment anywhere, and anywhere usually means to the customer willing to pay the highest price. Since the world’s LNG receiving terminals are underutilized, there is stiff competition for offshore supply. As a result – out comes the small wooden globe – “cargos have been shipped right around the world, from Trinidad all the way over here, to China. If (customers) are paying $15 in China or Japan but only $5 or $6 in the United States, East Asia is where the gas is going to go.” Only a few years ago, he says, no one could have predicted that.

LNG technology is changing quickly. New tankers are twice as big as they were in the past, so per unit transportation costs are coming down. Also, some tankers now have their own liquefaction facilities. Instead of receiving liquefied gas from an onshore plant, these tankers essentially just need a natural gas connection. Once connected to a pipe, they can liquefy the gas as they pump it into their holds.

The environmental advantages of gas are yet another compelling reason for countries to increase their use of the commodity. As things stand now, in developing Asia people are choking from diesel fumes and coal emissions. According to a World Bank study of Chinese pollution only 1% of China’s 560 million city dwellers breathe air the European Union considers safe. The resulting lung disease helps make natural gas a compelling fuel alternative.

Until recently, the world’s oil markets were efficient while the world’s gas markets were not. This is changing. “At the beginning of last year lots of gas tankers were coming to North America, (delivering up to four billion cubic feet (BCF) per day of LNG imports into the US), but by fall they were not,” says Tertzakian. Recently, LNG imports in the US were down to half a BCF per day.

The reason for this dramatic swing is that last summer LNG prices were more than twice as high in the US as in Europe, “so the tankers were all rushing over here. This is representative of the new era, which is one of the semi-globalization of the gas business. The big transatlantic price differences are being ironed out. It is also rather new. Companies like the UK’s BG Group have effectively globalized the industry. Gas is becoming much like oil.”

Although the Atlantic basin is the most advanced illustration of where the gas business is going, Tertzakian says, the Pacific basin is “getting there.” He twirls the globe: “These regions (China, India, the Middle East) have a trump card to play – natural gas – and they are playing it right now.”

Moving parts: For both geographic and political reasons – think NAFTA – North America is to a large extent a self-contained unit in the natural gas scene. But that is changing rapidly, and for many reasons. Among the gas bulls interviewed for this article there is a fascinating debate about whether Canada should consider joining the world’s small number of LNG exporters. This would only make sense, of course, if North America actually developed a surplus of natural gas, and Canada needed to build overseas markets.

“The Americans are trying to decouple from Canadian gas, but I don’t think they necessarily will,” says AJM’s Robin Mann. “The US is in better shape than they were five years ago. East Texas has had some big plays” and the States have been leaders in developing non-conventional resources like coal-bed methane (CBM) and shale gas. “Will this offset all the declines in the US? We don’t think so.”

Part of Mann’s thinking is that Canadian exports are bound to decline. “We need to add roughly 3.5 BCF (of daily productivity) each year just to maintain production. Based on our best guess about this year’s drilling in Western Canada, at the end of 2008 we are going to end up one BCF short. As we move forward to 2015, if all the oil sands projects go ahead, we will need an additional 2.5 BCF per day for oilsands use. Where is that going to come from? Exports to America. When you start adding all these things in, they are going to affect Canada’s exports.”

AJM’s geoscience vice president, Dave Russum, agrees. “CBM and shale gas development is sufficient to prop up American production rates to some degree, but it certainly doesn’t look as though it will grow the rates above current levels and we will in all likelihood see a decline in production in the United States.” The technology for this kind of development has greatly improved, but “the question is price. There is no shortage of gas in the US – the numbers are staggering. However, it is not cheap gas. The Barnett shale is an anomaly because of its location (near Dallas), for example, and despite all its advantages the margins there are pretty skimpy.”

Peter Tertzakian is the contrarian. “There are some yellow flags looming,” he says. “Production from the south-central United States (Texas, Oklahoma, Louisiana and Arkansas) is growing. If this production keeps growing, and it has already squeezed out LNG imports, what are the implications for Canada? A production surge in the US could potentially be a threat. The producers in Texas have much lower costs and much better netbacks; they are closer to the main (pipeline) arteries and they have bigger and more immediate markets.”

A constant theme of the interview with Tertzakian was his perception of the rapidly changing dynamics of the gas business. “There are a lot of moving parts. Everything is shifting. Compare today to only 18 months ago. Now we have the globalization of gas; a resurgence of gas production in the Lower 48; changing technology; changes in Canadian royalties and taxes; increases in demand in Western Canada, especially Alberta. Canadian production is falling off. LNG is being squeezed out. And we have to understand the productive potential of unconventional resources like CBM and shale gas. The gas industry has to be very mindful of all these things. We can’t just sit around and read the weather forecast to get an idea of how much we will be paid for our gas. We have to look around and figure out how we can be competitive.”

Mann acknowledges the competitive advantages of the American industry. “Pricing is higher there and costs are lower. You don’t have winter access problems, moving rigs and equipment around is simple, and the infrastructure is well developed. Also they don’t have the human capital problem that we have here – the Fort McMurray effect, which is driving up labour costs for everyone in the industry. In Canada operating costs for gas producers are going up (despite lower drilling day rates), and they aren’t going to come down.”

Tertzakian stresses that he sees a gas surplus in America as anything but a slam dunk. He sees it as a risk complicated by the fact that “right now we have all these pipes into one market. We only have one customer. That’s a dangerous thing, to only have one customer.” To protect Canadian interests, he suggests building an LNG export terminal in BC “so we are not hostage to a single customer.” He picks up the globe. “Look how close our west coast is to Korea.

As the interview ends, Tertzakian offers a final word of caution. “Generally I’m bullish (about the gas industry). But I think we in western Canada have to be very proactive in thinking about what all the changes mean. We need to be nimble, and we can’t afford just to be a price-taker. The Canadian sector has to work better with government to optimize the value of this resource. What sense would it make to produce this increasingly valuable resource and have it sold at lower prices in the United States if there were higher prices being paid around the world?”

The Silent Crash

This chart (click to enlarge; all graphics in this article at Carlo Magnifico's chartbook) illustrates how stocks began to underperform commodities as the recent commodity bull began. The methodology used here was to create a ratio by dividing the Dow Jones Industrial Average by the Reuters/Jefferies commodity index (the leading benchmark for commodities as an asset class). During commodity bear markets the Dow Jones Industrial average does well, while during commodity bulls it goes into the tank. The large symmetrical triangle has scary implications, explained below.

By Peter McKenzie-Brown

In real terms, in recent years the Dow Jones Industrial Average has been in a "stealth correction" - or, less generously, a silent crash. Growth in M3 money supply is now hidden, so it is not obvious that the US Fed is printing money at the astonishing (estimated) rate of 17% per year. One result is that, while in nominal terms the Dow has appeared fairly flat for the last couple of years, it has actually been in a tailspin.

It's dropping in euro, pound, yen, yuan and Canadian dollar terms, to name a few. More importantly, it is dropping in terms of real money (gold bullion) and other commodities - products from underground and from land and sea, the value of which is independent of the printing press. Since 2001, putting your money into traditional US equities has mostly been investing in a silent crash.

If you believe in technical indicators, that situation could get much worse. The chart explains this graphically. Technically speaking, its most important feature is that the two lines form a large symmetrical triangle. According to the massive classic on technical analysis, Edwards and Magee’s Technical Analysis of Stock Trends, roughly 75% of symmetrical triangles are continuation patterns – that is, they suggest a major turning point.

A breakout is a technical event in which a stock or commodity price “breaks out” above the high (or below the low) trading pattern lines that enclose other price points. Breakouts are used by technical analysts to predict substantial upside or downside movement. Think of them as a kind of tipping point. Critical mass creates unstoppable momentum.

Until we see a major breakout, in theory the chart could go either way. However, for the reasons this blog has been discussing for about a year, I believe the slight breakout we are now seeing is the beginning of a big drop. I have covered many of the causes – for example, dollar weakness, peak oil and its ties to gold prices, developments in the natural gas markets, Asian growth, financial crisis and so on – in earlier posts.

To understand the tremendous momentum behind the collapse in the Dow relative to commodities, you need to appreciate the strength of the commodity rally.

The chart above illustrates the power behind this commodity bull. The blue lines show the long, drawn-out collapse in commodity prices from 1980 to 2002. The red and green lines show a bull of tremendous virility – perhaps, if we can believe the recent breakout, one that is getting stronger still.

My last chart compares the performance of the Dow to those of proxy indexes for shares in oil (the XOI), natural gas (the XNG) and gold (the XAU). The strength is there. Like the commodities whose prices back up their profits, there is little sign of the commodity stocks slowing down.

Note: Donald Ross, a correspondent, offered an alternative interpretation to the symmetrical chart presented at the beginning of this post. He also sent comments which deserve to be quoted in full:

I don't think that you (really Carlo) are correct in drawing a Symmetrical Triangle here. From Edwards & Magee (regarding Triangles):

"'Remember that it takes two points to determine a line. The top boundary line of a price area cannot be drawn until two Minor trend tops have been definitely established, which means that prices must have moved up to and then down away from both far enough to leave the two peaks standing out clear and clean on the chart. A bottom boundary line, by the same token, cannot be drawn until two Minor trend bottoms have been definitely established.'

"Simply extending the Major trend line to form the bottom of a pattern would only be accurate if the reversals from the Minor tops reached down to, and reversed up again, at the trend line.

"I think that this chart is showing us a Descending Triangle, which is more often a bearish indicator than a Symmetrical Triangle. I've taken the liberty to draw on Carlo's chart. I'd like to know what you think. I must also point to the Edwards and Magee "caveat" at the end of the chapter on Triangles:

"'..., but the coarse, triangular patterns which can be found on graphs of monthly price ranges, especially the great, loose convergences which can take years to complete, had better be dismissed as without useful significance.'

"Your article, Peter, and Carlo's work, are extremely significant in my opinion. Ninety-five years of the un-Constitutional Fed's un-Constitutional activities have brought us to the end of the latest, and greatest, example of the fallacy of fiat currency."

Donald's interpretation of this chart, the descending triangle, is even more bearish than the symmetrical triangle discussed above. Here it is.

Biogas Fuelling the Olympic Torch?

By David DuByne

As I write these words, I am hearing from friends outside China about the Olympic Torch debacle – the torch getting received as if it were fuelled by human excrement. Here, within China itself, there is little news about it. Blogs (including this one) and other media are shut out by the Great Firewall of China.

Will the protests lead to a new world of human rights, with China taking a lead? Let’s get real. Will human excrement become a component of a fuel worthy to fire the torch that symbolizes national pride, friendly competition and peace? Perhaps, and in that area China could certainly lead the way.

China is playing a lead role in the area of biogas – processes by which we can turn our waste, animal waste and food waste into a high-end, useable commodity. The subject of using fecal matter as an energy source ranges from taboo in some societies to wide acceptance and utilization in others. In China, it fits into the latter category. Here’s what China’s National Development and Reform Commission has on the books for biogas.

In China alone there are nearly a billion and a half people with just as many livestock, poultry and garbage dumps all providing methane feedstock daily. It’s hard for China to sidestep the idea of turning something that was discarded into a commodity for electricity generation. China plans to have an installed capacity of bio-energy projects reaching 5.5 million kilowatts by 2010, but jumping to 30 million kilowatts by 2020, a 600 percent increase in 11 years.

Biogas is a combustible mixture of gases produced by micro-organisms when livestock manure and other biological wastes are allowed to ferment in the absence of air in closed containers. The major constituents of biogas are methane (60 percent), carbon dioxide (35 percent) and small amounts of water vapour, hydrogen sulphide, carbon monoxide and nitrogen. Biogas is mainly used as fuel, like natural gas, while the digested mixture of liquids and solids ‘bio-slurry’ and ‘bio-sludge’ are mainly used as organic fertilizer for crops. Chinese companies are now finding numerous other uses for biogas, bio-slurry and bio-sludge in China.

This development touches on an important aspect of Peak Oil: in a peak oil world there will be less fertilizer production and therefore higher fertilizer prices, which means higher farming costs that must be passed along as higher food prices. You could open Pandora’s Box when explaining how oil-dependent the farming, transport and processed food production industries are. Increased transportation costs to move food stuffs from field, to factory to your plate. Fertilizers and pesticides rely on natural gas- and oil-based chemicals for production, and farm machinery is run on liquid fossil fuels. The simplest equation is: Higher crude oil prices = Higher food costs.

China began using biogas digesters in earnest in 1958 in a campaign to exploit the multiple functions of biogas production, which solved the problem of the disposal of manure and improved hygiene. During the late 1970s and early 1980s the Chinese government realized the value of this natural resource in rural areas and this was the first important step in the modernization of its agriculture. Six million digesters were set up in China, which became the biogas capital of the world. The ‘China Dome’ digester is used to the present day, especially for small-scale domestic use. China’s 2003-2010 National Rural Biogas Construction Plan is to increase biogas-using households by a further 31 million to a total of 50 million, so the rate of use would reach 20% of total rural households.

By the end of 2006, the total number of families that use biogas reached 22 million, with a total annual biogas production of about 8.5 billion cubic metres and had built biogas pits for 22 million households in rural areas, and provided more than 5,200 large and mid-sized biogas projects based around livestock and poultry farms. The typical eight cubic metre biogas pits are able to provide 80 percent of the necessary cooking energy for a four-member family, according to The Energy and Zoology Division inside the Ministry of Agriculture. By 2020, about 300 million rural people will use biogas as their main fuel.

During the current, 10th, Five Year Plan, China is developing 2,200 grid power biogas engineering projects for wastes from intensive animal husbandry and poultry, treating more than 60 million tonnes of manure a year, that’s in addition to the 137,000 installed digesters to treat sewage. According to The Chinese Academy of Sciences and Geography, the total annual production of manure and night soil could theoretically generate about 130 billion cubic metres of methane, equivalent to 93 million tonnes of coal and 80 percent of industrial wastewater can also be used to produce methane. The number of large-scale grid power scale plants are planned to increase to 30,000 by 2030, a 15-fold increase.

As the idea of cleaning up the environment starts to take traction in China, dealing with sludge from urban and industrial wastewater treatment that has traditionally dumped into landfills, oceans and waterways is taking center stage with a catchy campaign “Recycle Waste into a Resource”. The Chinese central government is showing great interest in medium and large scale biogas plants and integrated agricultural and agro industrial biomass with waste handling plants to reduce water pollution.

To facilitate the usage of biogas the government had set up biogas technical training courses in Shanxi Province and in 2005 trained 6,000 farmers, 4,000 of which gained National Biogas Professional Technician Certificate. The Ministry of Agriculture which administers The Chengdu Biogas Scientific Research Institute (BIOMA) also operates an international training and research center in Chengdu, Sichuan Province. Farmers from Yunnan Province that graduated from the course are experimenting with a "four-in-one" biogas plant that incorporates a pigpen and a household latrine to provide feedstock, then uses methane to heat a greenhouse for growing vegetables and raises carbon dioxide within the greenhouse to boost plant yield.

Biogas feedstock programs throughout China are just beginning to utilize industry waste from other sources; alcohol production and paper mills. Tianguan Alcohol Factory, which consumes two million tonnes of shop-worn grains per year to produce denatured alcohol, is now recycling the dregs of the distiller to produce biogas in a 30,000 cubic metre digester, supplying more than 20,000 households or 20 percent of Nanyang city’s population.

Hongzhi Alcohol Corporation, located in Mianzhu, Sichuan Province is the largest alcohol factory in south-western China. It uses its industrial organic wastewater, sewage and dregs to produce biogas. The city of Mianzhu treats 98 percent of municipal sewage including wastewater from hospitals through digesters with a total capacity of 10,000 cubic metres.

Chenming Paper Co., which generates 300 tonnes of sludge a day, is adding its own start up biogas program using pulp wastes. The same goes for intensive animal husbandry on many large or medium size livestock and poultry farms in the suburbs of cities. China’s power generation is starting to morph into local energy generation for local residents from local industry using local feedstock, which is a model we should get used to in a world of high energy prices: Local production, local consumption.

As our globalized distant point of manufacture, long delivery chain lifestyle changes year upon year with declining crude oil availability, known as “Peak Oil”, we as a world will need to find crude oil substitutes to supply base chemicals for industrial and manufacture processes. Using biogas directly for cooking or co-generation of electricity and heat is especially feasible when the biogas is used at or near the site of generation. Biogas methane can also be used to make methanol, an organic solvent and an important chemical for producing formaldehyde, chloromethane, organic glass, and compound fibre. Good quality fertilizer and electricity generated are additional bonuses.

Finally, biogas can be used to prolong storage of fruit and grain. An atmosphere of methane and carbon dioxide inhibits metabolism, thereby reducing the formation of ethylene in fruits and grains prolonging storage time and the same atmosphere kills harmful insects, mould, and bacteria that cause diseases.

My mind’s eye sees a future where food storage will be in local communities as the Just-in-time delivery system will encounter problems as fuel becomes more expensive and disposable income worldwide is reduced. I envision a return to a bulk delivery system of dry goods which will be weekly or bi-weekly that will require local communities to store their own grain and bulk food utilizing biogas to keep pests and rodents out of the food supply. Tiny shipments as we are used to today will need to be restructured into a bulk delivery system, the concept of one box from one company half way around the world stocked on a store shelf should taper off with higher crude prices. Foods from supermarkets and hyper-marts packed in small individual boxes, bags or wrapped in plastic will have their own set of problems for delivery and manufacture to overcome. Which gives biogas an edge by offering solutions to two probable side effects in the future because of continuing upward crude prices, food storage and fertilizer.

What I never hear mentioned is a back-up fertilizer system. We are required by law in many countries to have back up batteries and generators for critical electrical systems in case of power failure. Is there a back-up fertilizer system in place for our food production in case of oil shortages or long-lasting supply disruptions? Biogas production may provide a bit of protection. It is hardly an Olympic step, but it’s a step.

David DuByne teaches business English in Chongqing, China while keeping an eye on energy, commodities and bio-fuel production in Asia. His website - Dave's ESL biofuel - is devoted to bio-fuel and oil depletion.

The Gas Storage Cycle

Chart #1: This chart compares the amount of natural gas in storage (usually underground reservoirs) in the lower 48 states, over time. The shaded area indicates the range between the historical minimum and maximum values for the weekly series from 2003 through 2007. The pattern is normal, of course. Like squirrels with their nuts, we store natural gas when it’s plentiful and consume it when we need it most.

By Peter McKenzie-Brown

Last fall, the amount of natural gas in storage in the United States set a new five-year record. Since then it has plummeted, and it has dropped more dramatically than at any other time in the last 15 years. The severity of the drop is obscured by the impact of Hurricane Katrina, which distorted the cycle several years ago. As my correspondent Paul Stallion explains,

looking at the numbers you will notice that this winter approximately 30 per cent more natural gas was drawn down from storage than for any other year in the past decade and a half. This fact is somewhat hidden in the chart of seasonal highs and lows, because usage nevertheless stayed within the 5-year average. What isn't mentioned is that the short-term (5-year) average itself is skewed by the hurricane which devastated New Orleans (which is also the reason gas in storage in the last few years could so easily remain so close to the top of that average). Chart #1 is therefore misleading, in terms of how dramatic the recent drawdown has been - which is why no one has yet mentioned it...

The chart also illustrates a key trend. Over three winters, there have been progressively lower supplies as the winter ended. This post suggests that this year less gas in storage is likely to combine with other factors to drive natural gas prices much, much higher than you might expect.

The volumes of gas in storage vary every year. During warm winters we consume less, for example, and during cold winters, more. Sometimes gas production surges, as it has in the south-central United States (Texas, Oklahoma, Louisiana and Arkansas) for the last few years. The combination of warmer winters in ‘06 and ‘07 plus growing supplies help explain the high storage levels of the last few years. The relatively mild summers of the last few years have been another factor. When it’s really hot, you use a lot of gas to generate electricity for air conditioning. Also, last summer liquefied natural gas (LNG) from overseas was cheap, and the US brought in large volumes by the tanker load for storage.

In the last six months, that situation has reversed. This winter was unusually cold in eastern North America, so we have consumed a lot more gas than usual. Also, prices for LNG are now much higher in Europe and East Asia than in the US, so that supply is going elsewhere: US imports have dropped from 4 billion cubic feet (BCF) per day last July to less than half a BCF today. And while the surge in south-central gas supply continues - mostly in Texas - production is in decline everywhere else in North America except Alaska, which isn't connected to any serious markets.

Now, turn your mind to the following chart. In my view, it says important things about the state of natural gas.

Chart #2: The purple line shows NYMEX natural gas prices during the last decade; the brown line shows the performance of the natural gas index (XNG) on the Amex. The XNG is a weighted share price index of the 15 largest players in the US gas business.

In the first half of the last decade, gas prices averaged perhaps $3.50 per thousand cubic feet. In the last five years, they have been around $7. A big increase, but compared to the price of oil, which has risen by a factor of five, not a big deal.

The odd part about chart #2 begins in the winter of 2002. Since that time natural gas prices have had lots of peaks and valleys, but the XNG has climbed steadily. My friend Carlo Magnifico, who provided the chart, puts it like this:

There’s been a steady accumulation of gas shares since 2002. The gas index has not had any really painful corrections like the price of gas has. It’s as though the price of gas doesn’t really factor into the price of gas stocks. Someone knows something. Gassy stocks are the place to be.

Last December this column anticipated the recent run-up in natural gas prices, and the balance of this article supports that call. We are now in a commodity bull market. During those cycles, commodity stocks rise while industrial stocks drop. In another article, I called this the great divergence.

Before I summarize the case for natural gas prices continuing to rise, a comment on one likely cause of this commodity bull. Harvard economics professor Jeffrey Frankel suggested in his blog that a decrease in real interest rates (“real” rates exclude inflation) increases the demand for storable commodities. In his thought-provoking comment, he writes,

If strong economic growth is not the explanation for the large increases since 2001 in prices of virtually all mineral and agricultural commodities, then what is? One wouldn’t want to try to reduce commodity markets to a single factor, nor to claim proof of any theory by a single data point. Nevertheless, the developments of the last six months provided added support for a theory I have long favored: real interest rates are an important determinant of real commodity prices. High interest rates reduce the demand for storable commodities, or increase the supply, through a variety of channels:

• by increasing the incentive for extraction today rather than tomorrow (think of the rates at which oil is pumped, gold mined, forests logged, or livestock herds culled)
• by decreasing firms’ desire to carry inventories (think of oil inventories held in tanks)
• by encouraging speculators to shift out of spot commodity contracts, and into treasury bills.

A decrease in real interest rates has the opposite effect, lowering the cost of carrying inventories, and raising commodity prices, as happened in the 1970s, and again during 2001-2004. It’s the original “carry trade.”

Professor Frankel makes clear that this is only one factor, but I think it's a point worth noting. Keeping that idea in mind, here is the case for a continuing bull market in natural gas prices. Such a market is probably the event that the steady upward performance of the XNG (Chart #2) is anticipating.

1. We are in a bull market for commodities (partly for the reasons Frankel suggested), and a rising tide raises all ships.

2. The gas industry must put enough gas in storage to meet demand next year, and the gas needed will be much greater than it was a year ago. As Chart #1 shows, volumes in storage are now well below last year’s volume, so demand will be much stronger. More to the point, this spreadsheet shows that this winter 30 per cent more natural gas was drawn down from storage than for any other year in the past decade and a half. As Paul Stallion's comments explained earlier, Hurricane Katrina's impact on supply obscures this statistic because it so dramatically dropped the bottom end of the 5-year average.

3. Gas production has been increasing in the south-central US. However, it is in decline elsewhere in the lower 48 states. Also, imports from Canada are unlikely ever to rise to the peak levels of a few years ago - partly because of declining production, but also because of greater domestic demand in Alberta and elsewhere.

4. Prices for LNG have more than doubled since last summer. Some countries are willing to pay $20 per thousand cubic feet, compared to the $9 and change that Americans now pay. This means we are far less likely to see low-cost LNG unloaded at American gasification terminals in the near future. Cargoes will continue to be redirected to higher price destinations, like East Asia.

5. The last factor to consider is the weather - to a large extent an imponderable, but something meteorologists are getting better at forecasting. The US National Weather Service predicts a hotter-than-normal summer this year. On a related note, the usually accurate Colorado State University forecast team "expects an above-average Atlantic hurricane season and may raise its prediction of 13 tropical storms and seven hurricanes when it updates its outlook" this week, according to Reuters.

Either of these factors could have an additional big impact on gas supply. High temperatures mean more need for air conditioning, and therefore more gas demand to fuel electrical generation. Hurricanes could mean shut-in production in the Gulf and in Texas and Louisiana.
Forecasting prices is a mug's game, and I will stay out of that. But I think natural gas prices are going way up from where they are today. To hedge against it, I put a little money here.

Note: Just two days after I wrote this came news of a major natural gas outage at the Independence Hub in the Gulf of Mexico. For several weeks, this will take one BCF per day out of production, worsening the situation described above.

The Great Divergence

By Peter McKenzie-Brown

Think of gold as a proxy for commodities – essentially metals, energy and forest and agricultural products. If you can buy that idea and you are heavily into equities outside the resource sectors, this chart should make you very nervous. It shows how much a single unit of the Dow Jones Industrials would cost in ounces of gold. Most recently, about 12 ounces would buy you one DJIA. By contrast, seven years ago you would have had to pay 41 ounces.

How useful is this information? In my view, it is something equity investors should take quite seriously. You will note that the chart begins at the exact tail end of the great commodity bull market of the 1970s, and the start of a 20-year commodity bear. By contrast, the huge downtrend since 2001 represents the beginning of a commodity bull which may put earlier markets to shame. For more on the bull in bullion, listen to this podcast of a conference call with investment analyst and best-selling author Don Coxe.

It seems to me that the chart is instructive for a number of reasons – the most important of which is to serve as a reminder that at the peak of the last commodity bull market, one ounce of gold would have bought you one unit of the Dow. Will we see the gold/DJIA ratio back to the levels of the 1980s – say, one DJIA for six ounces of gold or even fewer? Stay tuned. A doubling of the price of gold would do it, and the continued crumbling of the Dow would help. Some combination of rising commodity prices and declining share prices is likely.

There is support for this idea in an academic study conducted a few years ago by researchers from Yale and the University of Pennsylvania’s Wharton School. In a paper titled “Facts and Fantasies about Commodity Futures,” Wharton finance professor Gary Gorton and K. Geert Rouwenhorst, finance professor at the Yale School of Management, actually concluded that commodities are not as risky as stocks. Most important, commodities are “negatively correlated" with stocks and bonds, meaning their prices tend to rise when stock prices fall, and vice versa. That actually explains the huge divergences between gold and the Dow in the chart, which encompasses negatively correlated bear and bull markets in stocks and commodities.

Without putting too fine a point on it, the Gorton and Rouwenhorst report concluded that during the 45-year period they studied (1959-2004) you’d have made more money in commodities than in stocks, with less volatility and a better inflation hedge – even during a long period which covered alternating bull and bear markets. How well could you do if you were investing in commodities during a raging bull market like the one that exists today? Think about it.

Gold-Oil: I created the charts in this article with my friend Carlo Magnifico. He’s one of the more interesting technical analysts I know, and his home page is worth studying.

Here is our chart showing the gold/oil ratio. Basically, it suggests that, since the recent commodity bull began, an ounce of gold has been worth 8-14 barrels of oil. This ratio got wildly out of kilter after the 1986 oil price collapse, and stayed out of whack until oil supplies began to tighten at the beginning of the millennium. During commodity bulls, as illustrated here, the ratio tends to be much tighter. The chart suggests that at this writing gold is somewhat undervalued relative to oil.

As Carlo explains, “gold and oil both have real value and can’t be created out of thin air. There is always some sort of demand for both, and that demand is purely based on current supply, basically gold and oil are always at fair value against all paper currencies every day. So since gold and oil never change in value, they can be measured against each other.”

“If there is a major gold/oil divergence (disconnect),” he adds, “have a good look at the fundamentals. That will tip you off to opportunity.”


Gas-Oil: If you are an energy investor, this chart – the ratio of oil to natural gas prices – is more interesting still. Partly because oil and natural gas are both hydrocarbons and industrial consumers can often switch them for each other, a big price divergence means a correction will soon take place.

As this column pointed out last December, the decoupling of oil and gas could not last. I suggested then, and I still believe, that a natural gas squeeze is on. Check the chart. The dashed blue midline is a powerful magnet.

The Decoupling of Oil and Gas Prices

By Peter McKenzie-Brown

Energy forms are not created equal. Gasoline and diesel are great fuels for transportation, and at the moment there are few viable alternatives. Coal, on the other hand, is just dandy for generating electricity and smelting metals. Natural gas is terrific for space heating, powering electricity-generating turbines and manufacturing fertilizer and petrochemicals.

Because of their different applications and their different energy densities, hydrocarbons have different relative prices. And until recently, they were priced in a band which reflected their relative values. That band is now falling apart. Perhaps this is a sign of things to come - but not before the market experiences what commodity traders call a "short squeeze".

The chart shows the price of oil compared to that of natural gas in North America. Until recently, natural gas prices traded in a fairly close ratio to the price of oil. Depending on the state of the industry, the ratios formed a band which ranged from 10:1 to 6:1. Here’s a practical example of how helpful those ratios used to be.

Petroleum industry analysts make their estimates of the future price of petroleum stocks based on their future cash flow – that is, the amount of cash they will have available from production. If they wanted to estimate the future net worth of an oil producer, for example, they would make a knowledgeable assumption about the price of oil in the coming year and an estimate of the company’s total oil production for the coming year. A bit of fifth grade arithmetic then enabled them to estimate the value of that company’s shares.

To illustrate, let’s begin with four assumptions:

• First, the company under review will produce a million barrels of oil in the coming year.
• Second, the average price of a barrel of oil will be $25.
• Third the company’s cost of oil production will be $10 per barrel.
• Fourth, the company has 15 million shares outstanding.

Given these assumptions, the company’s cash flow for the coming year would be $15 million, and cash flow per share would be one dollar.

To get a good idea of the likely price of the stock in a year's time, we would then ask ourselves whether we thought oil stocks would be in a bull market then or a bear. If we were bearish, we would estimate the price at year end by multiplying that dollar of cash flow by three. If we were bullish, we would multiply it by five. So shares of the company in question would have an implied value of $3-$5.

What if the company’s production consisted of natural gas rather than oil? You can see on the chart that until recently, natural gas prices tracked the price of oil fairly closely – so much so that immutable ratios about the relative value of oil and gas seemed to exist. When gas prices were strong, a gas producer would only have to produce six times as much gas as oil (6,000 cubic feet of gas equals 1 barrel of oil) to be on equal terms with an oil producer. For example, to generate the same cash flow as the little oil producer I just described, in good times a gas producer would only have to produce 6 billion cubic feet of gas a year. If natural gas prices were relatively low, the company would have to produce perhaps ten times as much gas – 10 billion cubic feet per year – to have the same share price as our oil producer.

Eternal Verities: For many years these ratios seemed to be eternal verities for oil and gas producers. Then, last year, the verities fell apart. Oil and gas decoupled. In 2006 gas averaged less than $6, while oil was $65. The 10:1 ratio had been breached. And the situation today? Natural gas on the NYMEX is $7, while oil is $96. That’s a ratio of more than 13 to one. The once seemingly immutable ratios have collapsed, and the gaps are widening.

One outcome is that the shares of natural gas producers – especially Canadian gas producers – are in the toilet. The following chart of Rider Resources illustrates the disasters that befell investors in Canadian gas stocks during 2007.

What does all this mean? On a continent and in a world facing hydrocarbon-related energy and environmental problems, the cleanest and most efficient form of hydrocarbon energy has become the ugly stepsister compared to its less secure and much dirtier competitor, crude oil. This is not a happy state of affairs – especially since the North American gas industry is in decline. Forecasters now commonly suggest that Western Canada's conventional gas production has peaked and will continue to decline. In the United States, reserves peaked years ago.

The reasons are complex, but the practical reality is that the economics of gas production stink, especially in Canada. The $7 futures contract for gas on the NYMEX isn’t reality here. In Western Canada, our producers get $5-6 per thousand cubic feet for their gas, while the cost of finding and developing the stuff is in the $7-$9 range. Because of the strong Canadian dollar, a less attractive fiscal regime in Alberta, the lack of storage facilities and for other reasons, the Western Canada sedimentary basin is now the most expensive place in North America to find natural gas, and the least profitable in which to develop and produce it. This is the reversal of yet another verity. Until recently, Western Canada’s natural gas hunting grounds were among the most profitable and prolific in North America.

Greenhouse Gases: In a world nearing the crude oil peak, you would expect something like this to happen. The simple, cold logic of economics 101 implies that tightening oil supplies would send price signals which would identify the problem, spur crude oil exploration and make previously marginal resources profitable.

The irony, though, is that in North America these events are taking place to a large extent at the expense of natural gas – an energy resource that can be used to fuel vehicles, generate electricity and fire industrial boilers. As we approach Hubbert’s peak, we are neglecting development of one of the few viable alternatives available, and one which, compared to all other hydrocarbons, contributes less per energy unit of the greenhouse gases that appear to be warming our planet.

In a world where oil and gas prices have decoupled in this way, it may seem to make economic sense to bail out of gas producers like Rider Resources: Put your money into companies developing pollution-intensive resources like the oil sands.

If you subscribe to peak oil theory, and if gas is relatively plentiful while oil isn’t, then the decoupling I described makes sense and is a long-term trend. It also means – and this is a serious environmental problem – that a world desperate for energy will focus investment on oil and coal (environmentally unfriendly) rather than gas (environmentally friendly.)

Medium Term: I believe this is probable over the medium term, at least, because of the growing importance of liquefied natural gas (shipped by boat from plentiful overseas reserves) in world trade. LNG will help keep North American gas prices relatively depressed, since it can be landed in the US for as little as $4-5 per thousand cubic feet. If that trade continues to grow, then the decoupling will continue.

However, nothing moves in a straight line, and there is a strong case to be made for rapid upward adjustments in gas prices. Perhaps the ratio of gas and oil prices will soon revert back toward the mean - either because oil prices drop or (in my view more likely) gas prices climb. As the above chart of the natural gas exchange-traded fund (ETF) shows, US natural gas stocks may have just about hit bottom. From an investment point of view, if natural gas prices are about to rise and you can anticipate when they will begin to make this move. You could make a lot of money by buying companies like Rider Resources (I personally do not own this stock) rather than avoiding them.

Evidence that such a situation may be upon us can be found in this chart, which shows net positions in natural gas contracts. The net long positions held by the commercials and small speculators are so extreme that they suggest that a "short squeeze" could be in the offing.

A short squeeze occurs when short sellers start to feel pressure from a rising stock or commodity - natural gas, in this case. Their losses increase as prices move higher. This "squeeze" places pressure on those holding short positions by forcing them to buy back their bearish positions in order to limit their losses. Short squeezes often result in dramatic price gains over relatively small periods of time due to this spike of buying pressure.

If that's what's happening here, the commercial buyers (who tend to win over the long term because they better understand the market) and the small speculators seem ready to cream the large speculators. Stay tuned: This could be more fun than the Grand Ole Opry.