Revolution Repeated

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

By Peter McKenzie-Brown

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Getting More for Less

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

By Peter McKenzie-Brown
North America’s natural gas business is going through fundamental change, but Alberta’s conventional gas sector isn’t well positioned to compete. As Canadian Natural Resources' president Steve Laut told a conference call when he was discussing his company’s deep cuts in capital spending for 2009. “We are drilling (for gas) in B.C. but cutting back in Alberta.

The oilsands can withstand (Alberta’s) higher royalties, and on the oil side, the government got it right, but they missed it on gas. Alberta is the worst place for gas development in North America, and likely the world.” Why are things so bad? Part of the problem is the province’s much-maligned new royalty regime, which sapped the industry’s motivation to invest in the province’s traditional source of supply, conventional gas. In November the province gave explorers the option to pay royalties at the old rate for four years, provided the wells were more than 1,000 metres deep and spudded after the New Year.

This eleventh-hour tinkering “will have an improvement on activity levels in the province,” according to Tristone Capital vice president Cristina Lopez, “but it will not improve the cash flow outlook for companies that are going into a difficult commodity-price environment.” That’s a major reason for the decline in conventional exploration and development. “There’s been a tendency to assume that as long as we have gas opportunities in Alberta, people will come here to invest their money to get it out,” said Dave Russum, who is head of geosciences at AJM Petroleum Consulting. “We should not automatically assume that will be the case. When you change the royalty system and make other such changes, then investors will go to other opportunities where they have other advantages – closer to markets, or where there’s a better royalty regime or a lower cost structure.”

He notes that until this year there has been an absolute correlation between wells drilled and gas prices: When prices went up, so did the number of wells. This year, prices went up but drilling in Alberta went down. Was this an unintended consequence of Alberta’s new royalty regime? Probably, but other economic factors are also at play. Geological targets are changing; costs and prices are fluctuating for reasons that have nothing to do with natural gas activity levels (think oilsands); new technologies are fundamentally changing the economics of development; and issues related to environmentally responsive, full-cost accounting are playing an increasingly important role in project approvals.

A Fourth Amigo...Again
Three Western countries – Norway, Canada and the Netherlands – are now self-sufficient in natural gas (the UK was among them until four years ago). Soon, another country could join that small but lucky band. If you were to hazard a guess, which country do you think might join that group? That country, whose conventional gas production peaked in 1972, began focusing on unconventional natural gas in the 1980s.

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

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

The cost of developing and delivering Western Canada’s gas varies greatly from region to region, but the WCSB is still one of the world’s most expensive onshore basins to develop. A recently released National Energy Board map illustrated the geographical diversity in cost related to developing and producing these gas supplies. The average cost of gas supplies ranges from $11.18 per thousand cubic feet in the BC Foothills to $6.58 per thousand in the adjacent Alberta Deep Basin. For gas producers and analysts, the critical factor in the NEB analysis was that gas prices need to average $7.88 per thousand cubic feet for producers to generate a risked after-tax rate of return of 15% in this basin.

 Given an average Alberta spot price for natural gas around $6 during 2007, the report intoned, “the average economics for new gas development in western Canada were marginal.... These results are consistent with the general impressions expressed by industry players about the tight economics of new gas....”

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

 Even though unconventional gas is more expensive to develop than conventional production, that’s where about 60% of natural gas activity is going. Like the US, which made great progress developing unconventional gas during an era of lower prices, Western Canada is developing these resources in a period of price/cost disequilibrium – that is, lower prices and higher costs.

This is counterintuitive. In classical economics, adversity in the gas industry – the lower margins and riskier business environment of the last few years, for example – would force the industry to drive down costs and increase efficiency. The U of C’s Mansell squelched that assumption, first zeroing in on the dynamic relationship between price and cost. “Costs drive prices,” he said, “but prices also drive costs.” Supply costs go up and down depending on activity levels, rig and services availability, materials, labour, technology, changes in well productivity, changing drilling targets, and changing fiscal and tax regimes.

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

Technology
While companies employ cost-cutting measures (shutting in higher-cost gas supplies during tough times, for example), Mansell makes the case that real efficiencies are more likely to arise in periods of relative prosperity than in periods of economic adversity. “In a tight margin environment, would companies put more R&D and technology into increasing efficiency? It’s not clear. They actually have more free cash to play with in a higher price environment (and are therefore in a better position to increase efficiency). However, if a company is financially healthy, it can even increase profits in a low-cost environment by applying new technologies.” In other words, greater efficiency in the petroleum sector comes mostly from technology –improved drilling, seismic and other technologies used in exploration and development – along with the obvious benefits of such capital infrastructure as plant and pipeline.

According to Mansell, “It’s a dynamic environment. Mostly because of better know-how, over longer periods of time the industry is getting 1.5% to 2% more output per unit of input each year.” How is that happening? AJM’s Dave Russum puts a technical slant on things. “Per well costs are higher than in the past, that’s true. However, we now understand that in certain kinds of gas resources we can greatly increase productivity by increasing drilling density in lower-quality gas reserves. You need to be able to fracture the maximum amount of the reservoir.” So important has this trend become that it is contributing directly to the reduced number of wells being drilled in Canada. This year, nearly 40% of the wells drilled in Canada will involve horizontal or directional drilling – twice the level of ten years ago.

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

As the U of C’s Mansell points out, “Current costs may not reflect future costs. As you learn more about the resource, costs could come down substantially – not only the cost of production, but also the cost of finding new reserves.” Recent innovations in fracking wells illustrate how this can happen. Companies have made great strides in increasing the number of fracks they can make in a single horizontal well. Horizontal wells drilled into shale reservoirs now average eight fracks each – an astonishing improvement from only ten years ago, but one that is causing potential bottlenecks in the system.

According to Kevin Lo of FirstEnergy Capital, to fracture just one of the Horn River shale gas wells in north-eastern BC, you need a fracturing crew equipped with more than 30,000 horsepower of compression. To put that in perspective, in Western Canada perhaps 800,000 horsepower is available. “We do not believe that there will be sufficient capacity to perform all of the jobs necessary, should (BC’s Horn River and Montney shale gas) plays grow,” he said in a research note. He also worried about the logistics of bringing in enough propping agent: fracturing a single horizontal well in these reservoirs can require up to two thousand tonnes of sand.

Stewardship
Another area where big changes are happening, of course, is in environmental practice and policy. Take the case of EnCana’s application to drill in the Suffield National Wildlife Area, where a hearing began last September. The gas at Suffield is shallow, biogenically-derived gas in mixed sand and shale sequences. Since it is not generated in the same temperature and pressure systems that create conventional hydrocarbons, shallow biogenic gas is an unconventional variety. The Milk River and Medicine Hat sands of south-eastern Alberta and south-western Saskatchewan are classic examples of this type of unconventional gas. This was the first gas produced in western Canada. It is continuously gas-producing, and it is the largest gas-producing region in the WCSB.

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

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

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

The issues are complex, and the ERCB has a long history of listening carefully to all sides and dealing with these situations fairly. However, this is only right. As the U of C’s Mansell explains, economic theory supports the environmentalists’ point of view. “In theory,” he says, “you want to be as close as possible to full-cost and-full benefit accounting from a social point of view. Policy decisions should incorporate all incremental benefits and the incremental costs – including costs and benefits that don’t necessarily show up in the market. How you estimate that isn’t an easy question to answer, but your accounting should be based on a benefit-cost analysis.”

Since a poll by the provincial government found that only 16% of Albertans believe the province does a good job of looking after the environment, this story has legs. So there you have it. Alberta may be “the worst place for gas development in North America.” However, the WCSB remains an important gas basin, and activity throughout the region is helping illustrate gathering industrial trends. On the policy side, issues related to full-cost accounting will likely take years to iron out – but at least they are being heard.

Damage Control

Gasoline and other fuel prices are subsidized in the three representative oil-producing countries graphed on the top right - to the point that gasoline costs $0.12 per gallon in Caracas.

Compare the growth in oil consumption in those countries to growth for the world as a whole. Did you notice a pattern?

By Peter McKenzie-Brown

The world has two kinds of energy-consuming jurisdictions: Those which respond to high oil prices, and those which don’t. In this post, I want to help define which is which. I also want to offer a few explanations why dramatic increases in energy prices have not yet damaged the world economy. These are intimately related issues.

I recently had an interview with Marcel Coutu, the chair of Syncrude – the world’s largest oil sands plant. Syncrude has been in operation for 30 years, and it has gone through a great deal of debottlenecking and expansion. It now produces 350,000 barrels of light, synthetic oil per day.

I asked Marcel for his thoughts on peak oil, and he gave me a few comments that summarize things precisely.

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.

He didn’t seem to think this was a major global problem, and I wish I had asked why not.

Three Theories: Historically, rapid increases in oil prices have led to global recession. This certainly applies to the stagflation that influenced the decade after the energy crisis of 1973. The terrible recession of 1982 was without doubt related to the energy crisis of 1979-80. And the long, gradual boom that began in ’83 was closely tied to declining oil prices, and accelerated by their collapse in 1986.

What I think we need to ask ourselves is why high oil prices don’t seem to be doing a lot of damage to the global economy. According to The Economist, there are three possible explanations.

An important and interesting idea is that high oil prices are not hurting the economy simply because they themselves are the result of rapid economic growth around the world. “Rather than oil harming the global economy, it is global expansion that is driving up the price of oil” says the world's great champion of liberalism.

Another explanation is that developed economies are more efficient in their use of energy, thanks partly to the increased importance of service industries and the diminished role of manufacturing. For example, the EIA has calculated that the energy intensity of America's GDP fell by 42% between 1980 and 2007.

A third notion is that the oil price rise has been steady, not sudden. This has given the economy time to adjust. The Economist writes, “Giovanni Serio of Goldman Sachs points out that in 1973 there was a severe supply shock because of the oil embargo, when the world had to cope with 10-15% less crude almost overnight. Not this time.” It’s worth adding that during 1979-80, the percentage increases in oil prices were not as great as they were in the early 1970s, but in absolute terms those increases were greater by far.

The Role of Emerging Economies: As Marcel Coutu explained at the beginning of this article, the most important factor for higher prices has been the shift toward greater consumption by developing economies.

The US, for example, has responded to high prices by cutting consumption slightly. According to one source, the decline will be 1.1% this year, such that American consumption next year will be no higher than it was in 2004. Given such a niggardly response, growing demand from China and other emerging markets will be more than enough to offset this shortfall. With supply growth slight to neutral, the steady increase in demand is hauling prices remorselessly higher. It would take a recession in emerging markets to drive commodity prices substantially lower, and to date recession in those economies is not in the cards.

A couple of points deserve comment here. One is that the achievements of Western nations in reducing energy intensity are nothing compared to the achievements of China. According to an excellent paper on China’s energy consumption and demand , since 1980 China’s energy intensity has dropped by about 75% – nearly twice the drop in the US. The reason is that in every way the world's next superpower has become far more efficient.

Of course, I am raising this point because it suggests a very deep irony: Exporting the world’s manufacturing sector to developing countries has not only enabled the West to become a more efficient energy consumer. It has also helped those countries to become more efficient. Don’t blame the Chinese, in other words: They are doing a far better job at using the world’s resources efficiently than the West can even imagine.

Final Thoughts: These ideas, too, hark back to Marcel Coutu’s earlier comments. By subsidizing energy consumption within oil exporting countries, the world is contributing to inefficient energy consumption. Some of the cheapest gasoline prices in the world are in Saudi Arabia, Kuwait and Venezuela – the last being the all-out winner, with gasoline selling for $0.12 per gallon. The economies of these countries are not known for their gathering efficiency, yet the charts illustrate how much more dramatically oil consumption accelerates when prices are subsidized than when they are not.

The plain truth is that energy importers are subsidizing the inefficient consumption of oil in these countries because of the geographical reality that they have oil to export. Yet the countries we are most anxious about - China and India, for example - are the ones that are increasing their energy consumption not because of large subsidies, but because they are able to provide goods and services with greater energy efficiency than the rest of us.

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.

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.

India Beckons

This article appears in the April 2008 issue of Oilweek; image from this site.

By Peter McKenzie-Brown

With the head of an elephant and the body of a man, Ganesh is one of the most revered deities in the Hindu pantheon, and certainly the most easily recognizable. Ganesh is the patron of arts and sciences; the god of intellect and wisdom; the remover of obstacles; the propitiator of business.

On one of the coldest days of winter, Ganesh seemed to arrive in Calgary, offering to remove obstacles for companies prepared to help unlock India’s petroleum wealth. The occasion was a travelling road show hosted by the government of India and advertised under the bureaucratic name NELP VII.

For the E&P sector, the prizes on offer are huge: 57 blocks of land in highly prospective but poorly explored sedimentary basins. As the presenters quickly made clear, the financial rewards can be high, and the geological and geopolitical risks are low. There are also excellent opportunities for the service sector.

NELP stands for New Exploration Licensing Policy, and it reflects the reform and liberalization of the country’s economy – a process which began in the early 1990s and has gathered steam ever since. Under the policy, which went into effect in early 1999, the government has held six rounds of bids, awarding 162 production sharing contracts. As a result, the country’s petroleum industry has grown from two companies producing from three basins in 1990 to 49 companies producing from ten basins today. There are 26 basins in the country in total, only 15 of which have been explored. India’s sedimentary basins (more than half of them offshore) total more than 3 million square kilometres in area.

The seventh round of NELP will likely be the most successful yet. On April 11, companies from around the world will submit bids on 57 exploration blocks – 19 in deep water, nine in shallow water and 29 onshore. Whether from government or industry and whether Indian or foreign, all of the road show’s speakers agreed that the bids will be evaluated through a transparent, competitive process with single-window clearance.

According to Les Kondratoff, whose Canoro Resources was successful in the last round of bidding, “going to India today is like coming to Alberta was in the 1940s” (because of the low drilling density). “Why wouldn’t you go there?” he asks. “The risk is lowest.” He points to his company’s Amguri field on a 53-square-kilometre exploration block. He believes it may be a 70 million barrel field. “In Canada, we’d be popping Champagne with that big a field. In India, big discoveries are not too uncommon.”

Indeed, according to information provided by the irrepressible V.K. Sibal, director general of India’s Directorate of Hydrocarbons, Indian gas reserves are growing more quickly – 6 per cent a year during the last seven years – than in any other part of the world. Because of the huge market in India, he stresses the potential for monetizing gas discoveries within India. “Our vision is that we can take gas from everywhere (in India) to anywhere, from anywhere to everywhere.”

Calgary-based NIKO Resources has been the greatest Canadian success story in India. Since the company was awarded exploration blocks in 1999, its stock has risen from $3 per share to a peak above $100, and one of its biggest Indian successes is yet to come on stream. The company and its partner, Reliance Industries, plan to bring a deepwater gas field on stream this coming June; production is expected to peak at 80 million cubic metres (2.8 billion cubic feet) per day.

You have to be a bit cautious when looking at the numbers which the Hydrocarbon Directorate’s Sibal uses in his presentations. The country’s “prognosticated resources” in the 15 basins explored to date, he says, are 205 billion barrels of oil and equivalent. Of those, 66 billion barrels have been identified as “in place reserves,” including 15 billion barrels discovered in the last seven years. However, pending further evaluation and appraisals, so far his directorate has only assigned 4.73 billion barrels of in-place reserves to this century’s 49 Indian discoveries.

Sibal offers compelling exploration numbers. During the first nine months of the 2007-2008 reporting year (it ends in March), the industry drilled 35 exploration wells in poorly explored basins and came up with 17 discoveries. In the previous three years, the success rate for discovery was an excellent though less eye-popping 18 per cent.

Resources Needed, and Available: Speaker after speaker at the NELP conference raved about the opportunities India presents. However, in addition to the obvious opportunity offered to the E&P sector, there was an undercurrent of opportunity for the service sector. Although there are already many service providers in India – international companies like Weatherford International and domestic ones like Jindal Drilling – opportunities for the service sector are clearly outstanding.

Getting the equipment and services needed to explore and develop are slowing down the country’s exploration effort. According to Jindal Drilling’s Naresh Khumar, “There is a huge demand for all kinds of services. Companies are asking for drilling holidays because they cannot get rigs to drill.” From cementing to wireline to workover services, from marine logistics to jack-up rigs, the situation in India is dire.

Frankly, this explains India’s highly attractive NELP energy policy. The country expects demand for both oil and gas to more than double by 2025, leaving huge gaps between consumption and domestic supply despite large anticipated increases in production. National security and trade balances make this problem paramount. The country is anxious to develop a world-class petroleum industry, with much greater capacity in the areas of service and supply.

Weatherford Tools’ David Reed – his company (a US-based international oilfield service provider) is growing rapidly in India – is impressed with the “ease of entry, access and equity” which players encounter there. It is “at the top of the scale” as a country to work in, yet “standards for service providers are very high. There are no compromises in India.” He is also smitten with the people. “There is a tremendous skill-set in India, and you would be crazy not to leverage that for your business.”

The skill-set Reed is referring to represents one of India’s many paradoxes. While 40 per cent of Indians are illiterate, the country has the world’s second-largest pool of trained scientists and engineers. Those skilled masses enable India to develop more computer software than any other nation in the world – worth $22 billion last year in export income.

Doing Business in India: The story barely begins with the skilled workforce. Now firing on all cylinders, at 9.4% last year India’s economic growth rivals that of China. Since 1991, when the country began its program of economic reform, annual growth has averaged 8%.

India speaks 23 major languages and 22,000 distinct dialects but, stresses Canoro’s Les Kondratoff, “the language of business is English.” India boasts the 12th largest economy in the world – $1 trillion last year, with net exports of $127 billion. The country has large and diversified infrastructure, including 15 international airports and 449 domestic ones.

Indians practice many religions. Hindu is the most important, but the country also has the world’s second largest Muslim population. Despite inevitable tensions, the great diversity of Indian people is held together by the largest and noisiest democracy on the planet.

India’s use of British-style common law means contracts signed in India are honoured. According to the Hydrocarbon Directorate’s Sibal, “production sharing contracts are sacrosanct to us.” He cites “attractive, competitive and transparent bidding terms,” a positive climate for investment, efficient infrastructure, expanding domestic oil and gas markets, higher returns and lower risk than in other developing countries. He then throws out a challenge: “Compare us to the world’s best. We come out on top.”

One India hand is Don Whelan, who went there in 1996 with the late Bill Olsen, the founder of NIKO Resources.

A real fan of the small company in India, Whelan is now creating a Mumbai-based petroleum service company called Today’s Petrotech. “Little companies, as NIKO was when we went there, are more adaptable,” he says. “The first two years were a real learning curve. After we got over that hump, it became easier and easier. Now it seems like second nature.” He warns, though, that the Indian demand for paperwork sometimes seems endless.

Having married since moving to India, Whelan has no intentions of returning to Canada. For him, the expat life in Mumbai is just fine. “Our maid, our driver, our gardener – their wages are about $100 per month each.” He worries, though, that Mumbai’s infrastructure isn’t keeping up with changing times. The streets are increasingly gridlocked, and that is going to get worse in the fall when Indian automaker Tata Motors begins selling its long-awaited People’s Car, with a sticker price of about $2,500.

Amarjeet Singh, a KPMG partner, is headquartered near New Delhi. He says the comparisons between investing in India versus investing in China favour India every time. “If you just look at the experience of all big multinationals going to China, most of them will vouch that they are still struggling to make money. In India there are many roadblocks, but if you are doing your business properly, if you understand the market, if you adapt yourself to Indian conditions and frame of mind you will make as much money as a domestic player.” But he cautions that “you have to have a long-term view. If you have a long-term view you will always make money.”

Singh recommends that entry-level players in India “outsource all of the functions – accounting, administration, all of those things. Those are not your core business.” Singh admits that taxation in India is complex, but says “it’s complex in Canada, too. If you plan well, if you handle it well, taxation is not a roadblock to doing business in India.”

According to Singh, “The fiscal regime which is applicable to exploration in India is at least as aggressive as in any other part of the world. There are tax holidays, you are permitted to set off losses in one block against income in another, you can aggregate all your expenses against aggregated production and so on. The government has carved off benefits for the E&P industry that are far above those in other countries and other industries in India. And once you have a production sharing contract, you can operate any way you want.”

Canoro’s Les Kondratoff echoes those sentiments. “Projects aren’t ring-fenced and there’s a seven-year tax holiday from the time you begin commercial production. Royalties are low and you are entitled to full-cost recovery.” He adds that there is enormous demand for bottled propane, and refineries want ever more crude. There are opportunities all around to monetize petroleum assets.

His company had a devastating experience in Russia. Canoro’s Russian partners, he says, abrogated contracts. Canoro had no viable recourse before Russian courts, so Kondratoff particularly appreciates India’s long experience with common law. India, he says, “has all the ingredients for success.”

Ganesh-like, NELP seems to be removing obstacles to that success. The next step is the bidding, and the journey is to unlock India’s considerable petroleum wealth. For those who miss out on NELP VII there will be other rounds, and India will remain an investment destination.

Can Less Oil Consumption in the West Lead to Lower Global Demand?

By Peter McKenzie-Brown Until recently, there has been a constant refrain to the effect that Western economies seem undeterred by higher oil prices. Demand destruction does not seem to be taking place within OECD, even at today’s high numbers. The gist of the argument is that, compared to the situation in the 1970s, for example, oil is such a small part of GDP that the impact of energy prices is almost negligible. A lot of industrial demand destruction took place during previous periods of high prices, in the 1970s and 1980s. More recently, it has been taking place through the outsourcing to emerging economies of oil-intensive manufacturing. The chart shows that in transport, where fuel costs are almost everything, these notions do not apply. The ratio of the Dow Transports to the price of oil, which you calculate by simple division, illustrates how profoundly the lowest oil prices of recent years (1997-1999) helped boost such transportation industries as railways, airlines, trucking and shipping. It also shows how negatively higher prices have affected transportation shares in the years since. Here is the same chart in less abstract form, displayed in terms of its two constituents. In this chart and the one above, the RSI (relative strength index) and MACD indicators apply to the transport index. Click on the charts to see them full size, or click here for updates on the charts used in this article. There is nothing particularly profound in pointing out that the transportation industries are strongly affected by higher oil prices. To use air travel as the most obvious example, fuel represents something in the order of 60% of its operating costs. To what extent is that affecting other parts of the economy? High energy costs are causing industry outside the transportation sector to find ways to cut per unit energy costs, and that is significant. Also, North Americans are buying more energy-efficient vehicles, but so far that has been more a trickle than a flood. However, this chart suggests what I think may be a coming sea change in North America’s energy consumption behaviour. Before you read my interpretation of this graphic, see whether you can figure out why. NYMEX gasoline futures have only been traded for four years. Since data is so limited, we have to be careful how we interpret this chart, which shows wholesale gasoline and oil price changes, and also indicates (vertical blue lines) America's driving season. When I look at this chart three things seem obvious. The first is that gasoline prices peak during the American driving season. That makes sense, since the summer months are the period of peak demand. My second observation is that peak gasoline prices during the driving season are higher than the relative changes in the price of oil by a considerable margin. The third is that wholesale prices are reaching new highs well ahead of the driving season this year, reflecting much higher crude prices. To my mind, all this suggests a steep spike in gas prices coming, and a change in the recent dynamics of crude oil's crack spread. We Canadians, who buy gasoline in litres, pay the equivalent of about $4.50 per gallon out of smaller per capita incomes. Even at those prices, we are paying barely half of most European prices. But our American neighbors are complaining about pain at the gas pumps with gasoline below four bucks a gallon. Will much higher gasoline prices this year finally cause them to begin changing their driving habits? I should think so. Perhaps, like Canadians, they will finally begin driving smaller, more fuel-efficient cars, drive less and so on. If so, that would be a good thing, and it would lead to continued crude oil demand destruction, although on a small scale. There is solid evidence for this in a number of areas. US gasoline inventories are at their highest levels since 1993, for example, and gasoline demand is trailing last year's level. (However distillate fuel inventories - diesel and heating oil - are lower than last year, especially in the Northeastern US market.) Will these developments lead to global demand destruction? Not according to an excellent commentary from Paul Hodges. Hodges acknowledges that demand in OECD countries is flat to declining. "The major influence is the weather. This year is seeing a mild winter, so demand will probably be down around 1mbd (million barrels per day)." However, he says, demand outside OECD is growing at around 1.6 million barrels per day per year.

This is focused on China (390 thousand barrels per day growth in 2008), Saudi Arabia (150 kbpd), other Middle East (330 kbpd) and India (140 kbpd). The common characteristic of all these areas is a relatively young population, growing incomes, and heavily subsidised oil product prices. There seems little chance of any of these factors changing in the next few years. Governments do not want to stir up social unrest by increasing domestic prices, and have no pressing need to do so as they all have healthy fiscal positions. 2008 is also likely to see a particular boost in China in the use of transportation fuels, due to the Olympics.

Efficient Markets? How Noise Drives Prices

By Peter McKenzie-Brown This week was remarkable. It began with the Americans twisting Saudi arms so they would increase oil production. Nervous that there might be spigots that could actually be opened, oil prices dropped off their lofty levels. Then a decline on global stock markets was greatly exacerbated by the squeeze forced on France’s Société Générale by a rogue trader.

The Martin Luther King holiday market closures compromised an orderly unwinding of those futures contracts, and the decline in the markets turned into a meltdown. Not knowing that the actions of a 31-year-old rogue had precipitated the collapse, the Fed’s Ben Bernanke flooded the world with cash by precipitously slashing key US interest rates. The markets were also flooded with rumours of a severe US recession impending – one that would take the world with it. Fearing a crash in demand, the price of West Texas Intermediate briefly dropped to its lowest level in three months. Then reality began to intrude: the Saudis don’t have a lot more oil they can produce, and geopolitics, rising demand and historically tight supply still govern the price of oil.

The chart illustrates two things. First, it shows the trading range of oil (the space between the red and green lines) during the last six years. Second, it shows an extended breach in that trading range – essentially, three months of trades above the red line. What used to be resistance has now become support. I consider it highly significant that oil prices popped up after touching their three-month low.

In the future, oil is likely to trade above the red line. One of the great things about technical analysis of this kind is that it is a way of imposing order (straight lines) on a market riven by noise (jagged lines.) However, technical analysis is not an excuse for not understanding what decisions help form the jagged lines of day-to-day trading. Oil prices are governed by a highly sophisticated market – one that can quickly balance innumerable pricing factors to establish appropriate prices for oil, but so doing creates endless charts of jagged lines. Herein I present my perception of how that market developed and of the major factors influencing it. As a Canuck, I will deal with the matter from a Canadian perspective.

The Background: As oil became a vital factor in western life during the twentieth century, exploration for the stuff – a new industry – found more than the world could consume. In response, big companies set prices for the oil they controlled overseas, while governments and regulators in the US helped create a parallel environment in which America’s huge domestic oil industry could prosper from higher prices. By 1970, these different policies had created a global pricing environment in which oil produced in the United States cost $3.18 (U.S.), while oil produced overseas only fetched $1.30 (U.S.)

This situation received a severe blow in 1973 when OPEC began to act as a cartel – an organization committed to keeping prices higher than the market would ordinarily allow. They were so successful that OPEC’s member states made price control the organization’s primary purpose, and for more than a decade a statement from OPEC was enough to give world energy markets the jitters. The energy crises of the period were possible because the world was no longer awash with oil. In particular, production in the United States (then the world’s largest producer) had begun to decline.

The Western world needed new supplies, and the volumes required were only available from OPEC members. This period culminated with the Iranian Revolution of 1979-80, which brought panic to oil markets. Dubai oil prices rose from about $2.00 (U.S.) per barrel in 1972 to $36 (U.S.) in 1980. All this was far more traumatic a generation ago than the rapid oil price increases of the last ten years. The reason is that – at least, in relative terms – oil then played a much larger role in the world economy.

Spot and Futures Prices: The market responded dramatically, and predictably, to these painful price increases. Consumers used less oil while producers pumped more. OPEC soon lost the ability to keep prices high. Then, in 1986, Saudi Arabia, an OPEC leader, flooded the market with oil in an effort to re-establish market share. As a result, prices plunged. Dubai oil dropped to $13, and fluctuated around that level for more than a decade. It did not move decisively upward again until 2000, when tight oil supplies began to squeeze prices higher. Aided by the convergence of computer and telecommunication technology and by increasing competition among global oil producers, the world’s response to these three “price shocks” – the price spikes of 1973 and 1980-1981 and the price collapse of 1986 – was to create a sophisticated global energy market.

After much turmoil, this market, which now accommodates innumerable buyers and sellers, imposed a laissez-faire discipline on the matter of global oil pricing. In this market, petroleum prices take the forms of “spot” and “futures” prices. Spot prices represent what traders charge for oil for immediate settlement – usually, delivery within two days. Futures prices are prices for delivery of oil at a certain date in the future – as soon as one month, as far into the future as nine years – at specified prices. Driven by a global network of traders working around the clock (except weekends and holidays), spot trades take into account the needs of refineries and a constant stream of geopolitical and economic data.

The markets are more strongly influenced by information about how much crude oil inventory is in America’s stockpiles than by OPEC statements about how much oil they are going to produce. News about hurricanes and other extreme weather events also figure into price calculations. So do rumours and worries about conditions in the world’s large economies. 

The world’s energy traders bring uncountable resources, facts, needs, expectations and beliefs about the future into their collective trading decisions. This interplay of intelligence and knowledge creates a group mind capable of processing extraordinary amounts of information as it establishes global prices. Charts of spot prices changing minute by minute can be found on numerous web sites.

Benchmark Pricing: Spot prices represent the business end of crude oil pricing, but futures contracts are the ones that truly set prices. As their name implies, futures contracts anticipate what prices will be in the future. Investors and speculators buy these contracts on major commodity exchanges, and spot traders use them as their main references as they negotiate prices.

Traders have developed many strategies using futures contracts. They are commonly used for financial speculation, but they also have practical business uses. Refiners can use them to secure the price they will pay for oil at certain points in the future, for example. To create futures markets, exchanges had to settle on particular kinds of oil to serve as benchmarks. The price of a barrel is highly dependent on both its grade (which is determined by factors such as its specific gravity and its sulfur content) and its point of delivery. In North America, the benchmark price on the New York Mercantile Exchange (NYMEX) is West Texas intermediate oil (WTI), delivered at Cushing, Oklahoma.

There are other benchmark crude oil contracts. Of these, the most important is Brent light, delivered at a port in the north of Scotland. Traded on the International Commodity Exchange in London, this oil contract essentially determines the price of oil in Europe and Africa. Oman oil, which is traded in Dubai, helps determine the cost of oil in the Middle East. The US government’s Energy Information Administration uses an entirely different approach to oil price calculations. It calculates the weighted average cost of oil imports (including oil from its biggest supplier, Canada) to determine the world oil price for the United States. Known as the Imported Refiner Acquisition Cost index, this is a lagging indicator. Instead of giving information about what prices are or will be, it describes what they have been.

Edmonton Par: Although Canada is a large and growing oil producer, we are a price taker rather than a price maker. Canadian prices are established by reference to the benchmarks of New York, especially, and of London. Those benchmarks are the price makers. The “real” price of oil is its spot price – the amount a buyer will pay for oil for real, immediate delivery. One important Canadian pricing standard is Edmonton light oil. How prices for that oil are established illustrates spot pricing in action. Initially, the price for Edmonton light is set by the companies – Imperial Oil, Petro-Canada, Shell and Suncor – with facilities at Refinery Row, near Alberta’s capital city.

Each morning they post the price they will pay for Edmonton light. Those prices closely track the most recent closing price for NYMEX futures contracts. The daily average of the prices offered by those four refiners is known as Edmonton Par, and it is the standard used for calculating oil prices in Western Canada. Foreign buyers (mostly located in Chicago) negotiate deals that take into account Edmonton Par, the futures price in New York, the spot price in Edmonton, the date the oil will be delivered, the difference in quality between Canadian light and WTI, the cost of transportation and the availability of competing supplies. As with other efficient markets, the price of Canadian oil reflects a balance of the needs and intelligence of many buyers and sellers.

Canada’s Split Personality: Global markets have had quite a big impact on the distribution of oil within Canada and across North America. In particular, they have helped determine which parts of North America use Canadian oil, and which use oil from the US and overseas. Refiners avoid the high transportation charges required to pipeline oil from Alberta to Toronto and points east. Instead, they buy oil from offshore Newfoundland or from international markets. That oil is delivered to ports in eastern Canada or to a pipeline terminal at the ice-free harbour in Portland, Maine. From those delivery points the oil is piped to major refining centres in Come-by-Chance, Nfld.; Saint John, NB; Montréal and St. Romauld, PQ; and Nanticoke, Ont.; and to smaller eastern refineries.

Oil from western Canada is another story. It is highly competitive from Vancouver to Sarnia, and in parts of the US West and Midwest. Many refiners in those areas have developed equipment designed to refine specific kinds of oil from Canadian producers. That specialized equipment is one part of the industrial infrastructure that has created secure markets for Canadian oil. Another is North America’s complex network of interconnected pipelines, which make delivery relatively easy.

In practice, Canada has a split personality in the matter of oil imports and exports, and this is mostly a function of our planet’s market pricing for oil. We are the seventh largest exporter of oil in the world, but also the seventh largest importer. In 2006, each day Canada exported 1,784,000 barrels of crude oil, mostly from the west. At the same time, however, we imported 849,000 per day into the east. Canada was thus a net exporter of 935,000 barrels of oil per day.

Because a great deal of our oil production is lower-quality heavy oil, in 2006 Canadian production on the whole sold for less than the $66 per barrel fetched by West Texas Intermediate. However, those net exports added more than $55 million per day to our trade balance with the world. The creation of a sophisticated global marketplace for crude oil coincided closely with the years in which Canada joined the big leagues of global oil producers and exporters. As we have seen, market pricing now suffuses the sector, and it has helped put the industry into its present form. An example is Canada’s decision to import oil for its eastern refineries while exporting oil from the west. In this instance and many others, efficient markets have helped create a cost-efficient industry.

One Decade into a New Era

Monthly oil price chart from TradingCharts.com

By Peter McKenzie-Brown

Ten years ago, oil prices hit their lowest levels in two decades, and pundits proclaimed that an era of lower prices was here to stay. Industry insiders felt that not even OPEC could help the world’s producers. Prices had plummeted because of increased production from Iraq, lack of demand growth in an Asia struggling to recover from an agonizing economic crisis, and high world oil inventories following two unusually warm winters.

In addition, OPEC's members were cheating on their export quotas, and large new volumes of oil were flowing into world markets from such non-OPEC countries as Norway and Russia. The oil industry had given up hope that prices might rebound. The chairman of Royal Dutch/Shell unveiled a five-year plan that assumed a price of $14 a barrel; he then began to muse about oil at $11. BP began working with similar assumptions. Algeria’s oil minister was so worried about the inability of OPEC to cut production that he raised the spectre of $2-a-barrel oil.

Drowning in Oil: So pervasive was the general oil-price pessimism that in March, 1999, one of the world’s most highly respected business magazines, The Economist, issued a special 20-page supplement about the prospects for crude oil. The magazine’s lead editorial described “A world drowning in oil.” With spectacular bad timing, the publication argued that crude oil prices could drop to US$5 because of a glut in world supplies, and suggested that nothing could save the price of oil. “Crude is gushing from the ground at the rate of 66m barrels a day, half as copiously again as in OPEC’s prime. The world is awash with the stuff, and it is likely to remain so.”

As The Economist hit the newsstands, OPEC began to bring new discipline to world crude markets. The cartel pledged its third round of production cuts in just over a year, thereby reducing exports during that period by 4.3 million barrels per day. In addition, the organization negotiated coordinated cuts by other major oil exporters – Russia, Mexico, Norway and Oman. The cartel and its co-conspirators (except Russia) stuck to their guns, and a new bull market began.

Three Eras: In my view, the rise in oil prices over the last ten years reflects a third era in the petroleum industry’s 160-year history.

 • The first period lasted from 1860 until about 1970; call it the “era of growing surpluses”. During that time, the key events in oil pricing had mostly to do with new discoveries and other events that increased production. In other words, the events affecting crude oil pricing reflected increases in supply. There was a general decline in real oil prices, because the amount of oil available was steadily climbing.

 • What we might call the “era of energy price shocks” lasted from 1973 until almost 2000. Three price shocks – each a combination of geopolitical events and market forces – helped drive oil prices. The first two shocks were the price spikes of 1973 and 1979-80, which were responses to events in the Middle East and OPEC’s control of supplies.

Then market forces – less demand from the world’s consumers combined with increasing production, especially from OPEC producers – asserted themselves. In 1986 this led to the third shock – a rapid collapse of oil prices. Oil prices did not begin to recover until near the end of the millennium.

 • The third period began a decade ago; we can call it the “era of tighter supply”. Virtually all observers agree that prices have been steadily rising because oil supplies are “tight” – that is, there is little surplus oil supply to compete for existing demand.

Much of the reason for this strong demand is the powerful global economy, which demands ever-greater supplies of oil. In such a seller’s market - the petroleum industry is producing 30 billion barrels of oil per year but only discovering ten billion - there is not enough competition among oil producers to drive prices down, or keep them at lower levels. As a result, geopolitical events and concern about the availability of oil supplies are having strong impacts on crude oil prices.

Many factors are now in play. These include war, terror and political instability; industrial incidents like plant and pipeline failure; storms and abnormally high and low temperatures; rapid economic growth in the developing world; industry reports and financial news and rumour, especially as they apply to oil demand and supply. During the era of tighter supply, these factors can be powerful short-term forces driving changes in crude oil prices. Rarely before has this been the case, and never before could seemingly small incidents trigger such large price movements.

Peak Oil: This summary of the oil ages does not mention peak oil. The reason is that we have not entered that fateful period yet. Whether it arrives next year or next decade, it will represent something fundamentally different from our experience today. In the era of tighter (though still growing) supply, the world can carry merrily on. Just pay more and get on with it. In the fourth oil era, all the rules will change. We won’t be able just to pay more for our oil. Because of the nature of the beast, we will have to learn to use less. The chart at the beginning of this post shows the astonishing growth in oil prices during a decade of gathering scarcity. You ain’t seen nothin’ yet.