By Peter McKenzie-Brown
The world has seen countless petroleum fortunes since the infant industry oozed out of oil seeps in Pennsylvania and Ontario. The message of these pages is that during all that time, nearly 150 years, petroleum has been and remains among the world’s greatest and most reliable generators of wealth. Oil and gas tend to create wealth during long cycles. Given time, these complex commodities outperform. It’s just that simple.
Or is it? This book, which begins with a global review of the industry, explains how the stock market investor can use an understanding of oil and gas to make money. Later chapters will use particular companies to illustrate specifics, but at this early stage it is worth noting that those illustrations will focus on two kinds of company.
The integrated global giants are one type. For the most part, they are headquartered in the United States, Britain and France, and they are huge by any measure.
“True” oil companies (those that just produce oil and gas, but do not refine it) are the other type you will find in these pages – especially those with operations in Canada, which has this continent’s best remaining resource potential.
That last statement requires an important qualification: Mexico’s petroleum resource potential is as great as Canada’s, but it is shorter-term, with nothing to compare to the vast potential of Alberta’s oil sands. More to the point, the Mexican constitution forbids private companies from developing oil and gas – a provision that is unlikely to change. Private sector oil and gas development on this continent is therefore almost certain to remain north of the Rio Grande. And increasingly, it is likely to shift north of the 49th Parallel, into Canada and Alaska.
Exxon Mobil is the mightiest of the global giants. At yearend 2001 it Until recently the world’s largest corporation by revenue – that enormous enterprise dates back to the industry’s earliest years; you can almost think of it as a stock market proxy for Big Oil. Exxon Mobil has global assets worth nearly US$150 billion, and had net income (“profits”) of around US$20 billion in 2001. And even though the kingdom of Saudi Arabia appropriated the company’s huge Arabian assets in the early 1970s – a huge loss, at least in theory – the corporation’s share price has risen 2,000 percent. How does that compare to the performance of other companies?
To measure anything, you need some kind of ruler. In stock market investing you ordinarily use as the standard an average or an index. These pages deal elsewhere with the manner in which stock market indicators are made. In the meantime, it is enough to known that the Dow Jones Industrial Average – “the Dow,” as it is popularly known – is the most widely watched indicator of stock market movements. The Dow has many virtues. It is more than 100 years old. It is well known. And because it averages the prices of only 30 stocks, it is manageable. These stocks tend to be those of the largest, most established firms and represent a range of industries, too. Unfortunately, the small number is also a disadvantage: a group of only thirty companies is not an ideal proxy for the thousands of stocks that make up the market as a whole.
Imperfect it may be, but both the Dow and the well-known Standard and Poors 500-stock index (“the S&P 500”) greatly underperformed Exxon Mobil during those years. During the last three decades, both the Dow and the S&P 500 rose by slightly more than 1,000 percent. Both did well, in other words – but not nearly as well as Exxon Mobil. The following chart tells the story.
Of course, the Dow and the S&P 500 use the ticker prices of America’s large corporations. This means those indexes reflect older segments of the economy. How has Exxon Mobil, the elderly oil giant, performed relative to younger, rapid-growth technology companies during the last three decades?
The place to look is the Nasdaq Composite Average (“the Nasdaq”). This index reflects the prices of all domestic and international common stocks listed on the Nasdaq Stock Market – at this writing, more than 4,000 companies. The Nasdaq began life in February 1971, with a base of 100. Thirty years later, the index had performed about as well as Exxon.
And even that comparison understates the corporation’s performance, because many Nasdaq companies do not pay dividends. If you invested in the Nasdaq, the only return you got was capital appreciation. If you had bought a single Exxon Mobil share for $xy in 1971, your thirty-year return would have included 2,000 percent capital appreciation plus $xy in dividends.
Great as Exxon Mobil’s performance has been, many producers have done even better. Consider Alberta Energy Company, a Canadian natural gas producer. Here is its seven-year chart:
Even before the latest bull market in oil and gas began, the company’s stock tracked the Dow. Then it began to surge. You don’t sneeze at two hundred percent growth in seven years. These pages discuss elsewhere the merger of Alberta Energy and PanCanadian Petroleum into an oil and gas giant.
Not all Canadian oil and gas companies have done this well, of course. However, the non-performers understand the consequences they will face if they fail to deliver value. They get sold – frequently to American predators, who in recent years have been paying top dollar – or otherwise taken over.
The quick, simple message from these illustrations is that solid petroleum stocks can outperform both the staid corporations of the Dow and the emerging companies of the Nasdaq. This is not a new idea. Over the last century, the oil and gas sector has outperformed almost every other part of the economy. There are four main reasons for this remarkable record.
One is that the world has demanded ever-larger fixes of oil, which has become the oxygen of the global economy. Oil companies have profited richly from producing and marketing increasing volumes of oil and oil products.
The second is that the industry has become an extraordinary wealth-creation system, which operates somewhat like nature’s food chain. Small companies grow in size, and are eventually bought out by larger companies – which themselves are eventually consumed by the oil “majors” (the large international companies) and the three “super-majors”: Exxon Mobil, Shell and BP. These large companies then shed unwanted oil and gas properties and other assets, and there are markets for mineral rights and concessions for oil exploration. These factors enable small companies to form and grow, and the cycle to continue.
The third reason the petroleum sector has performed so well is that new technologies and management systems have enabled producers, in particular, to do their business more efficiently. This has enabled them to be profitable even when “real” oil prices (adjusted for price inflation) are at levels that would have sunk oil companies in earlier times.
National oil companies – the ones owned by the governments of petroleum-rich countries to produce government-owned oil and gas – have not fared so well. They suffer chronic shortages of investment capital because of constant and considerable revenue demands from government. And because they do not have the discipline imposed on management by the stock market, they tend to be less focused on the bottom line.
The fourth reason private-sector oil companies have outperformed is that petroleum by its nature can easily capture manufactured value. Petroleum products range from fuels to fertilizers to lubricants to other energy and petrochemical products.
For integrated companies like Exxon Mobil, oil production is just the beginning. The oil industry is a huge, interwoven web of industrial processes. Producing oil is one source of wealth. Distilling that oil into a huge range of high-value products is another. And if you react hydrocarbons with other chemicals, you can create valuable petrochemicals and pharmaceuticals.
Large businesses have developed around natural gas transportation and delivery. In the 1990s, an industry based on energy trading and energy-related financial derivatives quickly grew up. That industry’s reputation was badly tarnished when Enron quickly unravelled in 2001. The largest bankruptcy in history, the failure launched a thousand suits.
As the examples of Exxon Mobil and Alberta Energy illustrate, the greatest opportunities for most private investors to get wealthy through oil are in the stock exchanges of North America and Europe. Despite the existence of huge, government-owned petroleum producers, most of the petroleum industry’s real wealth can be read on the stock market ticker.
The fact that oil stocks have tended to perform well in the past is no guarantee they will do so in the future, of course. Even so, people buy stocks because history says they are likely to make money if they do. History also says that oil stocks outperform.
According to one group of stock market theoreticians, the movement of stockmarkets is a random, unpredictable walk that, for no particular reason, has trended upward since stock markets began. Elsewhere, we shall discuss this idea, which Burton Malkiel made famous in his classic book, A Random Walk Down Wall Street.
According to random walkers, technical analysis will not help you understand a company. Neither will fundamental analysis – after all, no single fundamental analyst has ever outperformed the averages over time. If you buy Malkiel’s thesis, the theoretical best possible investment strategy is to buy a group of stocks and hold them forever.
Later chapters will explain why oil stocks are likely to continue outperforming other stocks as a whole, and why an important new bull market is gathering steam. So if you feel comfortable that oil and gas stocks will continue to outperform the rest of the stock market over time, one investment strategy would be simply to buy high-quality stocks like Exxon Mobil and Alberta Energy (or a group of them) and hold on. The risk in this long-term strategy is low, and it suits a particular type of investment temperament.
However, as this book explains throughout, political and economic factors can have a profound impact on oil prices. War and upheaval in the Middle East have been a regular part of life for millennia, and there is no reason to think they will soon end. An Arab/Israeli war in 1973 saw oil prices quickly quadruple and remain high. In 1979-80, they more than doubled again, because of the Iranian Revolution. Because they reflect volatile commodity prices, oil and gas stocks are also volatile.
This volatility raises an intriguing question. Could you learn to consistently buy near the bottom of the price cycle and sell near the top — thereby making a lot for yourself while leaving a little profit for the next investor? Perhaps. One message of this book is that if you understand the patterns and rhythms of oil and gas stocks, you can enjoy unusually high returns, year in and year out.
A well-known oil and gas analyst, Wilf Gobert, has observed that the Toronto Stock Exchange’s Oil and Gas Index ticks up and down to a particular pattern. This year’s low will be 25 percent below last year’s high, while this year’s high will be 50 percent above last year’s low. That formula is worth remembering; it can be used for market timing – an approach these pages discuss in more detail, elsewhere.
Another strategy is simply to invest your money in energy stocks during the period March, April and May – the spring months. In a study of the period 1980 to 2001, George Vasic of UBS Warburg found that North American energy stocks gained between 8.8 percent and 10.1 percent over this three-month period during the spring months. A winning strategy, therefore, might be to invest your money only in a portfolio of energy stocks during those months, and to keep it in cash for the rest of the year. This approach is known as seasonality.
These are simple ideas for making money in oil and gas. To do even better takes more work. But it also requires a clear comprehension of how the industry and its indexes function. It requires fluency with the tools that make people good investors, including the ability to analyse a balance sheet and to be able to compare one company against another. It also means knowing how to apply such ephemera as chart analysis and technical oscillators. Later chapters offer basic studies in these areas.
Before we get to those disciplines, though, you need to understand why a commodity boom in oil and gas has already begun, and why it will fuel a major bull market in oil and gas stocks. There are several reasons.
One is instability in the Middle East, recently heightened by acts of terror and warfare. Most of the freely trading oil on world markets comes from that region, and there is a great deal of competition for supply. When political or military events interfere with supplies, oil prices go up.
Another is a potentially precarious balance of supply for oil and gas. This book will discuss both commodities and their diverse applications. The term “petroleum” refers to both oil and gas – two commodities that are similar but different. Their prices are linked.
The potential for tight oil supplies is worldwide and likely to become chronic. The last hundred years have generally been a buyer’s market in oil and gas. The industry was almost always able to meet demand with capacity to spare; consumers have fared well from this energy source, which has mostly been quite cheap. This is about to change. For reasons we will return to later, a seller’s market of high prices and prospects of energy shortages is likely to begin soon.
The longer-term outlook for natural gas is rosier in the sense that there are greater resources. However, there is reason to worry about medium-term North American supplies. Toward the end of this decade, the Lower 48 states and Southern Canada will begin burning natural gas from either Alaska or Canada’s Arctic (or both). Between now and the last weld on a northern pipeline, existing producing regions could find themselves hard-pressed to meet continental demand.
The world’s growing concern about the environment is a third reason why energy prices are likely to rise. Although issues like unemployment and terrorism can push environmental issues back from view, among North Americans they are rarely far from public consciousness. In particular, worries about global warming have extraordinary implications for the oil and gas sector. So do environmental concerns about hydro, coal and nuclear fuels.
Finally, there is the matter of an international cartel of petroleum producers. The Organization of Petroleum Exporting Countries (Opec) has roots in the petroleum industry’s earliest years, which themselves tell a complex and fascinating story.
Before beginning that tale, a note about method. These pages offer a great deal of historical information about the oil industry. That is because we take seriously a dictum of Winston Churchill, the great statesman who was an eminent historian in his own right, and a winner of the Nobel Prize for literature.
Said Churchill, “The farther backward you look, the farther forward you can see.” To understand Opec, you need to understand that the industry has almost without exception been influenced or controlled by an oil cartel. The industry’s penchant for cartels proves the adage once again that the more things change, the more they stay the same.
John D. Rockefeller was the first person to demonstrate that oil can be the source of almost unimaginable wealth. Rockefeller was a pioneer in many things oily, including the petroleum cartel. The Standard Oil Trust, which he created in 1882, quickly made him the world’s richest man.
In the century since, the world’s richest person has frequently had a fortune based on oil. Before Microsoft Corporation’s Bill Gates assumed that mantle, it lay on the shoulders of the Sultan of Brunei, the monarch of a small, oil-rich country bordered by Malaysia and the South China Sea. Like many other people made wealthy by petroleum, the Sultan is a passive beneficiary of cartel behaviour, which props up prices. On the international scene, he is not an active monopolist.
Rockefeller and his cronies frequently used unscrupulous tactics to defeat competitors, notably by taking control of railroad and pipeline transportation.
In addition, he took control of the refineries – the ultimate destinations for the great rivers of oil that flowed from the fields of America. While the Standard Oil Trust never controlled more than thirty-five percent of the world’s oil production, at one time it controlled ninety percent of all refining capacity. That gave the trust control of both market and price.
In 1901 Theodore Roosevelt committed himself to a war against monopolies. Five years later, he launched a lawsuit against Standard, charging discriminatory practices on the market, abuse of power and excessive control of the American oil industry. The suit was based on the 1890 Sherman Anti-Trust Act, which in its earliest days had mainly been used to break unions.
When Standard’s annual profits totalled the then-fabulous sum of $100 million, in 1911 the US Supreme Court ordered it broken into thirty-three new companies. In the United States, the petroleum industry has never fully recovered from the scandal of those early years.
The largest descendent of the “mini-Standards” calved from the trust is none other than Exxon Mobil, one of the three super-major global giants.
As its name implies, the corporation combines the Exxon and Mobil threads of the Standard Oil weave; they formally merged on November 30th, 1999. Exxon was once known as Standard Oil of New Jersey; Mobil began life as Standard of New York. And each was incorporated as part of the Standard Oil Trust in the same year, 1882. “The corporate entities that would become Exxon and Mobil began the 20th century as components of one company,” began the merged corporation’s official history. “At the end of the century, they came together as a single premier organization. For most of the years in between, they blazed separate trails as independent, competing enterprises. Each company placed a singular imprint on the energy industry and on a dynamic era of world history.”
The other mini-Standards have mostly been absorbed into large companies – notably London-based super-major BP, which in the late 1990s absorbed Amoco and ARCO, two other descendents of the Standard Oil Trust.
The world oil industry has a long tradition of strong influenced by a price-maker or cartel. There are several reasons why you might expect oil to prefer to organize itself as a cartel. One is that the commodity can deliver great wealth, and it can do so quickly. In addition, oil rewards bigness. Oil and gas require a lot of investment and relatively little labour, so oil producers are rarely mom-and-pop operations. Collusion is easier when the number of big competitors is small.
After the Second World War, economist Paul Frankel argued that the very economic foundation of oil was behind the continuing appearance of cartels. On the demand side, oil is price inelastic: people need it so badly they will pay whatever the market will bear. On the supply side, explorers drill during even the lowest-price environments, and producers will always sell. Only a cartel can bring order to such chaos, goes the theory.
Whether this notion makes sense or not, control of oil has been on the world stage for more than one hundred years. One cast includes some of the biggest corporations in the world. These grand, integrated companies explore for and produce, transport and refine crude oil; manufacture and market petrochemicals and other oil products; find, produce and deliver natural gas. Another cast includes oil producers owned by national governments – for example, Mexico’s Pemex and Saudi Arabia’s Aramco.
As we shall see in a later chapter, governments take a keen interest in petroleum issues. One reason is that energy is a strategic commodity; economies would collapse without it. Another is that royalties, concession fees and fuel taxes have made petroleum the most prolific cash cow on the planet.
When big players become highly reliant on petroleum revenues, collusion comes easy. This is why oil prices have usually been influenced as strongly by monopolistic agreements or government fiat (or both) as by free markets. Although no one has ever exerted more power than Rockefeller, cartels have been part of the price equation for oil and its products almost since the industry’s birth.
Sometimes the price fixers were quiet agreements among global energy executives. Sometimes they were government regulators like the Texas Railway Commission, which controlled prices by controlling production. Since 1973, the strongest political influence on oil prices has been Opec. To understand the oil industry, you have to understand this cartel, which comes up frequently in these pages.
During the days of the Standard Oil Trust, oil’s main uses were for medicine, lubrication and, notably, fuel for kerosene lamps. Oil became a critical part of Western economies during the First World War, when it found uses in warfare. By the 1920s, automobiles were common in North America. Oil quickly became a vital commodity, and one which American production dominated.
In 1928, US oil prices were high but threatened by cheap oil from Iran and Venezuela. Accordingly, in August representatives of Shell, BP, Standard (now Exxon Mobil) and other large companies secretly met at Achnacarry Castle in the Scottish Highlands to establish another cartel. Over a two-week period, they created the “Gulf Plus” system, by which world oil was fixed at the price in the Gulf of Mexico plus standard freight charges. This eliminated the prospect of BP supplying cheap oil from Iraq to European consumers, for example.
Shell, BP and the sixteen largest American oil companies signed on to the cartel, which added greatly to the bottom line. Although modified several times, the system lasted for a decade. “Most of the world’s oil resources were in the hands of the big oil companies,” wrote Anthony Sampson, “and the agreements succeeded in their main object of maintaining stable prices at the American levels, and of limiting competition inside each country. The monopoly of Rockefeller had evolved, with apparent inevitability, into a global cartel.”
The cartel of Achnacarry Castle was of great benefit to companies that shipped oil about on the high seas, but it was of little value to smaller North American producers. Exploration and production cycles continued to be the cause of frequent periods of hardship in an industry that could go from robust growth to withering recession with amazing speed – a characteristic that remains to this day. Producers experienced cycles of boom and bust, as large new discoveries offset increasingly robust demand.
This situation was at its worst during the Great Depression. Beginning with Dad Joiner’s discovery in 1930 of the celebrated Black Giant oilfield in East Texas, the global oil industry discovered more oil in that decade than in any other ten-year period.
Joiner was a legendary wildcatter – an explorer who used hunches rather than science in his search for oil. He sweet-talked money out of whomever he could, and was eventually well rewarded for his efforts. He received $1.33 million for his interest in the Black Giant discovery. Yet when he died, his estate included little more than a modest house.
So prolific were Black Giant and other East Texas fields that worldwide competition for crude oil markets became ruinous. Producers were running the taps just to produce oil that sold for pennies a barrel, and gas stations offered free chickens to lure customers. This called for political action, which eventually involved turning the Texas Railway Commission into a de facto cartel. The commission managed oil prices by controlling the amount of oil being produced in Texas.
As recently as 1950, the US produced half the world’s oil – most of that from the Lone Star state. Consequently, control of production in Texas meant control of worldwide prices. Indeed, the Texas Railway Commission served as the model for the later creation of Opec.
And once again, the big oil companies used their control of refining much as Rockefeller had done. As a group they set a posted price for oil – the amount they, as a cartel, would pay to Middle East producers. There was a crucial difference between their efforts this time and those of Achnacarry. Now they set the price of oil in the Persian Gulf rather than the Gulf of Mexico, with the cost of freight added. This meant Texas producers received higher prices than those of the Middle East.
You could argue that this approach was justifiable, since the cost of oil production in the Middle East was so low, but the potentates of those countries were not amused. Even so, they maintained an uneasy peace with the transnational oil companies of America and Europe. That changed on August 9, 1960, when Standard of New Jersey (now Exxon Mobil) lowered the price to $1.63 per barrel, ostensibly because of freight changes. By common agreement, the other big oil companies followed – although in some cases reluctantly.
The posted price essentially became a tool for producing countries to use when they calculated their taxes on those companies. The market set the price of Persian Gulf oil in the 1960s, and that price continued to decline. By 1970, oil from the Middle East had fallen to $1.21 per barrel, while the price of US production had risen to $3.18. This laid the groundwork for many adventures (recounted elsewhere in these pages), because of which Opec became the major world cartel. That cartel has remained a key player in the global market.
A singular feature of the world’s large, single-resource, oil-exporting countries is that, except for a few like Norway, Venezuela and Indonesia, they tend to be undemocratic. The wealth from oil production tends to fund government, and those governments can be reasonably enlightened.
For example, as the ruler of an oil-producing state, the Sultan of Brunei commands affection and respect among his people, who are among the wealthiest in the Third World. His government provides for all medical services and subsidizes rice and housing in that wealthy little country. Also of note about Brunei is that the death penalty is mandatory if you are caught using drugs. Interestingly, in recent years the Sultan’s public persona has stressed his devotion to Islam. There is thus little prospect for democracy.
The Third World’s other Islamic, oil-exporting countries are generally not so lucky. The name of Iraq, which is ruled by Saddam Hussein, comes to mind. So does Nigeria, with its generals and its failing and phoney efforts to create responsible government. In both countries, and in many other OPEC member states, corruption and extortion are widespread.
Wealthy princes and other plutocrats govern Saudi Arabia, as do other Excellencies in other oil-exporting countries. And since the Iranian Revolution of 1979-80 (of which, more later), religious leaders have had increasing political clout in the Middle East.
The dominance of non-democratic governments in major oil exporting countries is one of several sources of mischief for the industry and its consumers. Another is the frequent dominance of Islam. We will discuss both matters in the next chapter.
To prepare yourself for the general drift of that discussion, please entertain the following thoughts. First, most westerners consider Saudi Arabia to be an ally of the West. After all, a US-led war saved Kuwait from conquest by Iraq, the US now has military bases on Saudi territory, and it is committed to defending the country because of the industrialized world’s need for Persian Gulf oil.
So far, Washington has been able to keep the kingdom in line. But state-sponsored texts in Saudi Arabia teach that those in the West are “infidels” and the “enemy,” and encourage Saudi youth not to associate with Jews or Christians. Said Glenn Bonci, “such teachings create the ripples that create the hatred that creates the desire for people to dedicate their lives to destroying the West.” The following chapter investigates those allegations.
Soviet military advisers to Egypt flew abruptly home in the middle of September 1973, and Israel failed to take notice. Then, in a coordinated assault, Syria and Egypt launched a surprise attack during Yom Kippur – the holiest of Jewish holidays, and in Islam’s holy month of Ramadan. The date was October 6th.
On the Golan Heights, 180 Israeli tanks faced an attack by 1,400 Syrian tanks. When 80,000 Egyptians attacked, there were fewer than five hundred Israeli defenders along the Suez Canal.
Thrown onto the defensive during the first two days of fighting, Israel mobilized its reserves. The small country repulsed the invaders and carried the war deep into both Syria and Egypt. The Arab states were swiftly re-supplied by sea and air from the Soviet Union, which rejected American efforts to work toward an immediate ceasefire. So the United States began its own airlift to Israel. The two powers of the Cold War were nose to nose.
The United Nations saved Egypt from a disastrous defeat on October 22, when the Security Council adopted Resolution 338, which called for "all parties to the present fighting to cease all firing and terminate all military activity immediately." The vote came as Israeli forces cut off and isolated the Egyptian Third Army and were in a position to destroy it.
American support of Israel triggered fierce hostility toward the West from Iran and the Arab members of Opec, and they supposedly imposed oil embargoes on countries supporting Israel. In practical terms, imposing a selective embargo on a globally traded commodity is not possible: traders simply swap customers from nation to nation until the markets balance. However, the moves by Arab countries put fear into the market and panic buying sent prices up. This was the first in a series of short, sharp shocks.
First Price Shock: Economic historians know this sequence of events as the first oil price shock, and that shock weighed upon world economies for years. In the West, it contributed heavily to an economic malaise known as stagflation – a stagnant economy suffering high levels of inflation.
As the abortive 1967 oil embargo on the United States illustrated, Opec was mostly toothless for its first few years of life because world oil supplies were plentiful. In 1969, however, revolutionary Colonel Muammar al-Qadhafi overthrew Libya’s King Idris and soon forced international oil companies to pay thirty cents more for Libyan oil.
Inspired by his show of strength, Opec meetings in Caracas in 1970 and Teheran in 1971 generated agreements on solidarity and joint action. Their stated aims included raising government participation and take from the oil industry, to be achieved through “rational increases in production from the Opec area to meet estimated increases during the period 1971-75.” Meanwhile, the balance between oil supply and demand quietly began to shift in favour of the producers. After the Yom Kippur War, Opec realized that it had the power to become a real cartel. The organization found that by announcing a cut in oil production and an “embargo” on oil to the United States and Europe, it had the power to force consumers to pay higher prices for oil.
“Between 1971 and 1974 there was no resource scarcity, nor was there any sign of an over- and under-investment cycle,” M.A. Adelman explained. “What happened was learning by doing. A new cartel gained experience and confidence by repeated success.... The cartel’s confidence was built up by continued success, as it sensed little resistance by companies and consuming governments.”
Unilateral moves by Opec – especially in the Middle East, where producing countries expropriated foreign oil assets and increased taxes on oil – helped create an atmosphere of crisis, and panic buying set in. Despite a glutted oil market, by 1975 the price of Saudi oil had risen from less than $2 per barrel to $10.66.
After the cartel learned the tricks of the trade, it began meeting from time to time to agree how much to increase its “marker price,” and fine-tuned production to keep prices at those levels. Consumers in oil-importing countries had no choice. They paid for imports at prices periodically set by a small alliance of foreign countries.
Second Price Shock: If anything, the second oil price shock was more devastating than the first. It came in 1979-80, in response to the Iranian Revolution – the first great victory for the Islamic Resurgence – and the beginning of the Iran-Iraq War.
After a year of public demonstrations against him, the Shah of Iran left Teheran in January 1979 for an "extended vacation." He put the country in the hands of a regency council.
Soon a popular exiled leader, Ayatollah Ruhollah Khomeini, returned to the country and took power, declaring a religiously conservative Islamic Republic. The crisis atmosphere peaked when a group of “students” occupied the US Embassy, taking most of the staff hostage. Khomeini and his government were complicit in the hostage taking, which led to a 444-day standoff. These events were complicated in September 1980, when Iraqi fighter aircraft attacked ten air bases in Iran – thereby starting a bloody, costly war that would drag on for eight long years. The combination of revolutionary and military actions disrupted world oil supplies.
These events conspired with panic in the markets to send oil prices into the stratosphere. Oil rose to US$40 per barrel, and most people began to believe that henceforth oil prices would always stay high. Forecasts of oil at $100 per barrel (or higher) by the year 2000 began to abound. The prices of oil and gas shares rocketed.
By 1980, energy stocks accounted for thirty percent of the stock market in the US, and twenty-two percent in Canada. Nine of the ten largest capitalization stocks in the United States were energy stocks. The only non-energy name in the top ten was General Electric – and that venerable name had only half the market capitalization of Schlumberger, an energy service firm.
But both oil and stock prices began to subside after the hostage crisis was resolved and the Opec cartel began losing its teeth. One reason for the weakening of Opec was that new oil production began to arrive on world markets from the North Sea and Alaska. Another was that the high prices oil reached in 1979 triggered a dramatic drop in demand. It was ten long years before global oil production again reached its 1979 peak.
Beginning in 1980, Opec could no longer keep increasing supply. For the first time, the cartel had to make severe production cuts to keep oil prices up. As we shall see, this helped destabilize Opec, whose members all wanted maximum revenues. Most of them cheated on their production quotas.
Because of the first two price shocks, the world has become less reliant on oil for home heating and industrial processes. While oil is an important petrochemical feedstock and is still the source of much home heating oil, the refiner’s priority is to get as much transportation fuel – gasoline, diesel and aviation products – from a barrel as possible.
Refiners can use hydrocracking and other technologies to get high percentages of transportation fuels out of oil, which historically has been plentiful. This has made oil-based transport cheap: virtually all aircraft, ships, trains, trucks and cars require oil-based fuels, and the alternatives are either impractical or expensive.
To a large degree, global trade, travel and tourism have expanded because transportation fuels have been plentiful and cheap. As the first two price shocks illustrate, oil’s dominance in these areas gives it great potential as an economic weapon.
Of course, as the third oil price shock shows, there may be other ways to use oil as a weapon.
Third Price Shock: In January 1986, the third oil price shock arrived. In that single tumultuous month, oil prices dropped more than two thirds, to below US$10 per barrel. Before the market stabilized, trades actually took place below $5 per barrel.
The drop in prices was possible because people were successfully saving energy. In addition, they were substituting for oil such cheaper energy forms as coal and natural gas. Oil production in the non-Opec world was increasing. In addition, badly hammered by the recession of 1982-83 (itself partly induced by high oil prices), the world economy was still weak. In addition, world oil markets became much more sophisticated.*
But the decisive factor was Saudi Arabia’s decision to open the taps on its reservoirs, supposedly to re-establish its share of the world oil market. Prior to this decision, other Opec members were cheating on their production quotas to bring in revenue from a world that had declining demand for Opec oil. The members of the cartel were competing among themselves to maximize national revenue. Saudi Arabia was the Atlas that bore Opec on his shoulders. In 1986, he shrugged.
The Saudis had cut production to 3.6 million barrels per day in 1985 from 10 million just four years earlier. This kept prices up, but the kingdom lost market share and national revenue. In late 1985, the Saudis announced that they were as mad as hell and wouldn’t take it any more. They were going to increase their share of the market even if it involved a price war. As the Saudis turned on the taps, the markets panicked. Prices collapsed.
Did the Saudis really flood the markets just to recover market share? In the murky world of Middle Eastern politics, nothing is ever certain. However, serious conjecture has it that part of the reason for the 1986 oil price collapse was a grand plan by the US to bring the Soviet Union to its knees. As the story goes, cloak-and-dagger operatives and other diplomats from the American government strong-armed the Saudis into using the oil weapon against the Soviet Union.
According to this (highly improbable) conspiracy theory, deliberate efforts to flood world markets with Saudi oil were meant to cause oil prices to crash. The dramatic result deprived the Soviet Bloc of hard currency – 85 percent of which came from exporting oil and gas.
The New World Order
This policy, if policy it were, worked brilliantly. What President Ronald Reagan had famously called an “evil empire” soon began to crumble – one way or another, a victim of the geopolitics of oil.
The year after the Soviet Union fell, in 1990, the West was back at war in the Middle East. The first war of the Post-Cold War era was about protecting oil supply. The Gulf War began when Iraq used tanks and infantry to conquer tiny Kuwait, which took a single day. “With the possession of Kuwait, Saddam Hussein controlled 22 percent of the world’s exportable oil,” Walter Youngquist explained. “If he could also take Saudi Arabia, as there were indications that he might, he would control 44 percent of the oil for export.”
Concerned about security if the Iraqi regime controlled so much of the world’s oil supply, US President George Bush assembled an alliance of countries to wage war against Iraq. In late February 1991, before battle was joined, Hussein boasted, “The Mother of all battles will be our battle of victory and martyrdom.” A week later, the American Secretary of Defence, Richard Cheney, laconically observed, “The Iraqi forces are conducting the Mother of all retreats.”
The United States and its allies quickly defeated Hussein’s forces in a high technology, highly public military and media event. After winning the battle, however, Bush and his allies chose simply to stop the war. The armies did not take Baghdad and overthrow the government. They expected a spontaneous uprising in Iraq to do the job for them, but it did not come.
Although weakened, Hussein’s regime lived to fight another day. UN sanctions and other forms of pressure were placed on Iraq, and the country’s oil exports were briefly taken out of the world market. This contributed to an upward bulge in the price of oil.
According to President Bush, the Gulf War was signalling a “New World Order” in the post-Communist world. From now on, noble alliances of countries would band together to do the right thing for the world, as they did by liberating Kuwait. It soon became clear, however, that it was just another episode in 1,300 years of conflict between the West and the Middle East.
As Samuel Huntington later explained, “At stake was whether the bulk of the world’s largest oil reserves would be controlled by Saudi and emirate governments dependent on Western military power for their security or by independent anti-western regimes which would be able and might be willing to use the oil weapon against the West.... After the war the Persian Gulf was an American lake.” That lake today is anything but secure, and that insecurity is a source of great vulnerability.
The following chart spans the period in which Persian Gulf producers gradually came to dominate the global energy market. It shows how events in the quarter-century after the Yom Kippur War affected the real (inflation-adjusted) price of oil.
One way to interpret this chart is to conclude that the oil weapon worked for a little while, in the 1970s and early 1980s, but that it has long since lost its potency. Indeed, that was the common view as 1999 began, when world oil prices dropped below $10, reaching their lowest real price levels in history.
Forgetting the cyclical nature of the petroleum business, many pundits proclaimed a world of low oil prices well into the foreseeable future. Twenty years earlier, many of the same pundits had been forecasting high oil prices into the foreseeable future.
So pessimistic was opinion in the investment community that a highly respected business magazine, The Economist, issued a special supplement about crude oil. The magazine’s lead opinion article described “A world drowning in oil.”
With spectacular bad timing, the newspaper’s writer argued that crude oil prices could drop to US$5 because of a glut in world supplies. Nothing could save the price of oil, he wrote, even Opec. He despaired that the cartel could work its traditional magic, because members continued to cheat shamelessly on their export quotas. Furthermore, Opec was not the only game in town: increasingly large volumes of oil were flowing into world markets from such non-Opec countries as Norway and Russia. The author’s grim conclusion: surplus oil supplies would continue to depress world prices.
As the magazine hit the newsstands, Opec announced that it would bring new discipline to world crude markets. Members would cut production, and they would keep their exports low. In addition, the cartel 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.
What The Economist failed to see was another way of looking at the oil price chart on the previous page. That chart shows the volatility of crude oil prices and the impact on those prices of the vagaries of international affairs. When conditions are right, oil can be a weapon of great power. The magazine also failed to remember that, if unconstrained and conditions are favourable, cartels tend to grow in power. By using diplomacy to bring Norway, Mexico and Russia on side, Opec strengthened itself by orders of magnitude.
Bragging rights for the first major work to predict a new bull market in oil stocks go to Michael Economides and Ronald Oligney, both academics. In a commentary on the global energy industry, they wrote that “now is the time to buy energy stocks. They will escalate in value substantially in the early 2000s. The wise investor buys for the long-term because energy is the world’s biggest business, and it continues to move unstoppably forward.”
The three energy shocks and Opec’s recent successes in raising the price of oil illustrate the importance of Opec to the world’s petroleum industry. And as the next chapter will explain, the Persian Gulf’s importance is growing with every barrel of oil being pumped out of reservoirs in the non-Opec regions of the world.
But before we move on to that idea, it is important to understand that the conflict between the West and the nations of Islam is deep-rooted and intensifying. Let’s begin with the deep roots, which can be summed up in the parallel concepts of the Christian crusade and the Islamic jihad (“holy war”).
In Europe, social memories of the Great Crusades (1096-1291) usually conjure up notions of religiously inspired zeal to take the Holy Land back from the Infidel, by which they mostly meant Muslims. The Crusades were indeed motivated by the religious passion of the age and instigated by the Church. In practice, however, they generally meant taking hostage anyone of wealth, stealing anything that was stealable, raping anyone who was rapable, and laying waste the rest. The Crusades were efforts by poor states in Europe to conquer rich lands in the Middle East. That, certainly, is how they are remembered in the Arab world.
The Crusades were by no means the beginning of the struggles between Islam and the West, however. Through continual waves of jihad, in its early years Islam expanded outward from the Middle East with extraordinary speed and ferocity. The idea was to convert the Infidel – by which, in Western Europe, they mostly meant Christians.
Islamic armies invaded Europe through the Iberian Peninsula – an invasion that reached its first great climax one hundred years after Muhammad’s death, in 732. At the pivotal Battle of Poitiers, in what today is west-central France, Charles Martel and his Frankish army turned back the invaders, capturing and killing their commander, Abdurrahman. From those days to the present, there has been continual conflict between Islam and the Christendom of Western Europe, which today is called the West.
Before continuing this story, it is worth noting that the Crusades were inspired by religious zeal, but they were conducted in a way that honoured the Christian tradition of separation between Church and state. This tradition was concisely captured in the New Testament with Christ’s precept that one should “render therefore unto Caesar the things which are Caesar’s, and unto God the things that are God’s.”
Compare this to the Koran: “So when the sacred months have passed away, then slay the idolaters wherever you find them, and take them captives and besiege them and lie in wait for them in every ambush, then if they repent and keep up prayer and pay the poor-rate, leave their way free to them; surely Allah is Forgiving, Merciful.”
As this verse suggests, an early form of jihad was by act of theocracy (government by “God” – in practice, by religious leaders). Muhammad established himself as the leader of a theocratic warrior state during his lifetime, and early Islamic empires undertook many wars of conquest and conversion against unbelievers.
This single verse does much more than advocate jihad. It also refers to each of the Five Pillars of Islam, although sometimes in a veiled way. One of the pillars is faith in Allah and his Prophet Muhammad, which is suggested by the word “repent.” Another is regular prayer. The third is the fast during the Holy Month of Ramadan (“when the sacred months have passed away”.) The fourth is the poor-rate, which is known as Zakat. The fifth pillar is the obligation to take a pilgrimage to the city of Mecca, which is located in present-day Saudi Arabia. If they live up to the first four pillars, the verse says, “leave their way free to them” – presumably, to begin the pilgrimage.
Zakat is a voluntary 2½ percent tax paid in cash or kind by Muslims of means. According to the Book of the Prophet, as the Koran is also known, the proceeds are to be distributed among the poor. This taxing power helped strengthen the intimate ties between religion, government and war.
Although unsuccessful in the conquest of other westerly parts of Europe, Islam retained control of much of Iberia. Moorish Spain rose brilliantly out of the general squalor of medieval Europe.
An extension of Arab civilization, the rich and sophisticated society of Moorish Spain became the intellectual centre of Europe. Surprisingly, given the tradition of jihad, at its height of glory the community was tolerant of other religions. Although they were taxed for their right to religious freedom, Jews and Christians lived in peace with their Muslim overlords.
Though repeatedly diminished, Islamic power survived on the peninsula until 1492, when Christian forces conquered the last Muslim stronghold in Spain. No tolerance then: Ferdinand and Isabel soon ordered all Muslims and Jews to convert to Catholicism or leave their kingdom.
In one of the darker chapters of European history, they also made the Spanish Inquisition independent of control by the Church in Rome. Although it was also independent of the state, the Inquisition became a tool for confirming that Spain’s new converts had truly converted. It also checked into the beliefs and behaviours of others who were of interest to the Church and the court. No service was too small for the Spanish Inquisition.
As Spain drove out or converted its Infidels, expanding commerce with the Middle East and Europe’s assimilation of Arabic advances in mathematics and the sciences were fuelling the Renaissance in Italy. However, the Muslim world remained the powerhouse. Under Sultan Suleyman the Magnificent, in the mid-sixteenth century the Ottoman Empire (one remnant of which is now Turkey) was probably the most powerful state in the world.
But Europe soon waxed and the Middle East waned. Europe began acquiring powers that Arabs and other Islamic peoples could not match. By pursuing global trade, plundering the New World, building colonies, conquering empires and fostering the industrial revolution, the European powers (later joined by America) became masters of the universe.
Especially in the century or so leading up to the Second World War, Islamic countries fared poorly against Europe’s imperial might. In the aftermath of the First World War, for example, the European victors scrambled to divide spoils from the collapsing Ottoman Empire, which had made the mistake of siding with Germany and Austro-Hungary. The West’s claims on the world’s total landmass peaked in 1919.
Arabs have forgotten neither the humiliations of recent centuries nor the glories of centuries past. Indeed, the Western countries tend to see the years since the Second World War as a period of global progress. Not so, the Middle East.
Immediately after the Second World War, the West created the state of Israel. For Arabs, this religious state represented an unwanted new intrusion of non-Islamic values into the holy places of the Middle East – notably near the Noble Sanctuary in Jerusalem. One of Islam’s holiest sites, the sanctuary surrounds the Dome of the Rock, from which Mohammed ascended into heaven in his famed night journey. During that evening, he met most of the Prophets of the Old Testament, and received one command and a number of revelations. The command was prayer, five times a day. The revelation encapsulated the core values of Islam: surrender (“islam”) to Allah, and faith in the words of the Prophet.
"The Messenger believes in what was sent down to him from his Lord,” wrote the Prophet Mohammed. “And the believers; each one believes in Allah and His angels and in His books and His messengers. We make no division between any one of His messengers. And they say: We hear and we obey. Oh Lord, grant us Thy forgiveness; unto Thee we return."
The incursion of a Jewish state into what had been Palestine evoked fresh memories of the Crusades, and opposition to Israel ran deep. Egypt, Syria, Jordan, Lebanon, and Iraq sent their armies against the fledgling state, but were slowly repulsed. Since that time, Arabs have tended to see the defeats of their many military campaigns against Israel as losses to the West by proxy.
The Cold War was still cold, with the world divided into two different camps: NATO versus the Soviet Bloc. And both groups were building loyalties wherever they could. Numerous countries in the Middle East joined the Soviet camp – for example, Iraq, Egypt and Libya. Others, like Saudi Arabia, sided with the Americans as long as diplomats on both sides pretended that Israel did not exist.
This story goes way back in time, but a useful starting point is the Suez Crisis of 1956. The episode began when Egyptian President Gamel Abdul Nasser, a socialist, seized the Suez Canal. At the time the canal was a private asset belonging to the Anglo-French Suez Canal Company, which had constructed the canal in 1869 and operated it from that time forward. Britain, France and Israel plotted to take military action against Egypt. Thus was the Suez Crisis born, and the United States had not even been consulted.
Israeli forces launched a combined air and ground assault into Egypt's Sinai Peninsula, supported by an Anglo-French invasion of the canal. The Soviet Bloc supported Egypt, and Cold-Warrior sabre rattling began. Using an idea proposed by Canada’s Lester Pearson, the United Nations helped resolve the conflict by creating its first peacekeeping mission.
A decade later came the Six-Day War. Barbara Tuchman, an eminent American historian, put it best: “A people considered for centuries as non-fighters carried out in June, 1967 against long odds the most nearly perfect military operation in modern history."
While Tuchman may have put it best, William Varner put it briefest. “Israel fought the Six-Day War on three fronts against three countries in three overlapping stages,” he wrote. “In the south, Israel engaged and defeated the Egyptians. In the central region, Israel engaged and defeated the Jordanians. In the north, Israel engaged and defeated the Syrians. In each of these theatres, Israel gained significant territory that would serve as its own buffers in future years.”
Following this brief war, the Arab oil producers unsuccessfully attempted to place an oil embargo on the United States for its support of Israel. Defeats in both war and embargo were humiliating to the Arab world. They resurrected bitter memories of a thousand years of Western conquest in the Middle East.
At first, there were mostly howls of outrage. Then there were outrages and reprisals: acts of terror against Israel and its main ally, America, followed by retaliations in a long and weary cycle. The pattern has been going on for decades – or millennia, as far back as Roman times, depending on your perspective.
This brief review helps lay the groundwork for a major theme of this book. Oil became a weapon of war and revenge during the Yom Kippur War in 1973. However, it lost its potency in the 1980s as new reserves from elsewhere began to compete with Opec’s oil production.
Opec began to regain those powers in the late nineteen nineties. The oil weapon is an economic bomb with the Middle East as its epicentre, and the non-Islamic countries are surprisingly vulnerable. “The world’s five largest economies are the world’s largest energy importers,” Benjamin Barber points out. “The stronger the nation, the more fragile its independence.” The world’s second and third largest economies are China and Japan. They, too, are vulnerable.
As we explain in the next chapter, the world’s crude oil reserves are going through the normal processes of depletion, and most of the world’s great producing regions are quite mature. As a result, the supplies available in world markets are coming increasingly from the Persian Gulf. Opec’s share of world production is still not as high as it was in the 1970s, but its share is growing rapidly. In 2000, Opec had 41 percent of world oil production, and was closing in on the 47 percent it held at the height of its influence, in 1979. This means the oil weapon is gaining in strength.
The oil weapon belongs mainly to five of seven neighbours bordering the gulf, especially on the Arabian Peninsula. The states include Iran, which stares across the Persian Gulf at the others: Bahrain, Iraq, Kuwait, Qatar, Saudi Arabia, and the United Arab Emirates.
While the Gulf produces perhaps a third of the world’s oil, it has a strategic advantage over other producing regions. Its production makes up a quarter of the world's supply, and an extremely large percentage of the oil available on the global market typified by super tankers plying the oceans of the world. The Persian Gulf countries export most of their oil to industrial nations. The following chart shows the relative strength of each producer.
The Persian Gulf countries are different in many ways, but four major similarities among them are particularly important. In no particular order, those likenesses are the following. First, the countries’ economies are based on prolific oilfields. Second, their economies have often been mismanaged, which is partly why they remain poor countries with high rates of population growth. Third, they are undemocratic. And finally, they are overwhelmingly Islamic.
Prolific: First, they have within their borders most of the world’s most prolific oilfields. The Persian Gulf producers are rich in oil, but dependent on this single commodity to an almost unimaginable degree. Iran and Iraq have had agrarian civilizations for thousands of years. Until thirty years ago, Saudi Arabia’s best-known export was Mecca as a destination location for Islamic pilgrims.
Before they began producing oil, Kuwait and the UAE were small, poor communities on mostly-barren parcels of desert bordering the Persian Gulf; oil is now responsible for as much as 99 percent of economic activity in these desert kingdoms. Oil generates more than 60 per cent of the economic activity in Iran, which is the largest of these countries and has the most diverse economy.
As the next chapter explains, the Persian Gulf’s crude oil production rates are likely to begin tapering off after all the world’s other producing regions have gone into decline. This means the importance of the Persian Gulf to the world’s oil supply has yet to reach its peak. When that occurs, it will equip the oil weapon with a short fuse.
Mismanaged: A second similarity is that these countries they have mostly mismanaged their petroleum wealth. Despite their crude oil riches, by Western standards they are poor countries that have saddled themselves with inefficient national oil companies. Their oil wealth has been spent on weapons, the military and infrastructure without creating economic diversification.
The economies of the Persian Gulf countries are almost entirely dependent on crude oil revenues. Indeed, Kuwait, the United Arab Emirates and Saudi Arabia would still be desperately poor patches of Middle East sand if it were not for their mineral wealth. Yet despite their huge oil revenues, the rapidly growing populations of the Gulf are generally experiencing more unemployment and poverty than wealth, especially in Iraq.
Consider a few facts and statistics:
The Islamic Republic of Iran is a theocratic republic, governed by religious leaders according to conservative interpretations of Islam. The republic has 66 million citizens and gross domestic product (GDP) of $413 billion (currency in this section in US dollars). That works out to $6,500 per person.
Iraq is the poorest of the countries in the region. Its 23 million citizens have per capita GDP of $2,500. Civil rights abuses and corruption are rampant. In theory Iraq became a republic in 1958. In practice a military strongman rules. The country has endured an unusually brutal leader since Saddam Hussein took control in 1979.
Saudi Arabia and Kuwait are both monarchies, while hereditary “emirs” rule the small principalities that make up the United Arab Emirates. The population of Saudi Arabia is about the same size as Iraq’s, but per capita income is a much-higher $10,500.
The tiny populations of Kuwait and the UAE (more than two million in each country, most of whom are non-nationals) are the wealthiest in the region. Per capita GDP in Kuwait is $15,000. In the UAE it is $22,800 – similar to that in Western Europe. Both states have invested heavily in petrochemical plants, and have bought heavily into the stock markets of the world. This has created some economic diversification for their governments.
In many regions of the world, petroleum riches have contributed to general prosperity. Not so, the Persian Gulf. The Gulf countries export 17 million barrels of oil per day – about two thirds of the oil exported by Opec, with cash value in the hundreds of millions of dollars per day. Even so, most of these countries have been unable to successfully diversify.
Take Saudi Arabia, which by rights should be a rich nation. Despite its prolific oilwells, the world’s crude oil superstar is in trouble.
The kingdom had a population of six million in 1970; now it has more than 22 million people. Most of them are destitute. More than 100,000 school-leavers and graduates (mostly men) entered the job market in 2000. Only a quarter found work, even though the economy was at its strongest in more than a decade.
At 3.5 percent a year, Saudi Arabia's population growth rate is one of the highest in the world. Almost 60 percent of Saudis are under the age of 19.
A quickly growing population and a slowly growing economy have cut deeply into personal wealth in the kingdom. Saudi Arabia’s gross domestic product (GDP – a measure of all economic activity) per person has fallen sharply in recent years. In 1981 it was $28,600 for every man, woman and child. Twenty years later, during another oil price boom, it was $10,500. There is also great disparity of wealth, with a large royal family making great claims on national income.
Undemocratic: A third similarity among the Gulf States is that they are undemocratic. A thug rules Iraq, supported by one of the world’s largest armies. Mullahs, or religious leaders, govern Iran. And monarchs or other hereditary rulers reign in the other states.
Without the soothing influence of functioning democracy, differences in perspective between rich and poor, secular and devout can lead to social instability. So can conflict among ethnic groups, and it does. In the context of the Islamic Resurgence, which we will discuss shortly, it is highly unlikely that any of those countries would have a democratic revolution. To the contrary, the rising turmoil in the Middle East is being inspired by religious revival. It is more likely that new governments will be, like Iran, theocratic.
This, of course, leads to the last key similarity among the countries of the Persian Gulf. Their peoples are strongly Muslim.
Muslim: For reasons we will now venture to discuss, religious traditions and beliefs are a main cause of its potential political instability in the region. Islam is a mixed religion, with many variants of belief and practice. Everywhere you look in the Islamic world, however, the religion is growing in strength, intensity and numbers. This is part of the Islamic revival.
Radical groups in the Islamic revival are now calling again on the ancient idea of jihad. But for the time being, at least, the jihad is directed against “un-Islamic” states. In today’s context, that doesn’t only mean the nations of the west. “For revivalist writers, un-Islamic regimes include those ruling in most Muslim countries,” wrote Sohail Hashmi.
“The immediate goal of the revivalist jihad is to replace hypocritical leaders with true Muslims. Only when this long and painstaking internal struggle has succeeded in re-establishing an authentically Islamic base can the external jihad resume. Thus jihad is today largely synonymous with Islamic revolution in the works of most Muslim activists.”
“The strength of the Islamic revival can only be understood,” proposed Francis Fukuyama, “if one understands how deeply the dignity of Islamic society had been wounded in its double failure to maintain the coherence of its traditional society and to successfully assimilate the techniques and values of the West.”
The revival is also known as the Islamic Resurgence. It first became visible to the West through a popular uprising against a Shah who had spent most of his adult life trying to Westernise Iran. As we have seen, that revolution led to the second oil price shock. Later manifestations of the Resurgence included Afghanistan’s collective effort during the 1980s to repulse the Soviet Union and, six years later, its rebarbative Taliban government.
The Islamic Resurgence is similar to the Protestant Reformation of the sixteenth and seventeenth centuries in many ways. And its impact on human history will be at least as profound as were the American and French Revolutions, says Samuel Huntington. “The Islamic Resurgence is...a broad intellectual, cultural, social, and political movement prevalent throughout the Islamic World,” he wrote. Huntington continued, “Islamic ‘fundamentalism,’ commonly conceived as political Islam, is only one component in the much more extensive revival of Islamic ideas, practices, and rhetoric and the rededication to Islam by Muslim populations. The Resurgence is mainstream not extremist, pervasive not isolated.”
But while it lasts, argued Brian Beedham, “Islam's revivalists will try to justify almost everything they say about politics and economics by quoting from the Koran and the stories of Muhammad's life; and those who argue with them had better be able to counter-quote.”
The Islamic Resurgence is especially important because, in relative terms, the economies of Islamic countries are growing faster than those of the West. Their share of the world’s Gross Economic Product (GEP) has risen by a factor of four since 1950, mostly because of oil. During that same period, the West’s share of GEP has declined by about 25 percent. If Islam and the West are likely to remain locked in combat, as this chapter suggests, it is worth noting that the Islamic world has unique strengths.
One is that their relative share of the planet’s GEP would increase if they could keep oil prices high without cutting production. This is a good incentive for international skulduggery.
Another is that Muslim populations are making great gains in literacy. This means the Koran, which is the best-selling book on the planet, is getting ever more widely read. Middle East birth rates are also high, which means increasing economic activity. It is also providing cadres of the young, who throughout history have been the shock troops of social change.
Most of the wealth being generated in the Islamic world comes from oil. From Nigeria to Kazakhstan, from Morocco to Indonesia, most Islamic countries are endowed with some level of petroleum wealth. And as we shall see, most of the world’s great oil reservoirs surround the Persian Gulf. These reservoirs are the big guns when oil becomes an economic weapon.
Not surprisingly, Saudi Arabia’s oil minister, Ali al-Naimi, rejected the idea that oil is a weapon that could soon explode. Rather, he protested, “those who propagate the issue of supply insecurity, dangers of import dependence and perceived instability of the Arabian Gulf are ignoring realities.” He argued that Saudi production came to the West’s rescue during the Iranian Revolution, the Iran-Iraq War and the Gulf War.[30]
However, as M.A. Adelman has authoritatively pointed out, during each of those crises the Saudis took advantage of market conditions to increase prices, rather than to “rescue” the West. Indeed, Saudi Arabia cut production to get top dollar for its oil. Some rescue package!
Since the purpose of a cartel is to get top dollar for the commodity under monopoly, these Saudi moves make perfect sense within the economic logic of cartel thinking. However, some ideas from Samuel Huntington, whom we have already encountered in these pages, suggest that factors beyond economic logic will affect future Opec “rescue operations.”
Huntington has provided a coherent intellectual framework to explain recent confrontations between Islam and the West. In his view, the collapse of the Soviet Union helped open up an environment in which conflict would take place between “civilizations” (cultures or groups of countries) instead of ideologies or nation-states.
“It is my hypothesis,” he wrote in his famous essay, "that the fundamental source of conflict in this new world will not be primarily ideological or primarily economic. The great divisions among humankind and the dominating source of conflict will be cultural. Nation states will remain the most powerful actors in world affairs, but the principal conflicts of global politics will occur between nations and groups of different civilizations ... Conflict between civilizations will be the latest phase of the evolution of conflict in the modern world.”[32]
Huntington worried that clashes would be particularly intense between the Western and Islamic civilizations. In a series of essays that include some discussion of this question, Brian Beedham proclaimed “the contest of the giants.”
“Islam claims to be an idea based upon a transcendental certainty,” he wrote. “The certainty is the word of God, revealed syllable by syllable to Muhammad in a dusty corner of Arabia 1,400 years ago and copied down by him into the Koran.... As a means of binding a civilisation together, there is no substitute for such a certainty.” He continued, “This is what has set scalps tingling in other parts of the world, especially among Europeans. They see the Last Ideology on the march. A Muslim crescent curls threatening around the southern and eastern edges of Europe. A new cold war could be on the way. And it may not stop at being a cold war.”
Whether cold war or hot, in a clash between the West and the Middle East each side will use whatever advantages it has to get its way. One of the keys to Middle Eastern power is the oil weapon.
In the following chapter we will see that this weapon is becoming more potent. At first, the principle seems to be a paradox: the more it shrinks, the more it grows. The more the world’s great reservoirs decline and the balance of oil production capacity shifts to the Persian Gulf, the more powerful the oil weapon becomes.
“Other factors remaining constant,” wrote American anthropologist Leslie White in the 1940s, “culture evolves as the amount of energy harnessed per capita per year is increased, or as the efficiency of the instrumental means of putting the energy to work is increased.” This simple but elegant idea became widely known as White’s Law. In the decades since, countless studies have shown how cultures tend to use more energy over time, or to use it more effectively.
During those same years, petroleum became the biggest and richest industry on Earth, and the wealth of the planet exploded in value. These are closely related phenomena, according to White’s Law.
Perhaps the bluntest picture of this social law is a simple graph that charts two bits of information from many countries. One axis indicates per capita oil consumption; the other, per capita GDP. Having created the axes, draw a dot for each country to show where it ranks according to both criteria. The inescapable conclusion from this exercise is that the more barrels of oil consumed by each of a nation’s citizens, the higher their collective per capita standard of living.
There are other ways to graph White’s Law, of course. The following chart shows world oil consumption per capita according to region.
Source: BP Corporation
As you can see, North Americans consume five times the world average of oil. Europeans, who have a lower though similar standard of living, get by with much less. This is because high taxes on gasoline and other fuels discourage consumption, real incomes are lower and distances are smaller than in North America.
The rapid decline in consumption in the former Soviet Union reflects three developments in that region. One is the shift to market pricing for oil, rather than the command and control pricing of the defunct Communist system. This resulted in better management of reservoirs that had been inefficiently produced, and in greater conservation of oil. A second is the fall in living standards in most of the former USSR. The third is a dramatic collapse in oil production – from 12.6 million barrels per day in 1988 to eight million barrels in 2000.
The following chart illustrates regional growth in world oil consumption. It vividly portrays recent changes in the world economy.
Source: BP Corporation
The economic boom during the Clinton presidency, which saw SUVs and pick-up trucks proliferate, took North American oil consumption to an all-time high. European consumption was stable. And consumption in the former USSR dropped.
Most noteworthy in this chart, though, are the other two lines. Economic growth in Southeast Asia fuelled burning growth in petroleum consumption. Demand doubled during the 25-year period. Demand also doubled in the rest of the world, which includes developing countries with large populations.
India, Brazil and China, for example, are developing large groups of middle-class consumers. “China provides an example of the potential impact that the developing economies may have,” Steven Pfeifer explained. “In 1994, Chinese oil demand per capita equalled only 0.9 barrels, well below the annual per capita consumption levels of 23 barrels in the US, 16 barrels in Japan and 14 barrels in South Korea. If China were to ... embark on a rapid industrialization programme, the potential impact on oil demand is daunting. China would require an additional seven million barrels of oil per day at an annual per capita consumption level of only three barrels per person.”
The most consistent growth in demand comes from the developing countries of the world, rather than North America, Europe and Japan. Oil consumption in Third World countries has fallen only once since 1970, according to Matthew Simmons – “by 100,000 barrels a day between 1979 and 1980. In the twenty-nine other years demand grew, despite wild price swings and economic turmoil.... Oil growth in the developing countries of the world enjoyed an average 30-year growth rate of four percent per year.”
The consumption graph shows how much oil the world has used in recent years, but the numbers are hard to really appreciate. To visualize the volume of physical oil the world consumed in 2000, imagine a tank one kilometre in diameter and five and a half kilometres high – almost two-thirds the height above sea level of Mount Everest. We burn or otherwise consume that much oil, each year.
How long is so much consumption sustainable? What are its economic implications? What are the geopolitical issues? The last point is the place to begin – the oil world’s geographical divisions.
Two men representing opposing powerbrokers duked it out in the summer of 2000, at the World Petroleum Congress. The congress is a high-profile gathering of Big Oil, which graces one of the world’s oil centres every second year. On this occasion, it took place under heavy security in Calgary, the headquarters of Canada’s petroleum industry. The occasion was an after-dinner debate in a posh downtown hotel.
At one mike was Dr. Rilwani Lukman, the respected and articulate secretary general of Opec. Lukman represented eleven oil-producing nations that rely on oil for both general revenues and economic growth. Nine of those countries are from the Middle East or Africa; the others are Venezuela and Indonesia. Opec’s member countries control about forty percent of the world’s oil production.
At the other was Robert Priddle, the equally respected and articulate executive director of the Paris-based International Energy Agency (IEA). Priddle spoke for the economically advanced consumer nations that – except for Australia, Britain, Canada and Norway – are net importers of oil.
Lukman said – and Priddle agreed – that low oil prices are not in the interests of either producers or consumers. Low prices mean low revenue, and prevent the petroleum industry from making the investments needed to keep oil production up. During years of low oil prices, high-cost domestic oil industries like those in North America have to shut in their wells and lay off their people. “Years of knowledge and expertise come under threat,” Lukman observed. “The fabric of the industry unravels.”
He tried to garner support from the industry crowd, which had benefited enormously from eighteen months of oil production cuts by Opec. These cuts had driven prices from $10 to $30 per barrel. Said Lukman, “The spirit of cooperation within Opec can strengthen the oil industry.” He declared that Opec is a “responsible, mature organization, sensitive to the needs of both producers and consumers.” Indeed, he suggested, his organization was not a cartel at all, but simply wanted to “provide solutions when the chips are down.”
The IEA’s Robert Priddle begged to differ. “Consumers cannot be expected to accept control of production by a cartel in the interest of price stability,” he proclaimed. While he agreed that $10 oil was not sustainable for producers, he emphasized that $30 oil was not sustainable for consumers. High prices can do economic damage to advanced economies, he said, but they can hurt poor countries more. In the year 2000 alone, for example, India would pay $6 billion more for oil imports than it had the previous year.
While Priddle found areas of agreement between himself and Lukman, he emphasized his key points on several occasions and in several ways. Governments must not manipulate supply and demand; it’s contrary to the free market economy. “The risks are too great – and the risks involve both consumers and producers.” Although he did not voice the word, global recession is one of the risks from high oil prices. Above all, Priddle said, he hoped Opec was listening to consumers: “Thirty dollars (per barrel) is too much.”
Priddle didn’t get a lot of sympathy from Lukman, who repeated one of Opec’s major gripes. “The governments of some industrialized countries make from taxes at least three times what oil exporters get from the sale of the raw crude oil.” Opec calculates that during the five-year period ending in 2000, oil taxes in the G-7 club of rich countries totalled $1.3 trillion dollars. By comparison, Opec’s total oil revenue was $850 billion.
This exchange illustrates what the geopolitics of crude oil has always been about: Power brokering to serve national interests. In this instance, Opec had the upper hand. The world’s economies were strong and ample supplies of oil were not readily available because of the cartel’s production cuts. As we have seen, disciplined action among the organization’s members and its allies had forced prices up – way up.
A cartoonist could have a field day with this encounter, which was a caricature of the high-stakes world oil game. Lukman represented a group of countries whose people by Western standards are mostly poor, and whose wealth comes almost entirely from oil revenues. And they wanted to use their collective power to drive prices up to serve the interests of their political leaders.
Priddle represented a group of rich countries, whose national treasuries do very well from excise taxes on gasoline. They wanted lower prices to keep their consumers happy, because their consumers are also their voters.
Oil executives and workers were strongly concerned about the issues, since they would fare better if Opec won the struggle for higher prices. And the small, poor, oil-importing countries of the Third World were not even invited to lunch.
You would expect an exuberance of optimism about the world’s oil potential at the world’s premier oil and gas forum, and it was there in spades. Indeed, two speakers drew chuckles by observing, respectively, that “the Stone Age did not end because of a shortage of stones” and “the Coal Age did not end because we ran out of coal.” Forecasts of shortages were nowhere in sight.
But since those heady days, other ideas have gained ground. Of particular importance are the compelling arguments that world oil production will soon peak, and thereafter decline. If this is true, it has profound implications.
Unless oil suddenly and mysteriously loses the great wealth-creating powers that are behind increasing demand for the stuff, when production begins to fade the psychology of the oil market will fundamentally change. No longer will there be unused supply capacity. In a seller’s market, surplus buyers compete for available supply, and prices are strong.
Many readers will undoubtedly greet with rolling eyes the suggestion that oil supplies are in trouble. After all, both authorities and screwballs have famously cried “Wolf!” on this issue many times in the last hundred years. Just after the First World War, for example, the US Geological Survey forecast oil shortages by the end of the 1920s.
A later (but more spectacular) such claim came from an international alliance of intellectuals who called themselves the Club of Rome. In 1972 they published the Limits to Growth, which quickly became an international bestseller.
That book tapped widespread fears about environmental and economic issues. It predicted that expanding world population and industrialization would exhaust the planet's fossil fuel reserves early in the twenty-first century. Using a ballyhooed computer model, it predicted that, as the twenty-first century creaked in, the environment would be stressed to the breaking point by pollution, population growth and resource extraction. In the book’s 1993 sequel, Beyond the Limits, the authors extend the ideas from the first volume. However, they moved Doomsday back by several decades.
Unknown to the Club as they prepared the original 1971 publication, US oil production had already gone into irreversible decline. And the year after publication, the first oil price shock arrived. The group appeared clearly clairvoyant. Of course, exploration, better technology and new petroleum development soon began to bring more oil into the market, and in the following decade the Club’s famous forecast became a notorious object of derision.
The rise of efficient global oil markets had turned oil into just another commodity, rather than the patrimony that many oil-producing nations had claimed it to be in the 1970s. Price now responded quickly to supply and demand.
Given a background of failed forecasts, it would be tempting for this author to leave the issue of world oil supplies alone. However, the arguments surrounding peak production are persuasive, and they have important implications for investors. One is that Opec will continue growing in strength.
Since the late 1960s, Opec’s actions have become an integral part of the petroleum price cycle, and a matter of serious interest to consumer, policymaker and investor alike.
Opec is now the only force that can maintain oil prices at levels that can keep producers happy. When the cartel fails in this effort, as it has done frequently since 1986, oil and gas indexes on stock markets around the world begin to crumble. When Opec succeeds, investors buy oil stocks. When Opec fails, they sell. As we shall see, Opec will succeed more often than fail during the coming decade. Get used to it: investors will be buying.
This is because Opec will soon reacquire command over world oil production. Command might take the form of a 35-38 percent share of the market – roughly its share of world production during the 1970s. When it reaches that critical mass, the cartel will again be able to engineer prices to suit its own needs. And its needs are simple: maximum revenue. The cartel owes no favours to the industrial world, and oil is the only important source of revenue for its member countries.
Since losing command of world production, Opec’s ability to manipulate prices has become complicated. Not only must it get its members to agree not to cheat on quotas. It must also deal with outside competition.
At this writing, world markets are again awash with oil: in a single year (2001), Opec and its allies announced cuts in oil production amounting to three million barrels per day. Because cartel members were once again cheating on their quotas, announcements of these cuts did not prevent the price of West Texas oil from staying below $20 per barrel.
The lower price of oil disguises Opec’s growing strength. Opec’s share of the world market has been increasing since 1985, and its growing strength has enabled the cartel to get such non-Opec players as Russia, Norway, Mexico and Oman to collude on production cuts. Greater muscle is on the way, because oil production is near its ultimate peak.
To appreciate that idea, consider that demand for oil has continued to grow long after huge fields stopped being discovered. It seems reasonable to believe that, if you stop adding new oil reserves while you consume ever-greater quantities of this non-renewable commodity, you will eventually run out of oil. Less obvious is the difficulty of predicting when that eventuality will arise.
Walter Youngquist, a geologist who has written widely on resource economics, is one of several important protagonists who have weighed in on this debate. He points to “two overriding facts.” The first is that “the world is now consuming about 26 billion barrels of oil a year.” The second is that “in new field discoveries, we are finding less than 6 billion barrels a year.”
There are only about forty “super-giant” fields – those with more than five billion barrels of recoverable oil. But those fields originally held more than half of the oil so far discovered. Twenty-six of those super-giants are in the Persian Gulf.
According to Youngquist’s analysis, half of the world’s 42 oil-producing countries have already reached peak oil production, and most of the rest will peak in the next few years. Barring a major recession, he argues, world production will top out in 2007, and then begin to decline.
Youngquist has suggested that only four countries will reach peak production after 2007. These are Iraq, in 2010; Saudi Arabia (2011); the United Arab Emirates (2017); and Kuwait (2018). (Iranian production, which began with a 1909 discovery and was the basis for the creation of the company that later became BP, peaked in 1973.)
This means countries hooked on imported oil will become increasingly reliant on a producing region increasingly dominated by the Islamic Resurgence. It also means the world will soon experience oil shocks induced by scarcity rather than politics, or by a combination of the two.*
The exact year in which world oil production actually peaks is important, Youngquist says. “But also important is the sobering fact that it will occur within the lifetimes of most people living today” – and much sooner than most of us expect. “There is little time left to begin to adjust lifestyles and economies to the coming post-petroleum era.”
Youngquist was one of the first of a recent crop of theorists to propose that crude oil supply is very near its peak. Another is Colin Campbell, who with Jean Laherriére published a wake-up call in The Scientific American in 1998.
The conclusion of this important paper was that “The world is not running out of oil – at least not yet. What our society does face, and soon, is the end of abundant and cheap oil on which all industrial nations depend.”
“Barring a global recession,” the authors wrote, “it appears that world production of conventional oil will peak during the first decade of the 21st century.” Using what they took to be best available information about 80,000 oilfields around the world, their estimate of when the world’s conventional oil supplies would begin to taper off used a technique first published in 1956. It took the form of the following chart.
As you can see, the Opec countries took the full hit when oil consumption declined in the 1980s, warping the Opec production curve. However, production from other petroleum provinces seems to be following the bellshaped curves that Campbell and Laherriére predicted. In late 2001, the industry learned that North Sea production had peaked, as the chart anticipated.
M. King Hubbert pioneered the methodology behind this graph. As the authors of the Scientific American article explained, Hubbert “observed that in any large region, unrestrained extraction of a finite resource rises along a bellshaped curve that peaks when about half the resources are gone.”
Many people have used Hubbert’s methodology. For example, Princeton University’s Kenneth Deffeyes began his career with Shell, where Hubbert was his mentor, and published a book titled Hubbert’s Peak in 2001. In yet another study of world oil supplies, Deffeyes gives more information about Hubbert’s famous prediction.
As Deffeyes explains it, in 1956 Hubbert stood before a technical gathering and predicted that US oil production would peak in the early 1970s, but his idea met with derision throughout the industry. However, geology eventually proved him right. US production peaked in 1970, and has never recovered. Because his mentor had called the event so precisely, Deffeyes describes that forecast of American production as “Hubbert’s Peak”.
With Youngquist and Campbell, Deffeyes calculates that oil production will soon reach its insurmountable summit. “After the peak, the world's production of crude oil will fall, never to rise again.” He continues, “The world will not run out of energy, but developing alternative energy sources on a large scale will take at least 10 years. The slowdown in oil production may already be beginning; the current price fluctuations for crude oil and natural gas may be the preamble to a major crisis.”[44]
In a sometimes charming and always erudite analysis of the problem, Deffeyes reminds us that the bell curve of statistics has a lot of applications. For example, Hubbert assumed that oil production in the Lower 48 states would eventually track just such a curve. Based on highly educated guesses about America’s total endowment of recoverable conventional oil (about 200 billion barrels), Hubbert calculated that the high point on the bell curve would define itself in the early 1970s. He was right.
Like Campbell and Laherriére, Deffeyes has created a chart forecasting the planet’s ultimate recoverable oil, which he estimates at just over two trillion barrels. According to his bell curve, the top will appear in 2005.
As was the case for Hubbert in 1956, those who are calling for a near-term peak in oil production are not getting much respect among politicians, academics and industry observers. Indeed, Campbell colourfully accused those groups (in no particular order) of an “amazing display of ignorance, deliberate ignorance, denial and obfuscation.” Consider the implications if the energy pessimists are right, as these pages assume to be the case.
Oil consumption has contributed to economic growth for almost a hundred and fifty years. As we have seen, high living standards are closely correlated to high levels of energy consumption. A decline in oil production could contribute to economic chaos in the world. Until a cheap alternative form of energy is created, for most of humanity it could represent the loss of hope for a better life.
Youngquist calls the present time the “petroleum interval” because it will be too short a segment of human history to be classified as an “age” – like the Stone, Bronze or Iron ages. During that interval so far, oil consumption has grown almost irrespective of price. Between 1973 and 1979, for example, the price of oil rose from about $2 to $30 per barrel. According to standard economic theory, such a huge change in price would dampen demand. Did it? Just the opposite: demand rose by nearly nine million barrels per day.
There have been exceptions, of course. In the rich world, oil demand fell by slightly more than seven million barrels per day during the years 1979 to 1983 – a huge and unprecedented drop. Then it began to rise again.
We will never know how much of the drop in demand within rich countries was due to $30 oil and how much was due to an awful fear that future prices were headed to $100 a barrel or more. It probably had more to do with the latter, because oil consumption continued to rise among the poor nations of the world – the nations you would expect to be least able to afford more oil in a high-price environment.
The case that world oil production will peak within the next decade is compelling. The counter argument often delivered by the executives of large oil companies is that if the price is right, they can always deliver enough product.
It has become common to use a pseudo-manufacturing model to describe oil and gas production. “The petroleum industry manufactures oil and gas from hydrocarbons resources,” BP executive Joseph Bryant explained. “Wells are just manufacturing facilities. Pipelines are like roads. If you have the capital to invest, you can produce more oil or gas.”
This approach reflects the limited time horizon upon which men and women in the oil industry tend to focus – often no longer than a fiscal quarter. It says that future oil resources are not a problem – they are just a function of investment.
In business that notion makes sense, because the business of producers is to get petroleum out of the ground as quickly and efficiently as possible. More than a century and a half of steadily increasing production has led to the complacent belief that the oil industry will always be able to produce ample supplies of energy, just as other industries have always been able to manufacture widgets.
This view also receives compelling support from pure economics. “No mineral, including oil, will ever be exhausted,” argues M.A. Adelman, who has given this idea its greatest theoretical punch. “If and when the cost of finding and extraction goes above the price consumers are willing to pay, the industry will disappear. How much oil is still in the ground when extraction stops, and how much was there before extraction began, are unknown and unknowable. The amount extracted from first to last depends on cost and price.”
Adelman points out that the production history of vinyl records, typewriters, vacuum tubes and buggy whips also formed bellshaped curves. But this was not because there was “nothing left to produce.”
Adelman is economics at its metaphysical best, and his ideas have strongly influenced government policy and industry thought. But the following chart suggests that the world is in for a ride on oil prices even if oil is, as Adelman has suggested, a “renewable resource.”
Source: BP Corporation
As the chart illustrates, even though Alaskan production went on stream in 1979 and production from the Gulf of Mexico, Canada and Mexico has continued to grow, North American production peaked in 1985. The chart also shows the huge drop in production from the former Soviet Union after 1990.
South and Central America reached peak production of 6.9 million barrels per day in 1998, and production from that region may already have begun to decline. The most recent large producing region to start fading was Western Europe’s primary petroleum basin, the North Sea.
The only areas where oil production has not peaked are Africa and the Asia Pacific (each with about ten percent of world production) and the Middle East, with thirty-one percent. Only the Persian Gulf could possibly bring on new oil production quickly, if needed. Opec’s share of the oil market is growing, making the world ever more reliant on the gulf.
That is a sobering fact even if you believe that the world has plenty of oil. Here are some more sobering facts, offered to support the idea that the Hubbert’s Peak of world oil production may indeed be soon upon us.
As this writing, the world is producing ninety percent of its oil from fields more than twenty years old, and seventy percent from fields more than thirty years old. New field oil discoveries peaked in 1965; the petroleum industry has been making smaller finds ever since, and the number of new finds is smaller, too. Furthermore, most of the world’s giant and super-giant oil fields have already passed their peak levels of production, and they are in decline. About half of the world’s oil-producing countries have already begun to fade, and the rest will soon follow.
“Global oil supply is currently at political risk,” said the Oil Depletion Analysis Centre in a brief to the British Cabinet. “This is because the sum of conventional oil production from all countries in the world, except the five main Middle-East suppliers, is more-or-less at the maximum set by physical resource limits.”
And the danger, they added, is double-edged. “World oil supply will soon be at physical risk. This is because the Middle-East countries have themselves little spare operational capacity, and this will be increasingly called upon as oil production declines elsewhere.”
The great producers of the Persian Gulf are becoming increasingly vital sources of oil. They will soon have the rest of the world by the balls, which they will squeeze for more money.
For a region of great social instability and widespread anti-Western sentiment to dominate freely trading oil supplies is an unnerving prospect. It means geopolitical events will become even more important than they have been in the past. It also means the West will become highly vulnerable to supply disruptions caused by social unrest in the Middle East.
If consumption continues to grow while production moves irrevocably toward its peak, the price cycle will undergo a fundamental change. The cartel’s efforts to strengthen prices will no longer have to wait for tight markets and stringent production controls. Markets will become chronically tight because of tight supplies, and even a bad case of hiccups in the world oil system could cause prices to jump.
Since supply and demand must always be in balance, the post-peak production world will be one of stiffer demand competition among buyers for declining supplies of crude oil. In that seller’s market, oil prices will rise to chronically higher levels than we have seen even in recent years. This is bad news for consumers.
The rise of a seller’s market will transform the price cycle as the cartel begins exercising control. “In a small, (oil-exporting), less developed country,” said M.A. Adelman in a discussion of cartel behaviour, “there is no conflict between its oil sector and the rest of society. All of the benefits of a higher price go to the local economy; the burden is borne entirely by foreigners. The government’s duty to its constituents – citizens, royal family, ruling party – is to charge all that the traffic will bear.”
As in 1973, Opec or even a small number of its members could send prices to the moon by merely threatening production cuts. So could revolution, as happened in Iran in 1979. So could war – like the eight-year struggle between Iraq and Iran, which began in 1980.
As we have seen, instability in the Persian Gulf is not new, and conflict between Europe and Islam is more than a thousand years old. But the nature of that instability and conflict is morphing into something new. Turmoil has often affected world oil exports and prices in the recent past, but the conflict took place either among nations or as part of a civil war. It was more predictable. It ended. And ultimately, diplomacy or the markets by themselves found solutions.
Under the new reality, terrorist acts against big oil pipelines or distribution terminals in the Persian Gulf could rattle world markets. Insurrections could lead to attacks on production and distribution facilities. This kind of disruption is already being done in many parts of the world – for example, revolutionaries in Colombia routinely blow up oil pipelines to cut into government revenues. This behaviour is only preventable at great cost, and it is impervious to short-term diplomatic solutions.
Is there a positive way out? Matthew Simmons, a US businessman served as an energy advisor to presidential candidate George W. Bush, and offered fascinating insights into global petroleum issues. Said Simmons, “There is a far more serious aspect of energy prices that many of our policy planners are missing. It is in the world’s best interest to keep oil prices in at least a $25 price range.”
In an environment of strong prices, he said, Opec producers could use the resulting prosperity “to create a genuine middle class. Much of the hatred towards America and the West, which is so prevalent in the Middle East, is due to the widespread poverty throughout this region.” What he does not discuss is that such developments would require a sea change in attitudes among the people who govern the Opec countries. That is highly unlikely: Think of Iraq and Nigeria. As we have discussed, Islamic revolutions or civil wars are more likely. Think of Iran and Sudan.
There should also be fundamental changes in attitude among the world’s consuming countries, Simmons added. “The widely held belief that Opec owes the world the benefit of lowering oil prices to bolster our fragile economy is very short-sighted, foolish and dangerous thinking,” he wrote. “The consumers of the western world need to grow up and face the realities of true energy costs and the demographics of Opec nations....”
Western consumers should also face the fact that the West is in a period of energy complacency like the one leading up to 1973. Low oil prices in the 1960s and early 1970s fuelled energy demand. And although industrial magazines frequently discussed the world’s tight supplies in those days, the mainstream media did not pick up the story until turmoil in the Middle East ignited an explosion. We should remember that.
We should also remember the activity of government policy-makers in the 1970s. During a period of volatile and steadily higher energy prices, they sought new and imaginative ways to divvy up the spoils, adding creative taxes and incentives into the economic brew.
For the oil industry, that is one of the big risks in the coming era of higher oil prices and declining production – just as it was in the seventies. Not everything was glum on the policy front in those days, however. Some people kept a sense of humour.
Take the case of Scoop Jackson, a Democrat and head of the US Senate’s Energy Committee. In the mid-1970s, his committee held hearings on the perceived energy crisis. Through those hearings the term “obscene profits” became part of the industry’s lexicon.
Recognizing an opportunity, the American government legislated its revenue-grabbing Excess Profits Tax. In America, state governments also took other steps to increase revenues in the name of protecting consumers.
In Europe oil production was a relatively small industry, so that region’s producers emerged relatively unscathed. However, Canada’s 1980 National Energy Program (NEP) gets the blue ribbon for the worst timed and most destructive energy legislation in the Western world.
The NEP was packaged for the electorate as a policy based upon “energy security, opportunity and fairness.” In a world apparently facing an energy crisis, the framers of the policy wrote, “We need not face an uncertain supply of oil. Nor do we have to suffer economically as badly as other nations who lack our energy potential. If a way can be found to share more equitably the benefits of Canada’s energy resources, it may be possible to insulate Canada from some of the shocks emanating from the world economy, and to build upon this energy strength an industrial base in all parts of Canada that will provide for sustained economic growth.”
The policy was based on assumptions about the need for national control over a strategic industry, the critical importance of developing expensive oilfields in the Canadian frontiers, and the virtual certainty of ever-increasing oil prices. In practice, the policy encountered lower oil prices almost from the day Finance Minister Marc Lalonde introduced it as the keystone of the federal Budget.
Foreign oil companies happily sold their Canadian assets to Canadian companies at inflated prices – receiving $4.8 billion in 1981 alone. Canadian companies borrowed heavily for the privilege of acquiring overpriced assets, and paid astronomical interest rates for doing so.
Government-funded cash grants encouraged Canadian explorers to spend heavily and fruitlessly in costly drilling in the North and the offshore frontiers. Not a single important frontier discovery took place during the NEP era. Fertilized by government grants, frontier drilling and exploration costs grew dramatically.
A government-owned oil company, Petro-Canada, was active in the hunt. Indeed, Petro-Canada’s rapacious appetite for private sector oil companies led government to encourage the company to invest more than $7 billion in overpriced assets. Twenty years later, the privatised corporation’s market capitalization was about $9.5 billion, and thus reflected a poor return on those original investments.
The NEP spilled an alphabet soup of new taxes and incentives on the industry. The purpose was to simultaneously mop up money and influence how and where Canadian exploration and development investment would be spent. The expensive National Energy Program was intended to increase general revenues and to fund its own programs, which included subsidizing oil imports.
An odd part of the policy (imported from the Americans) was that of placing price controls on domestic oil production to subsidize foreign imports. This increased demand while discouraging domestic production. Buy-high, sell-low schemes eventually collapse, and the National Energy Program was no exception. As it burst into flames, it burned investors, taxpayers and the industry alike.
The program’s excesses were many. They included the grants, the Petro-Canada takeovers and – notably – the projected revenues from high oil prices that did not materialize, but were spent anyway. Taken together, they contributed hugely to Canada’s national debt. And for good measure, the NEP exacerbated the severe recession of 1981-82, thereby burning workers and consumers, too.
The moral, of course, is that energy crisis can unleash the hounds of bad policy. If another period of panic about oil supplies develops, governments may create other aggressive energy plans. Politicians could again come to invoke the nostrum of protecting consumers (also known as voters) as an opportunity to raise government funds. This is known as political risk.
Fortunately, energy policy since the early 1980s has been either benign or progressive. It has certainly transformed the industry, with many initiatives originating in the United States. When America deregulated its energy systems, Canada had to catch up.
The last major innovation in North American energy policy arose from America’s National Energy Strategy, undertaken during the first Bush Administration. Vito Stagliano was a senior policy advisor on energy during that period, and wrote an authoritative history of that legislation in the larger policy context. Stagliano argues that neglect of policy by the Clinton Administration skewered much of the intent of the original policy.
Said he, “Neglect of policy has consequences. During the Clinton Administration, in the absence of policy intervention the petroleum market evolved in the direction that (the National Energy Strategy) had intended to prevent. U.S. oil consumption rose from 17 million barrels per day in 1990 to nearly 20 million barrels per day in 2000. During the same period, domestic oil production fell from 7.3 million barrels per day to 5.8 million barrel per day. US oil imports rose from about 8 million barrels per day in 1990 to nearly 9 million barrel per day in 2000. Most critically, imports from members of Opec, the only producers with excess capacity, rose from 4 million barrels per day to 5 mission barrels per day in the same period.”
As a result, he said, “the members of Opec in 1999 once again took control of the international oil market. They succeeded in doing so by finding the will that had eluded them for two decades: they disciplined their output and, at greater risk to consumers, actually matched supply to demand.”
Where is the humour in all this? In a New Yorker cartoon from the mid-1970s, one balding businessman explained the facts of life to a colleague. “I’ve been in business forty years,” he intoned, “and I have never seen an excess profit.”
Spare a thought for the Great Pyramid of Cheops, constructed on a dusty plain in Egypt 4,500 years ago. That project was one of the great engineering and management achievements in all of history.
This marvel of design, Morgen Witzel reminds us, “was built with a technology just coming out of the Stone Age. Copper saws and chisels were used for finishing work on the site, but each of the 2.3 million limestone blocks that make up the structure was quarried using dolorite hammers and cutting tools. Each block then had to be moved from the quarry to the building site by hand, using wooden levers and rollers and with nothing for motive force beyond manual labour. The economics of the project were equally primitive: money had yet to be invented, and labour, tools and materials had to be paid for in goods.”
The Great Pyramid was possible for many reasons. Pharaoh’s subjects were great in number. The society was wealthy, with crops and livestock to tax in kind. Workers had access to recent advances in technology – copper chisels, for example. And Pharaoh’s administrators developed an effective seventeen-tier bureaucracy.
In other words, they had capital and management, labour, technology, resources and raw materials. In that sense, the requirements for erecting great edifices have changed little in more than four millennia, except in form. Of course, the great constructions of the twentieth century did not focus on sending people to the afterlife in style (excluding, of course, large military systems). Rather, they focused on meeting consumer demand.
Take an enterprise that attracts fewer tourists than the Great Pyramid but is far more essential: the system that delivers natural gas to your furnace. If you don’t live in a large gas-producing region like Alberta or Texas, your fuel could come from almost anywhere on the continent. How is such a vast materials-handling system possible?
Until after the Second World War, natural gas was a local heating and lighting source. Short pipelines served small regions, and most homes and businesses still used coal or oil for heating. Today it is a powerful continental commodity. Most of North America’s petroleum basins have been connected to its large population centres, and people consume natural gas with a great deal of confidence that supplies will not run out.
For this system to operate reliably requires a steel-cased network of pipes and storage facilities. At the wellhead, that system tames natural gas, which can roar from a well at rates of more than 75 million cubic feet per day. And it enables gas to flow through a copper tube into your hot water heater weeks or even months from now, after travelling thousands of miles from its source. You would need about one thousand of those cubic feet to keep your house warm on a cold winter’s day.
The pipelines that deliver gas are intricately interconnected. They are controlled by a dazzling array of remote sensors, electronically controlled valves and computer systems. Molecules from a well in the Northwest Territories are seamlessly switched to furnaces in Montreal, New York and San Francisco. So sophisticated has this system become that natural gas prices are nearly the same no matter where you live. Freight and service are extra.
Will there be a Hubbert’s Peak for natural gas supply? The answer is undoubtedly “Yes,” but a key assumption of these pages is that such an event is many years away.
Crude oil’s sister, natural gas, is thus getting prettier as she matures, and she remains reliable. Since supplies are expected to be ample for ten years and demand growth is brisk, North American gas producers will deliver ever-larger volumes of this vital commodity. Increasingly, those supplies will come from Canada and, after 2010, Alaska.
And a lot of gas is at stake. According to many forecasters, by 2010 the US alone will consume 29 trillion cubic feet, per year. At two dollars per thousand (a modest price in recent years), a trillion cubic feet would be worth $2 billion. The math works whether you use Canadian or US dollars.
Because of rapid depletion in older gas reservoirs, a great deal of activity has to take place in the field to meet both existing and growing demand. This capital-intensive activity (explained in some detail in Chapter 6) will require historically high natural gas prices. And because producers will be both selling more and fetching higher prices in their sales contracts, the sector will experience explosive growth.
Why will prices be higher? We will first discuss the matter of supply, beginning with the situation in the United States. We will later discuss demand.
Matthew Simmons, whom we met earlier in this book, made a good call on the energy disasters of winter 2001. For an extended period, California suffered rolling blackouts; then the worst cold on record attacked the United States. These events helped send natural gas prices to unprecedented levels.
Simmons is one of the authors of a major study of US gas supply, released in 1999. Commissioned by America’s National Petroleum Council (NPC) for the Department of Energy, this study investigated whether, during the near future, there would be a balance between natural gas supply and natural gas demand. Said the authors, there would.
Less than a year later, Simmons had changed his mind. As he told an industry audience, “Over the years, the industry’s wonderful can-do attitude, coupled with an over-cautious mindset that prices will never rise, created an industry-wide blindness to the many energy problems looming over the horizon, and the train wreck about to occur in the energy markets.”
Simmons’s comments were quite technical, as an industry audience would expect. “It is becoming clearer with each passing month that we grossly underestimated the demand pressures facing natural gas,” he said. “We also used some very optimistic assumptions on how the supply would occur, not only in access-related issues but by also using only modest decline rates throughout most basins of North America. In my opinion, the report grossly underestimated the number of rigs needed to get these reserves out of the ground. I also suspect the cost estimates used to grow the physical infrastructure to meet a 29 or 30 trillion cubic foot per year market by 2010 were far too low.”
During the previous election, Simmons had served as an advisor on energy policy to candidate George W. Bush. Simmons gave his speech just after the presidential election, at the beginning of a period during which, for a few brief months, North America was transported back to the 1970s. Cries of “energy crisis” echoed through the land.
The new US Administration saw an urgent need for new energy policy. President Bush and his vice president, Dick Cheney, had serious backgrounds in the oil and gas business, and they wanted to signal early that energy was a key concern.
It is worth noting that energy policy had undergone complete neglect during the Clinton Administration. The energy policy of the second Bush Administration would be the first in ten years. The previous American energy policy was the National Energy Strategy of George Bush Sr., who guided the legislation through Congress and saw it passed in 1992. That legislation was a landmark event in the deregulation of North America’s energy markets, but so was Clinton’s neglect.
In a preliminary poke at the issue, Bush assigned Cheney to be the point man on energy issues, early in his term. He also created a National Energy Policy Group, which consisted of the most powerful people in his Cabinet.
Vice President Cheney issued a report just four months later. “America’s energy challenge begins with our expanding economy, growing population, and rising standard of living,” he said. “Our prosperity and our way of life are sustained by energy use.”
“Estimates indicate that over the next 20 years, US oil consumption will increase by 33 percent, natural gas consumption by well over 50 percent, and demand for electricity will rise by 45 percent. If America’s energy production grows at the same rate as it did in the 1990s we will face an ever-increasing gap.”
In many speeches, Cheney described energy as a "storm cloud over the horizon...that has lately taken on an urgency not seen since the 1970s.” Cheney's solution was to drill more, mine more, generate more and build more nuclear plants. He gave a nod to conservation, but mocked it slightly as a gesture of personal virtue. In practice, he suggested, conservation and alternative fuels were not likely to slow the growth in America’s hunger for natural gas – at least, not substantially, in the near term.
Many environmental groups were outraged with Cheney’s proposals, and the energy markets offered no encouragement to Cheney’s doomed crusade. Surpluses rather than shortfalls began to appear. Oil, natural gas and power prices began to decline, with price drops escalating near year-end 2001. Cheney’s star in the political firmament dimmed shortly after that debacle. There was no longer any talk about him serving as Prime Minister to George W. Bush’s President.
Timing was not kind to Dick Cheney, whose opening energy crisis campaign was greeted with plummeting energy prices, followed by political crisis when it turned out that the failed Enron Corporation had been the biggest contributor to the Democratic Party and to the Bush-Cheney ticket in the recent presidential election.
What had seemed like insurmountable obstacles in the winter of 2001 seemed to magically fix themselves. For example, California had suffered rolling blackouts and severe power shortages, and the state’s natural gas prices reached record levels of US$32 per billion British Thermal Units (BTUs). By the end of September, the state could export electricity, and natural gas prices were toying with their two-year lows.
Some people have suggested that natural gas prices experienced a “perfect storm” in the winter of 2001. The cold weather and the California situation were two factors leading to record highs. Strong economic growth across the continent was another. And both the United States and Canada had done relatively poor jobs of replacing gas reserves during the previous few years.
This was partly because commodity prices had been low and partly because oil and gas shares were chronically cheap. Petroleum predators had found it more rewarding to acquire other companies than to aggressively drill for natural gas.
These developments notwithstanding, “US natural gas production (and net imports, mainly from Canada) is likely to increase sharply over the next two decades,” said America’s Energy Information Administration, a politically independent government body.
The agency cited “economic responses to strong natural gas demand,” by which it meant that individual operators develop more gas when prices are good. In addition, the IEA noted that the resource potential in North America is still large, and that unconventional and offshore natural gas recovery technology has greatly improved.
Scott Reeves is a vice president of Advanced Resources International, a Houston-based based consulting firm that specializes in unconventional hydrocarbons. He lists the forms of unconventional gas as tight sands, gas shales, stripper gas, deep gas and coalbed methane. “Unconventional gas is the fastest-growing source of US natural gas supply,” he said. “The aggressive pursuit of cost reductions has turned unconventional gas into an economic commodity.”
At the beginning of 2002, Reeves cited the Energy Information Agency’s forecast that the long-term contribution of non-conventional gas to the US gas supply will increase from the present 5.6 trillion cubic feet per year to almost nine trillion cubic feet by the year 2020. To reach that level of production, Reeves said a lot of things had to go right.
The resource base would have to grow – for example, there would need to be new developments in the Rocky Mountain Region. There would also have to be improved and more efficient exploration, better performance from future wells, plus “lower cost development and operations, and new, breakthrough technologies.”
That’s a tall order.
Conventional natural gas is the stuff that has been on production for more than one hundred years – initially for light, heat and industrial energy. Later it became an important petrochemical feedstock in addition to being an industrial and residential fuel.
It is worth remembering that non-conventional development began more than fifty years ago, with early sour gas development. Shell’s Jumping Pound facility (completed near Calgary in 1951) owns many sour gas firsts.
Sour gas is natural gas contaminated with hydrogen sulphide, or H2S. If you inhale one million parts of air mixed with five hundred parts of H2S, you will die within minutes. This is deadly stuff, and the industry’s first big non-conventional challenge gas was to remove it. Today, that chemical is removed at the gas plant’s sulphur facility, and sour gas is a large part of the gas business.
Because of the size and extent of her sour gas resources, in this area Canada leads all others. This is not the case in coalbed methane and production from tight sands, where the US is the clear leader. As Canada’s industry begins developing unconventional gas, it will use a great deal of American technology.
Tight Sands: Tight sands are rock formations that require well stimulation before they can produce much gas. Individual wells on these formations do not produce huge amounts of gas, but they can produce gas for quite a long time. In addition, some of these reservoirs are located in regions where there are a lot of different gas plays, often directly above and below each other.
In the best tight sand supply regions, operators can produce gas from several geological formations simultaneously, and frequently from the same well. That is why small but geologically favourable areas can provide large reserves; they can be the company-maker for small operators with the vision, money and technical skills to develop them.
Coalbed Methane: Until recently, coalbed methane was considered an exotic commodity. Coalbed methane is natural gas produced from coal reservoirs. It exploded in the 1958 Springhill Mine Disaster, which was memorialised in song, and the 1992 Westray Mine Disaster, which was not. In the early 1990s, commercial production began in the San Juan Basin, where New Mexico, Arizona and Colorado meet. Since that time, coalbed methane has become responsible for about 7 percent of American natural gas production. This is impressive growth, but coalbed methane is still far behind tight sands gas, which accounted for x percent of US production in 2002.
Deep Gulf: The other important new source of natural gas in the Lower 48 states is the Deepwater Gulf of Mexico. “Five to ten years ago, if you came to me with the idea of a directional well that stretched 25,000 feet...I'd have said you're dreaming,” said Brian Kuehne, of Royal Dutch/Shell. “But today, we're just kicking them down one after the other.”
This is one example of technology making it possible to find and develop big oil and gas fields below 1600 metres of Gulf water. Technology is also making it possible to produce one reservoir with fewer wells. For example, Shell could develop its Mensa gas field in the Gulf with only three subsea wells, compared with the forty that would have been required ten years ago. Since drilling is the biggest development expense, such advances greatly improve field economics.
For the Americans, the only other domestic source of new gas production available is Alaska. Unfortunately, economics will probably not justify a pipeline connection to the Prudhoe Bay gas fields – a US$17 billion project – until after 2010. The world’s biggest natural gas market will therefore have to import more gas, but those imports will not come from Mexico.
The reason is that Mexico’s Popular Revolutionary Party nationalized the country’s oil industry in the 1930s, and the result has been a bit like an old Keystone Kops movie. Profits from the sale of oil go into government coffers, and the government allocates what revenue it can afford back to Pemex for capital investment. In other words, energy investments depend on the Federal Government’s budget. In this environment, there is never any money for natural gas projects. Shrugged Javier Estrada, commissioner of that country’s Energy Regulatory Commission, “Gas projects compete with oil projects, and don’t win.”
Mexico therefore imports this commodity, despite the country’s excellent natural gas potential. Total Mexican gas consumption will increase from almost 1.5 trillion cubic feet per year at present to 3.5 trillion cubic feet in 2010, Estrada says. And by 2010, Mexico will import 150 billion cubic feet from the United States. Another half a trillion cubic feet will arrive by liquefied natural gas tanker, from overseas.
If the United States cannot import gas from Mexico, and Alaska will not be connected for at least a decade, the country will become increasingly dependent on imports. Some of that supply will come from overseas, although the economics of liquefied natural gas imports depend on historically high natural gas prices.
Transporting gas by tanker from Algeria, Indonesia or Trinidad can be quite profitable at about $US3.00 per thousand cubic feet of gas. However, because of the costs of liquefaction and transportation new import facilities are unlikely at much lower prices. This economic reality will place a lid on the price of North American natural gas for the first decade of this century. So doing, it will also keep an Alaska pipeline uneconomic. As we shall see, Canada would be the major beneficiary if that situation developed.
One of the themes of these pages is that Canada’s gas industry is likely to grow more rapidly than America’s during the coming decade. In general, therefore, Canadian gas companies will continue to outgrow their American counterparts.
Canadian gas companies have been doing so since 1985, when market rule in natural gas started to become reality. In only fifteen years, Canadian exports to the United States rose from three percent to fifteen percent of total US demand. This is possible because of the combination of Canada’s huge resource base and its small population: Despite the cold climate, Canadian gas consumption is only x percent of that in the United States, so America is the only available market for most of Canada’s natural gas potential.
Canada’s inventory of natural gas prospects and properties is vast and varied, and so is the necessary expertise. The only barrier to entry is the need for capital, and in Western Canada you frequently don’t need too much of that. Highly successful companies have begun with seed money of half a million dollars and less. A later chapter will discuss private investment, which can be quite profitable. In the meantime, we will discuss Canada’s major sources of natural gas.
Western Canada: The Western Canada Sedimentary Basin, which is part of the huge sedimentary belt that begins in the Gulf of Mexico and stretches northwest to the Beaufort Sea, offers an unusual array of opportunities. For example, it houses the world’s largest known crude oil resource – Alberta’s vast oil sand deposits, which these pages explain elsewhere. It is also has some of the most prolific natural gas basins in the world.
Natural gas production takes place in many guises in Western Canada, from the Saskatchewan and Alberta borders with the US to the nexus of British Columbia, Yukon and the Northwest Territories. A single well can cost as little as $100,000 along the border between Alberta and Saskatchewan. It can cost $10 million and more in the Rocky Mountain foothills.
Of course, production volumes also vary greatly from well to well. Some new wells produce a few hundred thousand cubic feet of gas per day, and dwindle out in less than a year. Others start depleting the field at 50 million cubic feet per day, and continue producing large but declining rates for years. Big wells generally cost a lot more.
As the following chart shows, natural gas drilling and exploration experienced almost explosive growth in Western Canada in the decade after the Gulf War. The reason is that new pipelines made the profitable US market more accessible, thereby mopping up surplus Canadian supplies. Greater demand meant more drilling to meet the market’s needs.
Source: Daily Oil Bulletin
The Mackenzie Delta: Follow the broad Mackenzie nine hundred miles north from its headwaters in Great Slave Lake, and you will eventually reach the place where the river breaks upon a hundred islands, spilling its contents into the Beaufort Sea. Over the ages, the northward flow of waters laden with organic material and sediment helped create geological formations that have become a vast hunting ground for natural gas. So far, exploration has established xy trillion cubic feet of gas reserves in the Mackenzie Delta.
Natural gas from the Mackenzie Delta could be transported to southern markets more cheaply than the huge reserves in Alaska. Here is why.
All three of the Alaska pipeline proposals made in recent years would require laying huge, high-pressure pipe over a long and difficult terrain. The proposal favoured by the Alaskan government would cost US$16-20 billion. It would deliver 4-6 billion cubic feet of gas per day, threatening to glut gas markets if constructed too soon.
Because the distance is shorter and much of the terrain less difficult, the proposals for pipelines from the Mackenzie Delta are much less costly. To use one of those projects as an example, at a cost of C$4 billion (US$2.5) it could deliver one billion cubic feet of gas per day to the transcontinental pipeline grid. And some proponents have considered even smaller projects to bring Delta gas to market. The Canadian contenders could thus deliver gas more cheaply per unit of energy, and without flooding the market.
Nova Scotia: In recent years, Nova Scotia has become a player in New England natural gas markets. A spanking new offshore gas project delivers natural gas to buyers in the Eastern United States, and is developing markets in Nova Scotia and New Brunswick. After more than 30 years of offshore exploration activity, natural gas from the province's first offshore project began to flow at yearend 1999. The first field to go into production was discovered in the 1960s on Sable Island, 300 kilometres southeast of Halifax in the Atlantic Ocean. The island’s boundaries shift each year with the ocean currents, and its fame comes from a herd of wild horses introduced nearly two centuries ago.
The $3 billion project developed six major natural gas fields that lie 10 to 40 kilometres (6 to 25) miles north of the edge of the Scotian Shelf. The publically traded owners of this project are major multinational oil companies (Shell and Exxon Mobil), but smaller companies are developing interests in this area, which is becoming an important production centre. Interest in exploring Nova Scotia's oil and gas potential is growing.
EnCana and other companies have made additional large gas discoveries offshore Nova Scotia. That will continue, and Scotian Shelf gas development will be an important source of growth for EnCana and other large and intermediate gas producers. As we discuss elsewhere, growth from such projects can have a powerful impact on a company’s share price.
Now, let us introduce a new concept: seasons, which are a market cycle driven by the sun. Crude oil is primarily a summer fuel, because gasoline demand peaks during the driving season. By contrast, natural gas demand peaks in winter, especially as Arctic cold moves down the continent. Gas is also a summer fuel, but to a much smaller extent. There are bulges in demand for gas in the summer during hot spells. People turn up the air-conditioning in a heat wave. The electricity needed to power more air conditioning increases the demand for natural gas, which fuels many electricity-generating turbines.
Natural gas is the ideal fuel for electricity generation, because new-generation turbines are very efficient and create little environmental disturbance. This means they can be installed quickly, without many regulatory hassles and delays.
This has greatly increased demand. The use of gas for electricity grew rapidly during the 1990s, when natural gas prices were low. As Cheney and others have suggested, however, available natural gas supplies are now tenuous. The gas market must seek out new basins as sources of supply. This means Alaska and the Canadian Arctic.
In the meantime, the winter of 2001 showed how chaotic an extremely cold winter could be. There were disruptions in supply in some parts of the United States, and prices skyrocketed. Petrochemical plants in particular found it to be more profitable to resell the natural gas they had on contract than to operate normally, even with staff receiving full wages. If there is little reason for optimism about near-term gas supplies, as Matthew Simmons suggests; a severe winter might soon arrive in which conditions become even more frenzied. As occurred in 2001, these weather events could create severe distortions in the larger economy.
Fortunately, North America’s natural gas potential isn’t close to reaching its peak. Besides the huge volumes produced in America’s lower 48 states and Canada (the US and Canada are the world’s first and third largest producers, respectively), there are vast untapped supplies in Alaska and the Canadian North. Mexico also has huge gas resources, but won’t yet let anyone develop them but its national petroleum company.
To bring gas from Alaska and Northern Canada is going to take a great deal of money, because the cost of a major pipeline into the complex environmental conditions of the north will cost an estimated US$10 billion. To justify those costs, natural gas from Alaska or the Canadian Arctic will require a natural gas price of US$3 per thousand cubic feet. Since several consortia have northern pipelines on the drafting table, we can be reasonably confident that their member companies are confident that gas prices will remain at this very attractive price.
Another reason we can feel reasonably confident is that natural gas prices are closely tied to those of oil. When oil prices go up, so do natural gas prices. This means natural gas prices will be affected by turmoil in the Persian Gulf and, over the longer term, by the decline in global oil production.
The potential for terrorism also should not be overlooked. Two months into the War Against Terror, the US State Department alerted natural gas pipeline companies that it had received warnings of possible attacks on the gas industry if Osama Bin Laden were killed or captured.
DYNEGY'S WHOLESALE GAS AND POWER SEGMENT IS COMPOSED OF POWER GENERATION, AND NATURAL GAS AND POWER MARKETING AND TRADING. This segment is focused on energy convergence — the marketing, trading and arbitrage opportunities existing between natural gas and power, which can be enhanced by the control and optimization of related physical assets.
According to Michael Walker, “Regulatory convergence, like the convergence of the industries which these regulatory bodies oversee, is happening fairly quickly at the state, federal and international levels. Regulatory convergence represents a major transformation in the role and structure of regulatory bodies. The examples of regulatory convergence cited in this case study represent a trend which is bound to accelerate in the future. The challenge will be to set up a new regulatory regime which truly reflects the market, and more importantly, the interests of the industries and consumers which regulators are sworn to serve.”[64]
In recent years, there has been a melding of natural gas assets and electricity assets in the United States. Mergers and acquisitions between companies primarily involved in electricity or natural gas have been the principal route by which the "convergence" of gas and electricity supply is being accomplished. Perhaps the most dramatic manifestation of the trend toward convergence is the merger/acquisition of natural gas transmission and distribution companies by electric utility companies. For example, there were 17 convergence mergers in the past 4 years. [Note a] During this period, six transactions were completed in 1997, followed by two additional mergers in 1998. In the next two years (1999 and 2000), three and six mergers were completed, respectively. At the time this report was being written, six additional transactions were pending. Note b] Concomitant with the convergence of natural gas and electricity assets, a new form of energy company has evolved--the energy services company. Energy services companies appear to have evolved in response to US electricity restructuring and natural gas deregulation and have become more widespread as increased competition has encouraged these operations to combine. Energy services companies have greater flexibility to market both electricity and natural gas interchangeably, thereby having the opportunity to maintain and/or increase their customer base. Other benefits achieved through mergers could be improved efficiency, lowered operating cost, and the opportunity to participate in the growing market for natural gas-fired power plants. [Note c] Energy services companies have little resemblance to the conventional view of a major US energy company. The conventional view is a vertically integrated petroleum company that also produces natural gas. However (as shown in the preceding Special Topic), the number of vertically integrated petroleum companies has declined in recent years. At the same time, the energy services companies have grown rapidly, perhaps signalling a fundamental change in the characteristics of a major US energy company. [Note d] The FRS survey group in 1999 contains four of the leading energy services companies in the United States: Enron, Williams Companies, El Paso Energy, and Coastal (pending merger with El Paso Energy in 2000). All of these companies have similar natural gas operations and energy marketing and services operations. For example, Coastal, El Paso Energy, and the Williams Companies have operations in the exploration and production of natural gas, gathering and processing, and transportation and storage. Enron had similar natural gas operations with the exception of natural gas gathering and processing services in 1999. All of these companies' energy marketing and services operations are generally conducted through subsidiaries and/or affiliates, which engage in the buying and selling of energy commodities, such as natural gas and electricity. These four companies have operations in natural gas-fired power generation and cogeneration and in electric utilities. For example, Coastal has cogeneration operations in the United States and abroad, particularly in Latin America and Asia. Note e] El Paso Energy has investment activities in natural gas-fired power generation in the United States and abroad, particularly in Asia, Europe, and Latin America, and geothermal operations in the United States. El Paso Energy also acquired cogeneration facilities through its merger with Sonat. [Note f] As a result of its purchase of Portland General Corporation in 1997, Enron became the largest wholesaler of gas and electricity in North America, but has now announced plans to divest the electric utility in 2000. Nonetheless, Enron will continue to buy and sell natural gas, electricity, and services through its subsidiaries. Enron also has natural gas-fired power plants in the United States. Abroad, the company has power operations in Europe, South America, and Asia. [Note g]
Max Cohen focused strongly on his key assumptions, which were three. “Number one, math is the language of nature,” he said. “Two, everything around me can be represented and understood through numbers. Three, if you graph the numbers of any system, patterns emerge. Therefore, there are patterns everywhere.”
“So what about the stock market?” he asked. It is a “universe of numbers that represents the global economy, millions of hands at work, billions of minds, a vast network screaming with life, an organism, a natural organism.... Within the stock market there is a pattern, right in front of me, hiding behind the numbers, playing with the numbers. Always has been.”
Cohen (played by Sean Gullette) is the lead character in a stylish art film called “p” (“Pi,” in the Roman alphabet). As the action unfolds, he realizes the answer lies in a 216-digit number. Bad people also want that number, so they can cause the stock market to crash. So do some Kabalarians – Jewish mystics who believe every word, letter and number in the Hebrew Scriptures contains mysteries only interpretable if you know the secret. To them, the number will reveal “a single word, the True Name of God, which was 216 letters long, and the key to the Messianic Age.”
But in the end, Cohen explained, “The number is nothing. It is the meaning, the syntax, what’s between the numbers” that counts.
And so it is with petroleum stocks. Their prices reflect many things: the raw emotions of fear, hope and greed; changing commodity prices; the vagaries of geology and geography; the success of steel pipe and equipment, and its failure; managerial triumph and perfidy. Yet all of this can be captured as patterns on graphs.
These pages argue that stock market patterns offer opportunities for the investor to invest in the oil and gas business cycle, as calibrated by stock market indexes. If you understand the patterns of the stock market indexes, you can make money. To understand this notion, it is worth looking first at the opposite idea – the efficient market hypothesis.
Stormed the redoubtable Burton Malkiel, “fundamental analysis cannot produce investment recommendations that will enable an investor consistently to outperform a buy-and-hold strategy in managing a portfolio.”
Malkiel is the best-known advocate of the efficient market hypothesis, which simply states that the market is able to price new information into the price of each company’s stock more efficiently than individual investors, no matter how smart they are or how hard they try. It is not possible to consistently outperform the market because all stock market participants are rational, and their combined knowledge is greater than that of any individual.
Since the release of important information is random, Malkiel argues, success in predicting the stock market is also random. Taken to its logical extreme, the efficient market hypothesis suggests that no matter how carefully you study a company's earnings history, balance sheet, management and production, you will not consistently find information that will give you an advantage over the market as a whole.
In such a world, what is an investor to do? According to Malkiel, you should carefully select a group of stocks, buy them and hold as long as you can. If you do this, you are likely to perform at least as well as the general markets. You cannot reasonably hope to do any better.
Malkiel uses sophisticated academic research to back up his ideas, but he allows for possible exceptions. One is that “a portfolio of stocks with relatively low earnings multiples (as well as low multiples of cash flow and of sales,) has often produced above average rates of return.” Another is that small firms tend to do better than large firms. There are other exceptions, he says, but none of them are guaranteed to outperform either averages or indexes.
Malkiel’s message is that you shouldn’t expect to outperform the market through stock picking over the long term. If that were true, what chance do you have in making a superior return in the market?
These pages argue that the odds are actually quite good, because some strategies do outperform, although it isn’t always clear why. Take seasonality, which is also known as seasonal investing. The simplest form of this strategy is captured in the epigram, “buy when it snows, sell when it goes.” According to that strategy, you should own stocks only between Halloween and the end of April. For the rest of the year, you should store your cash in a sock under the mattress or, preferably, in a money market fund.
Yale Hirsch provided a dramatic illustration of this strategy in the 1996 Stock Trader’s Almanac. In his article, he hypothesized an investor who placed $10,000 in the Standard & Poor’s 500 index during the period November through April, but left it in cash for the rest of the year. Between 1950 and 1994, her investment would have compounded to $173,788. On the other hand, if she had invested only from May through October, her nest egg would have grown to a mere $15,285.
Physician-turned-stock-market-investor Mark Vakkur later proposed a refinement of this idea – like Hirsch, using hindsight to take a long look at the behaviour of the markets. Following his strategy, you would be invested in a growth mutual fund nine months out of each year, as follows: You would invest all your money during the months of November through January and March through April. You would invest half of your money during the months of October, August and February and keep the other half in a money market fund. You would keep all your money in a money market fund during the months of May through June and September. This strategy cunningly keeps you out of the market during the months in which US markets perform worst.
Vakkur’s study showed that $10,000 invested in the S&P 500 in this way would have grown to $997,620 between 1950 and 1996. By comparison, $10,000 invested in the S&P 500, using a buy-and-hold strategy, would have grown to only $327,388 during the 47-year period.
To improve upon Vakkur’s strategy, you might want to take advantage of the seasonality of energy stocks.
In a study of the period 1980 to 2001, George Vasic of UBS Warburg found that North American energy stocks gained between 8.8 percent and 10.1 percent during the three-month period March through May. Thus, if you had put $10,000 to work in energies during those months only, at the end of the 22-year period your investment would have been worth about $65,000. If the same pattern were to continue for 47 years (the length of time covered by Vakkur’s study of the S&P), the value of your investment would climb to more than half a million dollars. Yet it would only have been at work three months of the year.
We don’t need to understand why these seasonal strategies work. All we need do is take advantage of the stock market’s seasonality – a cycle somehow induced by the sun and its proxy, the calendar. So doing, we will also take advantage of what a nineteenth century Rothschild called “the eighth wonder of the world:” the miracle of compound growth.
We have seen that Burton Malkiel was skeptical about fundamental analysis – the study of a company’s business fundamentals to forecast how its stock will perform. But he was downright scathing about technical analysis: You cannot predict future stock prices on the basis of past stock prices, he thundered. But technical analysts beg to differ.
Technical analysis is the practice of trying to predict stock prices by examining trading patterns and comparing the shape of current charts to those from the past. Critics like Malkiel deride technical analysis as hocus-pocus, not far removed from tealeaf reading. For their part, technical analysts insist that the stock market moves in broad patterns, which can be recognized by careful charting and an understanding of stock market history.
These pages venture into that snake pit later, concluding that a judicious use of both fundamental and technical analysis can generate superior profits. In the meantime, our purpose is to introduce the most basic tool of the technical analyst: Charts based on stock market averages and indexes. Fever charts, as they are known.
Both Malkiel and Charles Dow of the Dow Jones Averages believed in an efficient market, but from that starting point they drew quite different conclusions. As we have seen, Malkiel believed that because the market was efficient, no single approach to picking stocks could consistently outperform the market.
By contrast, Charles Dow believed that a study of general patterns within the averages could help the investor discern market trends. Market trends carry most stocks along with them (“a rising tide lifts all ships”), so an understanding of the direction the market is going can help all investors. Dow is the name behind the world’s oldest (1890s) and most famous measures of stock market performance. And the Dow Theory that originated with his work is the beginning of technical analysis.
Dow created three averages in told, and tinkered with them for quite a number of years before he was satisfied with his results. Those averages survive today as the Dow Jones industrial average (“the Dow”), the Dow Jones transportation average and the Dow Jones utilities average. Technically, these averages consist of “simple arithmetic averages of price relatives.” This means that all stocks in each average have the same weight, regardless of their size.
Dow calculated the value of each index by simply adding up the prices of the component stocks and dividing by the number of stocks. Think about that. The Dow includes thirty stocks, including General Electric (market value: US$375 billion at year-end 2001) and Caterpillar (US$17.5 billion). Yet both companies have the same relative weight in the average – or at least, they do when they first become part of an average.
According to Dow Theory “the averages discount everything (except acts of God,)” explained Robert Edwards and John Magee, who wrote the classic text on technical analysis. “Because they reflect the combined market activities of thousands of investors, including those possessed of the greatest foresight and the best information on trends and events, the Averages in their day-to-day fluctuations discount everything known, everything foreseeable, and every condition which can affect the supply of or the demand for corporate securities.”
Wall Street Journal editor William P. Hamilton later organized and formulated Dow’s ideas into Dow Theory. Part of that theory says that stock market movement is like the tide, characterized by primary, secondary and minor waves in a constant ebb and flow. The best way to visualize those trends is to use charts, which represent information in two-dimensional form. In a bull market, you will see higher highs and higher lows. When the bear begins to growl, the chart will display lower highs and lower lows.
The classic Dow definition of a technical bull market involved both the Dow Jones industrial average and the Dow Jones transportation average. For a bull market to be technically confirmed, both indexes had to proceed to higher highs and higher lows. If the Dow reaches a new high but the transportation average does not, the stock market is technically weak, and he bull trend is not confirmed. Adherents of Dow Theory buy if the market is moving along higher and higher peaks, and sell when it starts to go down progressively lower valleys. At least, that is their hope.
Since Dow’s time, the idea of an “average” has evolved into a better idea – the stock market “index,” which accounts for a stock’s size as well as its price. A company’s size is expressed as “stock market capitalization” – essentially, the number of shares outstanding multiplied by share price.
Like the averages, indexes offer elegant pictures when you chart them on a piece of graphing paper – or, more probably, pull them off the Internet. Since this book is about oil and gas, it will therefore be of interest to review North America’s main oil and gas indexes. Two of those indexes are American. The others are Canadian.
The American Stock Exchange (Amex) created the two American indexes. These charts are based on portfolios of stocks conservatively chosen to reflect a single industry. The Amex oil index fund is known as the XOI and has been tracked since 1983. The natural gas index fund is the XNG, and was created ten years later.
These indexes are based on specific investment vehicles. Units in the XNG are sold on the Amex. So are units of the XOI. Each is a portfolio of about fifteen stocks. By tracking the performance of these funds, you can follow the performance of big, widely held, peer group companies. That is the idea behind these industrial indexes.
The XOI and the XNG are price-weighted, which means that in the beginning their designers used blocks of shares of comparable value to create them. To create the XNG, for example, the developers began with closing prices from October 15, 1993. They then created a hypothetical portfolio – what is commonly called a “basket” of shares. Each company went into the gas index as a block of stock worth approximately $10,000 – five hundred shares of XYZ Corporation at $20 per share, say.
As the prices of these stocks changed, so did the basket’s value. But its progress was not charted in dollars, as you might expect. It is calculated as a percentage change from a specific starting point. Suppose on its first day of trading the XNG had risen by $15,000, or one percent. To graph the index, you would add one percent to the index’s starting point of 100, and the closing index would be 101.
Amex’s oil index, the XOI, represents a cross section of companies involved in the oil industry, from exploration and production to refining and marketing. The gas index reflects the performance of companies involved in natural gas, from exploration and production to pipeline transportation and transmission.
Like other indexes, the XOI and the XNG have an upward bias. There are at least three reasons for this.
First, good economic news comes more often than recession, and economic growth is taking place in almost every country of the world. General prosperity supports a rising stock market.
Second, the market winnows out weak companies by encouraging stronger players to buy them.
Third, companies that file for bankruptcy are immediately replaced with going concerns. A spectacular example was the fall of Enron, the energy-trading giant that at its height had market capitalization of $100 billion and was number seven on Fortune magazine’s famous list of 500 large corporations. In the fall of 2001, the corporation failed in spectacular manner.
“It turned out that many of Enron's profits were illusory,” said Tim Francis-Wright, “and that the company had liabilities that did not appear on its books. In September, its auditors forced it to move some of the liabilities back on its balance sheet (eating through $1.2 billion of shareholders' equity in the process). But its prospects fell to bleak, then to grave, as more and more hidden liabilities, many due to dealings with the firm's former chief financial officer, came to light. Its bond rating plummeted, causing its lenders to call their debts. On the first business day in December, Enron filed for bankruptcy.”
The moment Enron filed for Chapter Eleven protection from imminent bankruptcy, it was taken out of the XNG, suddenly becoming irrelevant. However, other social institutions – governments, investors, employees, chartered accountancy and the courts, for example – have longer memories.
For a quick image of the companies that bind America’s petroleum industry together, look at the components of the XOI and XNG. The following table names the names for each index at the beginning of 2002. They are the big players in their respective sectors.
Amex Oil Index (XOI) |
| Amex Natural gas Index (XNG) |
|
Amerada Hess Corporation | AHC | Anadarko Petroleum Corporation | APC |
BP Amoco PLC | BP | Apache Corporation | APA |
Chevron Texaco Corporation | CVX | Burlington Resources Inc. | BR |
Conoco Inc. | COC | Dynegy | DYN |
Exxon Mobil Corporation | XOM | El Paso Energy Corporation | EP |
Kerr-McGee Corporation | KMG | EOG Resources | EOG |
Marathon Oil Corp. | MRO | Kinder Morgan Inc. | KMI |
Occidental Petroleum Corporation | OXY | National Fuel Gas Company | NBL |
Phillips Petroleum Corporation | P | Nicor Inc. | GAS |
Repsol | REP | NiSource Inc. | NI |
Royal Dutch Petroleum Co. | RD | Ocean Energy Inc. | OEI |
Sunoco Inc. | SUN | Pogo Producing Company | PPP |
Total Fina SA | TOT | Questar Corporation | STR |
Unocal Corporation | UCL | Williams Company | WMB |
Look at these two lists. If you think of each as a proxy for oil or gas and compare the two, you can see that the oil and gas sectors evolved in quite different ways.
One difference is size. The XOI includes all three of the super-major oil companies – Exxon Mobil, Royal Dutch Shell and BP. At the end of 2001, the respective market capitalisations of these corporations were $275 billion, $175 billion and $105 billion. Each of these companies, in other words, had market capitalization larger than the $97 billion market value of all the companies on the XNG combined.
Range of operations is a second difference between the two industries. Big oil companies are global, because oil is in great demand and highly portable.
By contrast, big gas companies are continental; those on the XNG have operations mostly in North America. They usually have subsidiary operations in other parts of the world, but these tend to be smaller, early growth operations. Because natural gas is exceedingly bulky, it is difficult to transport. To be commercial, it has to be encased in steel from wellhead to burner tip. That is why it took so many decades to create a continental gas market, which has not yet begun to tap the huge Arctic resources in Alaska and the Northwest Territories.
A third difference is diversification. Oil is such a versatile product that integrated companies can manufacture it into many kinds of fuel, lubricant and petrochemical. The large operations needed in these petroleum enterprises require huge capital investments, but they create products that do not fluctuate wildly in price. Thus, the XOI is somewhat divorced from oil’s commodity price cycle, and therefore less volatile.
Natural gas is versatile, so it rides upon the waves of seasonal commodity price cycles. There are uses for gas for petrochemical feedstock and the generation of electricity and industrial power, but the lion’s share of this commodity goes into space heating. The natural gas sector is heavily influenced by cold and hot weather. During the summer air-conditioning season, hot weather increases demand for electricity, much of which is fired by natural gas. Mild winters reduce demand for gas, while abnormal cold increases it.
The following chart shows these cycles in action. The XNG dropped precipitously during the winters of 1998, 1999 and 2001, when the winters were unusually mild. It shot up like a rocket in the winter of 2000, when record cold blanketed most of the United States. It began to collapse in the summer of 2001 because of declining gas prices, and got another kick downward in the fall, as Enron failed.
The XOI and the XNG give pictures of the great strength of the American oil and gas industry. The TSE indexes give a different picture entirely.
The Toronto Stock Exchange set up most of its present slate of indexes in 1977. However, its design is quite different from that used in the Amex index funds. The TSE uses a “modified Paäsche” index – named after a mathematician.
The parent index is the TSE 300 which, when it began, equalled 1000. This index reflects the market value of all the publically held shares in three hundred large-capitalization companies. The TSE develops this list by calculating the total market value of each company’s publically held shares, and then adding them all up.
The following table gives the TSE and its fourteen subindexes, and their market capitalization at the end of 2001. This gives an idea of the relative value of the fourteen sectors, and therefore an approximation of the makeup of the Canadian economy.
Index |
| Market Capitalization (billion dollars, Canadian) |
TSE 300 |
| 713 |
|
|
|
Oil and Gas Subindex |
| 82.1
|
Other Subindexes |
|
| Pipelines | 21.9 |
| Financial Services | 207 |
| Insurance | 57 |
| Utilities | 50 |
| Gold and Precious Metals | 30.4 |
| Metals and Minerals | 33.7 |
| Paper and forest | 12.1 |
| Consumer products | 37.5 |
| Real estate | 6.8 |
| Transportation | 23.8 |
| Utilities | 49.9 |
| Communications and media | 32.9 |
| Merchandising | 29.3 |
| Conglomerates | 13 |
| | | |
At yearend 2001, petroleum represented about 12 percent of the TSE by capitalization. In 1981 that number stood at a record 24.7 percent. Low tide came in 1992, when oils briefly made up only 6.5 percent of the TSE 300’s total market value.
More than most other sectors in the index, oil and gas is underrepresented on the TSE because of the way market capitalization is calculated, and the way oil and gas assets are owned. Here is why.
To determine a company’s capitalization, you begin with the public float. The float includes all of the company’s outstanding shares except those held in a “controlling block” – a parcel of shares held by a single entity and equal to twenty percent or more of the company’s total outstanding shares. Multiply the float by the value of the stock and presto! you have market capitalization.
Canada’s petroleum industry is much greater than what is measured on the TSE. A main reason is the TSE’s practice of failing to include controlling blocks has created some interesting anomalies. Until the end of 2001, PanCanadian Petroleum was part of the conglomerate that grew out of the Canadian Pacific Railway.
The CPR was the great transportation project that, in 1886, bound Canada from Atlantic to Pacific. As part of its compensation for building that railway, Canadian Pacific received full ownership, including mineral rights, of regular sections of land throughout the Prairie Provinces. This turned out to be a rare and valuable asset, because most other mineral rights in Alberta, Saskatchewan, and Manitoba belong to the government. (British Columbia has the highest government ownership of mineral rights – essentially 100 percent.)
The CPR’s mineral rights were the foundation stone for PanCanadian Petroleum, in which CP Corporation retained an 82 per cent interest. So the index reflected only a small number of the company’s shares when it calculated PanCanadian’s market value. PanCanadian was a large corporation, with assets around the world and important exploration and development interests in Western Canada and offshore Nova Scotia. Yet the TSE’s index methodology ranked it as a middling $2 billion company.
This curiosity was rectified in 2001, when the CP conglomerate broke itself up, turning its component companies into publicly traded shares. PanCanadian Energy was the name of the new company, and its market capitalization began to reflect its true size. With more than 250 million shares outstanding and a share price of $40, the company had market capitalization of more than $10 billion – after having distributed $1.3 billion dollars to shareholders as part of the restructuring process.
Other prominent companies that are not fully represented on the TSE 300 include three of the six integrated oils. Imperial’s majority shareholder is Exxon Mobil; Shell Canada’s is Royal Dutch Shell; Husky is controlled by Hong Kong money. Thus, most of the asset values of three quite large companies are not included in the TSE 300 total.
Neither are the large subsidiaries that are wholly owned by foreign companies, of course. Indeed, the market capitalization calculated by the TSE is less than half of the usual market value of the industry’s total assets. After all, the industry’s gross revenue for oil and gas alone was about $45 billion (Canadian) in 2001. Compare these record revenues to the $82.1 billion market capitalization of the TSE’s Oil and Gas index, at yearend 2001.
Having established that the oil industry is much larger than the TSE 300 may suggest, it is worth comparing the TSE 300 to its cyclical components.
Index | Year-end 2001 |
TSE 300 | 7,700 |
Oil and Gas | 9,100 |
Oil and Gas Producers | 7,500 |
Gold and Precious Metals | 5,100 |
Metals and Minerals | 4,200 |
Paper and Forest Products | 4,950 |
Real Estate | 2,575 |
As you can see, during the TSE 300’s first quarter century of life, the long-term winner was the TSE’s Oil and Gas Index, which outperformed the market as a whole by one third. The third place winner was the Oil and Gas Producers Index, which was just below the TSE 300.
The above table says that if you buy petroleum stocks and hold them, you’ll do better than if you buy and hold all three hundred stocks in the index. This is also a better strategy than buying and holding shares in any other cyclical industry. Given this reality, the behaviour of the Canadian mutual fund industry is a bit odd. Mutual fund companies prefer to sell “resources” mutual funds, and energy funds are uncommon.
Mutual fund companies prefer to sell resource funds for a practical reason. Different resource sectors have different business and commodity cycles – different in terms of both timing and severity. This strategy creates mutual funds that have relatively less short-term risk, and are therefore more palatable to the nervous investor. However, it also averages down the great long-term performance of the oil industry.
We will review an attractive, pure energy investment at the end of this chapter – Canada’s answer to the XOI and the XNG.
Our earlier discussion of the XOI and the XNG gave some insights into the US oil industry. A look at the TSE’s oil and gas index (“the TOG”) provides a deeper look into the Canadian oil and gas industry.
The following table names the companies that were in the index at the end of 2001. Some of them undoubtedly will soon disappear from the list, because of merger and acquisition activity.
TSE Oil and Gas Index
| Company | Symbol
|
Integrated Oils | Hurricane Hydrocarbons Limited, Cl.'A' | HHL.A |
| Husky Energy Inc. | HSE |
| Imperial Oil Ltd. | IMO |
| Petro-Canada | PCA |
| Shell Canada Limited | SHC |
| Suncor Energy Inc. | SU
|
Oil & Gas Producers | Alberta Energy Company Ltd. | AEC |
| Altagas Services Inc. | ALA |
| Baytex Energy Ltd. | BTE |
| Bonavista Petroleum Ltd. | BNP |
| Canadian 88 Energy Corp. | EEE |
| Canadian Natural Resources Limited | CNQ |
| Compton Petroleum Corporation | CMT |
| Elk Point Resources Inc. | ELK |
| Ivanhoe Energy Inc. | IE |
| Ketch Energy Ltd. | KCH |
| Nexen Inc. | NXY |
| Niko Resources Ltd. | NKO |
| PanCanadian Energy Corporation | PCE |
| Paramount Resources Ltd. | POU |
| Penn West Petroleum Ltd. | PWT |
| Rio Alto Exploration Ltd. | RAX |
| Southward Energy Ltd. | SWN |
| Storm Energy Inc. | SME |
| Talisman Energy Inc.. | TLM |
| Ultra Petroleum Corp. | UP |
| Vermilion Resources Ltd. | VRM |
| Western Oil Sands, Inc. Cl.'A' | WTO
|
Oil & Gas Services | CHC Helicopter Corp. Cl.'A' SV | FLY.A |
| Enerflex Systems Ltd. | EFX |
| Enserco Energy Service Company Inc. | ERC |
| Ensign Resource Service Group Inc. | ESI |
| NQL Drilling Tools Inc. Cl.'A' | NQL.A |
| Precision Drilling Corporation | PD |
| Shawcor Ltd. Cl.'A' SV | SCL.A |
| Tesco Corporation | TEO |
| Trican Well Service Ltd. | TCW |
December 31, 2001
The industry that emerges from this list is quite different from those represented in the XOI and the XNG. For example, the TOG is much smaller and more transient. Between 1977 and the time this list was created, xyz companies were listed and eventually removed from the index. With consolidation in the industry, the number of petroleum companies in the TSE (and therefore in the oil and gas index, became a progressively smaller number. However, there tended to be more 800-pound gorillas among the companies that remained.
While Canada’s petroleum industry focuses on Canadian resource basins, it has traditionally been dominated by America. However, there is a regular ebb and flow of ownership in the industry. In recent years, the pattern has shifted toward more American ownership.
As we have seen, the makeup of the Canadian oil and gas index shows a dramatically different industry from those represented in the XOI and the XNG.
We will now dissect the TSE’s oil and gas index to see the three groups of companies that make it up. These are the Integrated Oils, the Oil and Gas Producers and the oil and Gas Service Companies. These are the three subindexes of the TSE 300’s oil and gas index. We will start with the Integrated Oils.
There are only six publically traded integrated oil companies in Canada. They are a bit of an odd mix.
Imperial, Shell and Petro-Canada: The biggest, Imperial Oil, is a giant by Canadian standards, but it is a relatively small part of Exxon Mobil’s global assets. Exxon Mobil owns 70 percent of Imperial, whose shares trade on both Canadian and American stock exchanges. Shell Canada (70 percent owned by Royal Dutch) also trades on those exchanges. Those two companies and Petro-Canada (20 percent owned by the federal government) are the only ones with service stations and other marketing facilities in every part of Canada. Their oil and gas producing operations are quite large, and usually responsible for most of their profits.
Suncor, Husky and Hurricane: Suncor and Husky are primarily producing companies, but have regional refining and retail operations. Also, they are both important producers of non-conventional oil.
Suncor was a pioneer in Alberta’s oil sands, which are huge deposits of bitumen – gooey, viscous oil — mixed with sand. Suncor strip-mines this oil, then runs it through an upgrading process to turn it into high-quality synthetic crude oil. Suncor began mining and upgrading oil near Fort McMurray in 1965, a brave experiment that did not become profitable until around 1980. Since then, Suncor has added a lot of processing facilities to the plant, bringing daily production to 225,000 barrels per day – up from the plant’s 55,000 barrels per day original design. Most of the increase in production came from a recent $3.25 billion (Canadian) expansion, which was completed at the end of 2001. The project’s name was the Millennium Expansion.
In the border town of Lloydminster, Saskatchewan, Husky operates a huge facility to upgrade production from the heavy oil belt in Alberta and Saskatchewan. After a series of false starts, in 1988 Husky and its three partners announced a firm agreement to construct the Bi-Provincial Upgrader. Located just east of Lloydminster, this $1.6 billion upgrader received most of its funding from government. Eventually, the governments sold their interests to Husky, paying a big financial penalty for having subsidized the project.
Today’s Husky was the result of a merger between Husky Oil Operations and Renaissance Energy. Prior to the merger, Hong Kong multi-billionaire Li Ka-Shing was the proprietor of Husky, through his business empire, and Renaissance was a stock market angel, which had fallen.
Renaissance had grown rapidly in the 1980s and 1990s, but it eventually stopped growing. It was unable to continue replacing all of its reserves each year, and its share price dove. Husky took the company over, bringing more stable, longer-term assets to the marriage.
The oddball among Canada’s fully integrated companies is Hurricane Hydrocarbons, whose production, refining and marketing operations are entirely in the former Soviet republic of Kazakhstan. Its chairman lives in the UK. And in 1999 it made a spectacular recovery from near bankruptcy.
We discuss many producing companies elsewhere in these pages. The companies on the Canadian exchanges come in many sizes, and have many kinds of operations. They produce in Canada and the United States, and in many other major producing countries of the world.
Talisman, Nexen and Western: Usually they begin as Canadian companies, gradually acquiring a lot of domestic oil and gas production. Then they begin investing overseas. That was how Talisman developed – originally, after BP sold its interest in what had up to then been its Canadian subsidiary. Under post-BP CEO Jim Buckee, the company grew quickly.
Talisman was an extremely controversial corporation as the millennium rolled over, because of its big oil discovery in Sudan. Human rights critics argued that oil revenue from Talisman was funding abuses in Sudan, and that those abuses included losses from civil war, landmines and, perhaps, local wars of genocide.
“Au contraire,” said Talisman’s CEO, Jim Buckee. The Sudanese were benefiting from the company’s presence. Producing more than 54,000 barrels of oil per day from Sudan created employment in the area, the company said. In addition, the company offered medical, educational and other services to the locals. This improved stability in the area, Talisman said, but the arguments among Talisman’s critics continued to rage.
As a large producer, Talisman had enough cash flow to continue operating in Canada while developing oil and gas reserves in other parts of the world. Another successful was Nexen, which has exploration and producing operations in Yemen, Nigeria and Colombia. More importantly, Nexen is heavily involved in synthetic oil production from the Athabasca Oil Sands.
The company planned to increase its daily synthetic crude oil production to more than 70,000 barrels from 17,000 by 2006. Nexen produces synthetic through ownership in the giant Syncrude oil sands mine and upgrader – the world’s largest industrial plant and material handling system, which produces twelve percent of Canada’s total crude oil. In addition, it plans to participate in another oil sand upgrader, with a corporate partner.
Synthetic crude oil production is a unique and profitable feature of the Canadian petroleum scene, and these pages discuss those operations in more detail elsewhere. In the meantime, it is worth noting that one of the companies on the TSE’s oil and gas index is Western Oil Sands. That company is participating in the construction of a third major oil sands plant. At the end of 2001 it had no revenues, just a percentage of construction costs for a large oil sand plant. The company’s share would cost $865 million. Yet the company’s share price was strong. The market saw this business plan as part of the wave of the future.
The third group of companies in the oil index make up the oil and gas services index. The first company on the list is a helicopter operator. This is because helicopters frequently hover over Newfoundland and Nova Scotia, ferrying people and supplies to offshore drilling rigs. They are also sometimes used in remote drilling sites in Western Canada.
The other companies in this subindex are a bit more standard fare for the oil industry. Precision Drilling, which is based in Calgary, is one of the largest companies offering onshore drilling services. The other service companies provide drilling, tools, equipment and supplies. This enables the sector to drill its wells, bring them on production, and care for them during their twenty- or thirty-year lifetimes.
A later chapter offers details on how these companies operate, and what to look for before you buy shares in them.
The TSE oil and gas index, which includes the integrated oils, the producers and the service companies, marches to a beat of its own, according to Wilf Gobert, who has been an oil analyst for more than 20 years. Gobert is managing director of Peters and Co., a Calgary-based merchant bank that specializes in Canadian oil and gas stocks. He has observed a rhythm in the oil sector that can be of considerable benefit to the savvy investor. However, it is not always easy to spot.
Consider the following ten-year chart.
TSE Oil and Gas Index
What is not apparent to the casual observer is what Gobert sees as a mathematical rule of thumb – not infallible, but helpful. In a typical year, the low will be 25 percent below the previous year’s high says Gobert. By contrast, the new high will be 50 percent above the previous year’s low.
This formula opens the doors for market timing – the technique by which investors and money managers aim for bigger profits by predicting when the market will change course, and the direction it will take. If they think the sector is going down, they will sell. If they think it is ready to take off again, they will shift back into oils in an effort to make another big killing. A later chapter suggests that timing the petroleum service sector can yield even more dramatic results than timing the oils themselves.
Gobert is one of the most widely respected Canadian oil and gas analysts, and under his direction Peters & Co. has created a specialized series of oil and gas indexes to better follow the way the industry works. These indexes give a better picture of the Canadian oil and gas industry than the TSE’s subindex, because there are so many more companies on the exchanges than the thirty-seven companies listed on that index at year-end 2001. According to some sources, there may be as many one hundred or more oil and gas companies on the Toronto and Venture exchanges with neither oil nor gas production. They are small players, but sometimes they are wildly successful. More commonly, they are not.
As the following table illustrates, differently sized energy companies perform in different ways.
Bull and Bear Cycles
|
| Bull | Bear | Bull | Bear | Bull | Bull | Bear |
|
| 1992-93 | 1993-95 | 1995-97 | 1997-99 | 1999 | 1999-01 | 2001 |
TSE 300 Oil & Gas | 77% | -28% | 112% | -51% |
| 148% | -6% |
Peters Energy 100 | 93% | -29% | 124% | -52% | 77% | 145% | -6% |
| Integrated Oils | 34% | -8% | 132% | -30% | 60% | 134% | -3% |
| Large Producers | 81% | -26% | 95% | -51% | 88% | 154% | -3% |
| Intermediate Producers | 195% | -46% | 76% | -65% | 88% | 89% | -26% |
| Junior Producers | 172% | -41% | 237% | -71% | 104% | 198% | -25% |
| Small Producers | 265% | -42% | 229% | -64% | 103% | 309% | -24% |
| Oilfield Service | 184% | -45% | 679% | -73% | 128% | 259% | -35% |
PE 100 Natural gas | 311% | -46% | 113% | -40% | 86% | 148% | -3% |
PE 100 International | 31% | -3% | 153% | -69% | 109% | NA | NA |
TSE 300 Index | 21% | 8% | 62% | -14% | 37% | 34% | -12% |
|
(2) TSE 300 top and bottom and these cycles is based on the dates of the Energy indexes' top and bottom. In the 1999-2001period, this wipes out the rise and fall of Nortel. |
Source: Peters & Co.
Notice how volatile Canadian energy stocks are, especially the service companies and the smaller exploration and production companies. “Canadian energy stocks outperform the market in their bull cycle and underperform in their bear cycle,” Gobert observes.
The table illustrates how integrated oils underperform in the energy bull market but outperform during the bear portion of the cycle. Thus, they are less volatile. If you want to stay in the Canadian oil and gas sector but avoid the extreme volatility of the smaller energy companies, one approach is to buy the S&P/TSE Energy Index Fund, which has the ticker symbol XEG.
This index is very much like its Amex cousins, and is managed for the TSE by Standard & Poor’s, the very firm that manages the XOI and the XNG indexes. The following table lists the components of Toronto’s XEG, at year-end 2001.
S&P/TSE Energy Index Fund (XEG)
Hurricane Hydrocarbons Limited, Cl.'A' | HHL.A |
Husky Energy Inc. | HSE |
Imperial Oil Ltd. | IMO |
Petro-Canada | PCA |
Shell Canada Limited | SHC |
Suncor Energy Inc. | SU |
Alberta Energy Company Ltd. | AEC |
Bonavista Petroleum Ltd. | BNP |
Canadian Natural Resources Limited | CNQ |
Compton Petroleum Corporation | CMT |
Nexen Inc. | NXY |
Niko Resources Ltd. | NKO |
PanCanadian Energy Corporation | PCE |
Paramount Resources Ltd. | POU |
Penn West Petroleum Ltd. | PWT |
Rio Alto Exploration Ltd. | RAX |
Talisman Energy Inc.. | TLM |
Ensign Resource Service Group Inc. | ESI |
Tesco Corporation | TEO |
|
|
Like the US index funds, the XEG is weighted toward greater stability than you will witness in the TSE’s oil and gas index. It includes companies that S&P has evaluated in respect to market capitalization, stock liquidity and fundamentals. XEG has a strong emphasis on the integrated oils, all six of which are included in the fund. In addition, it includes eight senior producers and two large service companies. The combination of balance and of fundamental strength is the reason the index fund is less volatile than the TSE index.
If, with Burton Malkiel, you believe in a “buy and hold quality stocks” investment strategy, this instrument is an interesting way to play the energy market. That is because the fund’s components include good though sometimes unusual suspects. The XEG has modest risk, and a low (0.55 percent) administration fee. If the behaviour of the stock market is indeed a random walk, buying this index fund – or, for that matter, the XOI or the XNG – will eliminate your need to become a picker of oil and gas stocks. Just let the index fund do the stroll for you. Index funds are an elegant way to passively invest in energy. They are a pure play, and have outperformed most comparable mutual funds over time.
Of course, you may think there is more to the stock market than a random stroll. You may believe you can get better results through business cycle investing, knowing that in it there is more risk, but also more reward potential. And you may be right.
For good results you will need to understand the cycles underlying the petroleum industry, and how they affect the fundamental value of individual companies. As the following chapter illustrates, the impact of the exploration and development cycle on individual stocks is a complex dance, in which price and cost take turns in the lead. You also need to understand the service sector cycle, covered elsewhere in these pages. However, we will first turn to the exploration and development cycle.
To the untutored outsider, the job may seem mysterious. In one of its incarnations, grey-suited men (and small numbers of women) sit solemnly in long rows in large meeting rooms, listening carefully to other suits at the podium. Their gold-plated pencils use retractable graphite, and they ask murky questions about cycle time, productive capacity and test results.
Fast-forward two months to a junket in Indonesia. Some of the same men and a woman are cycling along a high-tech floating road constructed of logs covered by geotextile and gravel. Besides being comfortable paths for fat-tired bicycles, these roads carry low-load, wide-track trucks over swamp that was otherwise almost impassable.
“It was a good week,” said Jill Angevine, an analyst at FirstEnergy Capital, “but the day in Borneo was an adventure. We flew in from Jakarta, and then took a boat down a river. There were mangroves and thick, swampy jungles on each side. It was hot and sweaty. We wore short-sleeved shirts, but we should have been covered up because of the bugs.”
“What we saw,” she continued, “was Equatorial Energy’s biggest area of activity in Indonesia” – its Sembakung concession, in northeastern Borneo. “They had a rig there, which we visited. We saw the pads they were drilling from. They showed us where they were going to drill next and we talked about their 3-D seismic.”
Another of Equatorial’s Indonesian properties the analyst’s discussed was really just new drilling at an old oilfield – a field whose previous productive life had ended in 1944. As Daniel Yergin explained, one reason for the attack on Pearl Harbor was the Japanese government’s worry that America would cut off supplies of oil from Texas. US public sentiment against the European and Asian wars was deepening, and there were calls for action in response to Imperial Japan’s bloody adventures in Korea, China, Hong Kong and other theatres of war. The Pearl Harbor offensive protected the country’s eastern flank as the Japanese military secured oil production in the Dutch East Indies – now Indonesia.
Of course, the emperor’s war office underestimated both the fury and the might of the Americans, who soon drove his armies from their South Pacific conquests. As defeat loomed, the Japanese Imperial Army blew up many oil fields before regrouping around the homeland. The ghosts of armies from that long-ago war haunt many abandoned wells in Indonesia, some of them on an Equatorial concession.
Romantic? Hardly. But the memory of war is an illustration of one concern that took those analysts to the swamps of Borneo. They wanted to investigate Equatorial’s operations and potential, for sure. But they also wanted to assess its political risks. “It’s such a different operating environment than we are used to,” said Angevine. “People are concerned about political risk, and it’s important to get comfortable with the operations and the political environment before you invest in the company.” War is an extreme example of political risk. Others include insurrection; government expropriation of property; political and economic instability; and arbitrary and unpredictable taxation.
After meeting with industry and government heavyweights and reviewing Indonesia’s new energy legislation, Angevine and most of the other analysts concluded that the risks were acceptable. “The reality is that the oil and gas business continues on, despite political problems,” she said. When she returned to Canada, Angevine began covering the company. “I calculate close to $2 per share (as the value of) Equatorial’s Canadian reserves alone,” she said of a $1.80 stock. The company’s Indonesian production was already more than 6,000 barrels per day, or about half the company’s total production. “You’re getting the Indonesian assets for free. It’s a bargain.”
The Equatorial Energy story helps illustrate the two things fundamental analysis does best: looking for bargains and looking for risk. But you do not need junkets to exotic swamps to get a good, clear picture of an oil company. The balance of this chapter discusses what you do need; it is a basic toolkit for analysing the petroleum sector.
You need to understand basic accounting, including some of the special features of petroleum accounting. You need to know how professional traders and analysts look at stock fundamentals. And you need Internet access and a telephone, through which you can get virtually all the information you need. But first you have to know what to look for.
For the petroleum sector, the bedrock of success is investment – best expressed by former Shell executive Doug Stoneman when he said “If you fail to invest, you will fail to survive.” Unless a petroleum company drills and develops new production, it will deplete itself into oblivion.
Investment begins with the shareholders who put money into the company, and it can include debt. But the main source of petroleum investment is known as cash flow; oil and gas companies can grow through cash flow even when their profits are zero. Because it enables the company to invest, cash flow is king. When you begin a fundamental analysis of an oil and gas producer, you need to focus on cash flow rather than profits. But where do you start?
To find cash flow, you go to the company’s financial report, and to understand that report you must understand basic accounting. So let’s begin our discussion of accounting by looking at this fundamental accounting document, which every public corporation must issue.
The financial report is an expression of double-entry bookkeeping, which was first codified in 1494 by Franciscan friar Luca Pacioli, an unsung hero of the Renaissance. Pacioli’s greatest book, the Summa, included the first European text on algebra. It also explained double-entry bookkeeping, and articulated the simple mathematical formula behind the entire system: Assets = Liabilities + Owner’s Equity.
Since then, double-entry bookkeeping has become the foundation of accounting, one of the great business professions. It has also become the mathematical basis for virtually all investment. So it is worth reviewing how basic accounting works.
The money and date columns in Pacioli’s ledger were almost identical to those in modern ledgers. Entries consisted of brief paragraphs. Debits were on the left side of a double page, credits on the right. The trial balance was the end of Pacioli's accounting cycle. If the credit and debit columns were not equal, said Pacioli, "that would indicate a mistake in your Ledger, which mistake you will have to look for diligently with the industry and intelligence God gave you."
The accounting portion of Pacioli’s Summa was a how-to document for the businessman of the day. “Accounts are nothing else than the expression in writing of the arrangement of his affairs,” Pacioli explained. “If he follow this system always he will know all about his business and will know exactly whether his business goes well or not.”
So good was double-entry bookkeeping that it quickly became the dominant European business system. Pacioli’s Summa was soon translated into five languages, and numerous European writers described his system of accounts. The first to do so in English was Hugh Oldcastle, in 1553.
The financial report evolved gradually from those rather beginnings, and made its greatest advances in Victorian times. Since 1844, the state-of-the-art financial report has officially consisted of two parts. The first is the balance sheet. The second is the income statement, which is also known as the profit-and-loss statement. To become an ardent investor, you need to understand these two documents – both their differences and their uses.
The balance sheet captures the company’s financial health at a moment in time by summing up its assets and liabilities. One side of the balance sheet totes up assets, moving from most liquid (cash) to least liquid (plant and equipment or goodwill). The other side of the balance sheet lists liabilities, in order of immediacy.
The balance sheet is based on Pacioli’s great formula: assets must equal liabilities plus owner’s equity. Indeed, it received its name because it balances according to that equation. Balance sheet assets are drawn from the asset side of the accounting ledger, while liabilities come from the debit side.
By contrast, the income statement captures changes in owners’ equity over a particular period – a year, say, or a quarter. It does this by classifying operating expenses, depreciation, income taxes, extraordinary items and other such financial events as gains and losses. Each income statement entry influences the value of the company’s assets and liabilities.
In theory, there should be no difference in importance between the two parts of the financial report. In practice, however, the two segments have jockeyed for the investor’s favour for decades. The income statement gained the upper hand during the Great Depression, because the market price of assets acquired during the Roaring Twenties had sunk to fractions of their book value. Income and expenses were more important to the investor than balance sheet assets and liabilities. In recent years the pendulum of accounting theory has shifted back toward the balance sheet.
Whichever part of the financial report you prefer, both parts have roles to play in investment decisions. Using only a firm's balance sheet, you can compare current assets and current liabilities to assess liquidity. You can compare debt to shareholder's equity to see how leveraged the company is. And you can get a better idea of whether the assets might include some hidden value or hidden risk.
Using the income statement, you can quickly figure cash flow, profit margins and other important indicators of how the business is doing. Of course, accounting is partly art, partly science. The income statement includes judgment calls by both management and the company's auditors. These judgments can substantially affect a firm's showing in a given period. So read the footnotes, since these often disclose how the company arrived at some of its balance sheet numbers. Footnotes can also disclose other potentially useful information.
We can now return to the question posed at the beginning of this section: “How do you calculate cash flow?” The answer is in the profit and loss statement. Cash flow is total revenue from oil and gas sales, from which you deduct operating expenses, cash taxes, royalties and interest payments. As we discussed earlier, cash flow is a particularly important concept for oil and gas investors. Petroleum companies expand operations from cash flow, which provides more investment capital than profits.
Also known as a value investor, the fundamentalist tries to choose growing, profitable stocks by comparing companies in terms of financial results, management, production and other business fundamentals.
This approach sets fundamentalists apart from technical analysts, who study previous trading patterns to forecast market direction. These pages suggest elsewhere that technical analysis has an important role to play in oil and gas investing. Technical analysis applies across industries, however; fundamental analysis does not. In its fundamentals, petroleum is different from other sectors, beginning with the exploration and development cycle.
As Pentti Karkkainen explains it, this cycle shifts between activity and payoff – the risk and reward segments of petroleum exploration, development and production. You might think of activity and payoff as, respectively, the debit and credit columns in a ledger.
Each side of the cycle has three parts. During the activity part of the cycle, the company acquires a parcel of undeveloped land – usually from government. Then comes exploration on that land, including drilling a well. The third stage in the cycle comes from developing whatever oil or gas you find, so you can begin taking it to market. All of this costs money.
The three parts of the payoff side include first the booking of oil and gas “reserves” – estimates of the volumes and values of commercial oil and gas that your development has created. Then comes petroleum production. Finally comes the cash flow that enables activity to continue.
[Insert chart from Karkkainen, p. 149]
Based on this simple cycle, Karkkainen suggests that the chart of a small oil company during a single cycle will frequently look like the one above. “We believe a period of weakness and consolidation will typically follow an exploration event as the company enters the development stage of the cycle,” he explained. “Uncertainty surrounding the cost of development and timing of production will be enough to cause this decline. The depth and length of this valley is a function of two things: the cost of development and the timing of production.”
Karkkainen is thus able to successfully connect the stock market behaviour of oil and gas shares with the petroleum cycle. His graph also successfully suggests a company’s path to maturity. “The mature phase of the exploration and development cycle is characterized by declining production and not surprisingly a declining stock chart,” he said. “The key to maintaining an upward trending stock, in a flat commodity environment, is to successfully reinvest the cash flow from one cycle into more undeveloped land and to successfully initiate new cycles.”
Karkkainen’s simple chart explains stock behaviour from the fundamentalist’s perspective. Simply put, the fever chart reflects investor perceptions of a company’s performance and growth potential.
What you want in a petroleum company, said Karkkainen, are low costs per unit of oil or gas, fast cycle time, and operations that recycle internally generated cash flow. “Costs, timeliness and the ability to internalize the cycle are three important variables for the investor when looking at an exploration and development cycle. Costs are an obvious consideration.... Timeliness refers to the length of time from discovery to production, with shorter being better than longer.... The final factor, the ability to internalize the cycle, refers to a company’s ability to be self-financing. External financing, be it debt or equity, dilutes the benefits of the incremental production and cash flow to existing shareholders.”
Karkkainen explains the fundamental analysis of oil companies in some detail. These pages will touch on his explanations, but focus on formulas that will help you better understand the companies you invest in. A simple way to begin is to understand how analytical tables work.
Analytical tables are the repositories of key information for the value investor – a breed whose most famous names include Benjamin Graham, David Dodd and Warren Buffett. Buffet is the most famous investor among the three. As the authors of the bible of value investing, however, Graham and Dodd are its patron saints. They use information mostly derived from the company’s financial report and the stock market ticker, which provides fundamental information about stock prices and volumes.
In a famous passage from the first edition of Security Analysis, which they wrote during the Great Depression, the two authors explained their perception of stock market dynamics. “The market is not a weighing machine, on which the value of each issue is recorded by an exact and impersonal mechanism, in accordance with its specific qualities,” they wrote. “Rather should we say that the market is a voting machine, whereon countless individuals register choices which are the product partly of reason and partly of emotion.” If you are a value investor, your focus is on discovering undervalued stocks, and buying them before the rest of the market realizes their real worth.
Graham and Dodd’s classic has been updated five times since it first appeared in print. In the most recent edition, the authors wrote that oil and mining companies “are subject to special factors bearing on amortization.... In addition to ordinary depreciation on buildings and equipment, they must allow for depletion of their ore, oil, and similar non-renewable reserves. Mining companies also incur exploration and development expense; the corresponding charges for oil and gas producers would come under the heading of unproductive leases, dry holes, and drilling costs in which ‘intangible drilling costs’ have a special accounting and tax status.”
They concluded, “These items are significant in their bearing on the true profits, and they are often troublesome to the analyst because different enterprises use varying methods to deal with these figures in their accounts.” The two major approaches to oil and gas accounting are called “successful efforts” accounting and “full cost” accounting.
Using a successful efforts approach, the company only capitalizes its successful wells. If a well locates oil or gas, the company writes it into its books as an asset. If it comes up as a duster – a dry hole – it is written off as a loss. Canada’s integrated oil companies, which are large and have diverse business operations, use successful efforts accounting.
Unlike integrated companies, Canadian oil and gas producers use the full cost method, the development of which is an unsung triumph of the Canadian accounting profession. Although many US producers also use full cost accounting and the original idea came from America, the Canadian system is a marvel of accounting theory. Here is how it developed.
Around 1960, the US-based accounting firm of Arthur Andersen published a booklet setting out their partners’ views in support of a form of full cost petroleum accounting. This contributed greatly to the theory of full costing, which at the time was still an accounting system on shaky ground.
In 1963, Professor W.B. Coutts of the University of Toronto released Accounting Problems in the Oil and Gas Industry. This publication was the outcome of a project that began in Calgary. A study group of chartered accountants had asked Coutts to review the practices in use and the reasons for each of them. As the book’s foreword explained, “the practices now being used are so diverse and produce such different results that attempts at intelligent comparisons of the financial position and results between some of the companies are virtually impossible. In addition, there seems to be a general feeling among those associated with the industry that none of the existing approaches is entirely satisfactory.” This was one of the first Canadian reports to recommend a full cost approach to petroleum accounting.
A number of Canadian oil and gas companies had already begun to adopt the method of accounting for exploration and development expenditures. Others now made the move.
“Companies outside the oil industry have adhered closely to the concept of full cost accounting,” Central Del Rio Oils (which later merged into PanCanadian) explained in its 1964 annual report, “but oil companies have departed from that concept in one important respect, by deducting from cash profit, in lump sums, the widely varying costs of lands abandoned, dry holes drilled and geological and geophysical work carried out during each year. That practice often produces inflation of net profit in a year of poor revenues, when land abandonments have been minimal or little expenditure has been made on exploration in search of new reserves. If both of these conditions apply, the result may be quite misleading. Conversely, in a year of good revenues, with substantial land abandonments or large expenditures on exploration, or both, net profit may be unrealistically low. Therefore, the net profit figures in many oil company financial statements have little meaning.”
The trend to full cost accounting had clearly begun, but different companies were using different approaches. An organization of petroleum accountants established a committee to address the lack of uniformity. Chairman Graham Bennett and most committee members were chartered accountants; their 1965 report was titled “Study of Full Cost Accounting.”
“The success of a company engaged in exploration for and production of oil and gas,” they said, “lies primarily in its ability to discover oil and gas reserves. In this quest for oil and gas, a company invests monies in many different ventures in widespread areas. It does this with the full expectation that many of these individual ventures will be fruitless and will eventually be abandoned. It recognizes, however, that success in the other areas must recoup all monies spent in order to provide an eventual profit. Because of this, proponents of full cost accounting believe that the relationship of reserves found to the total cost of finding those reserves should be disclosed in the accounts of the company by capitalizing all exploration costs. The cost of drilling dry holes and the cost of other non-productive exploration activities are a necessary part of the total or full cost of discovering and developing the reserves.”
Read that paragraph again carefully. It provides a clear explanation of the basic rationale behind full cost accounting.
A Petroleum Accountants Society task force published another important paper in the Canadian Chartered Accountant in 1965. By describing the work of the task force and the problems of applying depletion and depreciation theory to oil and gas, Graham Lebourveau helped the industry develop a standard that applied to both exploration and development.
The idea is simple. “Since the quantity of recoverable oil or gas in place is the major factor in determining its value,” he wrote, “it follows that the only accurate method of calculating depreciation is on a unit-of-production basis. This involves estimating the number of barrels of oil or the number of cubic feet of gas that can be recovered from a particular location, and dividing the result into the cost of the property. A unit cost is thus established which can be applied to the quantity of gas or oil produced during the period to give the depletion charges.”
For many reasons, putting that simple theory into practice was quite difficult. When a manufacturing company depreciates a widget-making machine, for example, it usually does so with clear expectations about how many years of useful life to expect from that contraption. By contrast, there are a lot of imponderables to take into account if you want to amortize an oilwell’s gathering pipelines, for example, over the estimated life of the reserves it will help produce.
As the task force developed these ideas, its members argued that full cost accounting had much to recommend it. A lot of other accountants agreed. Full cost accounting soon became standard among Canadian oil companies (although not among “the majors” – the international oil companies that generally followed American or British rules, and the integrated oil companies.)
Full cost accounting was being established, but it was still not a fully developed system. The basic principles were clear, but the practice still suffered from lack of uniformity. Different companies developed different systems.
The move to full cost accounting received another important boost in 1971, when a second article appeared in the Canadian Chartered Accountant. “Full Costing for Petroleum Exploration,” had quite an impact on the sector. Three chartered accountants from Alberta – John Bowles, John Rooney and Robert Waller – wrote this commentary to explain how and why the approach had developed. So doing, they helped codify the practice and explain the theory.
A task force comprised of representatives from major CA firms and financial executives from petroleum companies and other interested parties developed definitive rules for the application of full cost accounting in 1985-86. In 1986, the Canadian Institute brought the process nearer to completion by issuing an accounting guideline for applying the full cost method. The Canadian Institute of Chartered Accountants (CICA) issued a revision to this document in 1990.
Among many suggestions, the CICA guidelines recommended that conventional oil and gas acquisition, exploration and development costs be capitalized country-by-country. Each country would be a cost centre, and costs accumulated within each of those centres would be depleted and depreciated. The guideline recommended the unit of production method for depletion and depreciation based on the relationship between oil and gas produced in a period to proved reserves. It also recommended procedures for determining the limit of costs to be capitalized (the “ceiling test”), and accounting for properties sold.
While Canadian exploration and production companies almost universally adopted full cost accounting, American companies had trouble making up their minds. In the most recent edition of Graham and Dodd’s Security Analysis, the authors grumped considerably about the schizophrenia in the United States with respect to using two so different accounting approaches, but in the end they took a practical approach to the problem. “The analyst should not lose sight of an important fact; usually, the oil and gas company’s largest asset, oil and gas underground, is not on the books at all,” they report. “The oil analyst is probably better served pursuing information about existing reserves and their future cash inflows than by spending the same amount of time trying to untangle the accounting differences.”
The Graham and Dodd concern about whether oil and gas reserves were reported remains a serious issue. At this writing, Canadian companies generally give regular reports on reserves, although under Canadian securities rules they do not need to do so. They are only required to estimate their reserves when they are preparing prospectuses for new share issues. The quality of those reports has sometimes been an issue, however.
Reserve estimates varied considerably in quality from company to company. This is because the calculation of oil and gas reserves does not operate by universal standards, and most companies book their reserves numbers through internal calculations. By definition, reserves are estimates of the amount of oil or gas that can be taken out of a given pool under forecast economic conditions, with known technology.
Guesswork and subjectivity are therefore part of the equation. To make matters worse, different methods of making the calculations give different results. You do not need to be wildly optimistic to book reserves that are wildly different from those of a more conservative company with a similar play.
Careless rules around the booking of reserves have left room for abuse, which has duly been taken advantage of. A prominent case occurred in the late 1990s, when Big Bear Exploration bought Blue Range Resource Corp. Big Bear soon found itself under bankruptcy protection, and its president alleged that Blue Range had overstated its natural gas reserves during negotiations.
In response, the Alberta Securities Commission proposed rules on how the industry would calculate and communicate reserves. Under the new regime, all public oil and gas companies would annually disclose their reserves, as calculated by independent consultants. This would provide investors and analysts alike with better, consistent information about the stocks they follow.
Big Canadian oil companies say this proposal would “hurt their chances of raising funds in the US,” Andrea Lorenz explained in the authoritative magazine Oilweek. “The complaint is that the proposals continue to provide information that differs from what American investors see in reports required by the US Securities and Exchange Commission.”
The issue was a complex one, but it boiled down to the difference between “proved” and “probable” reserves. Proved reserves are there with a great deal of certainty – about 90 percent. Probable reserves are just that – probably there, but with only 50 percent certain.
The American SEC does not allow financial reports to carry estimates of probable reserves, even though companies frequently offer those numbers in news releases, for example. By contrast, the Canadian proposal would require oil companies to report both proved and probable reserves, thereby demanding greater disclosure than required in the US.
As Lorenz explains, big oil in Canada objected to this proposal. They argue that it would put them at a disadvantage to their American competitors, and in the capital markets that provide most of the funding they require. Those objections notwithstanding, the new requirement is likely to stand. For the value investor, this is good news.
Consistent and complete information is essential for the fundamentalist, who is like a savvy bargain hunter at a garage sale. She uses a toolbox of ideas to find undervalued stocks that other investors have missed. Many of those tools apply mathematical formulas to information taken from the company’s financial statements and the stock market ticker. Thus, key information is generally summed up in tabular form. But it was created on spreadsheets of sometimes-considerable complexity.
The informed investor should understand what those spreadsheets are doing, and what the numbers in analytical tables mean. To illustrate this aspect of petroleum analysis, the following pages consider key numbers on Peyto Petroleum that Todd Kepler, a BMO Nesbitt analyst, contributed to an analytical table.
For this study, we chose Kepler and Peyto at random. However, a quick review of Peyto’s chart shows that the company was a great success in its first few years of life. Its shares traded for twenty-five cents apiece on the Vancouver Stock Exchange (now the Venture Exchange) when the company went public in 1998. They were worth $4.10 and traded on the TSE when Kepler did his analysis four years later.
Kepler’s table included actual results for 2000, and estimates for both 2001 and 2002. It investigated the three “fundamentals” of Peyto’s performance: finances, operations and share valuations. Each week Kepler and his fellow BMO Nesbitt analysts summarize this information for forty different Canadian energy companies with operations in Canada. Like other brokerage houses, the company distributes this information, with comment, to well-heeled clients.
Analytical tables enable the investor to compare senior, intermediate and junior petroleum producers to each other. Frustratingly for many people, however, analytical tables typically use abbreviations without explanation. They assume that the reader understands the concepts – mistakenly, in the case of most retail investors and many brokers. This is a shame, because if you understand the values described in these tables you can make quick but sensible judgements about the company’s health and prospects for growth.
The following sections explain Kepler’s tables, bit by bit. They show how one analyst analysed a single company’s finances, operations and share valuations, the three fundamentals.
First came the financial information, which requires a fair amount of comment.
Financial Information
Abbreviation | Translation | 2000 | 2001E | 2002E | Growth |
BMO NB CFPS (FD) | Cash Flow per Share, Fully Diluted, using BMO Nesbitt assumptions | $ 0.34 | $ 0.85 | $ 1.05 | 209% |
DACF Multiple | Debt-adjusted Cash Flow Multiple | 5.7 | 4.8 | 4.9 |
|
CFPS Sensitivities | Cash Flow Per Share Sensitivities |
|
| 1%*; 2%** |
|
EPS | Earnings Per Share | $ 0.51 | $ 0.43 | $ 0.50 |
|
P/E Multiple | Price to Earnings Multiple |
| 9.5 | 8.2 |
|
ROE | Return on Equity |
|
| 4% |
|
* Oil 2002E, % @ $1.00/bbl.
**Gas 2002E, % @ $0.10/mcf
To make sense of this table, you need to understand the importance of per share data and the use of multiples. Also important are the sensitivities and return on equity. We must now turn to those concepts.
Every stock has a value on the market, known as its share price. The purpose of fundamental analysis is to determine the value of an individual share, so you can judge whether the market price makes fundamental sense. This is why per share values and multiples are so important.
Full Dilution: Returning to Kepler’s abbreviations, the first is “BMO NB CFPS (FD).” At first glance, this would seem to be the murkiest of the lot, but it is not. Once you get beyond the jargon, it is a simple concept.
The letters, “BMO NB,” mean that the analysis uses standard assumptions about the economy and commodity prices from Kepler’s employer, the Bank of Montreal’s Nesbitt Burns brokerage. The second group, “CFPS (FD),” means “cash flow per share, fully diluted.”
Cash flow in this context is known as “reported cash flow,” and it has two definitions, both of which require a certain amount of accounting knowledge. One definition is “cash flow from operations, before exploration charges.” Another is “net income plus non-cash charges such as depreciation, depletion and amortization, site restoration, and deferred taxes.” Used properly, cash flow is an elixir for corporate growth. More than profits, it makes exploration and development possible.
To understand what the formulas mean, we need to understand how they are created. In this instance, we must understand the concept of “fully diluted” shares – a number that includes both real and phantom shares.
The real shares consist of stock that already exists. The number used to describe the inventory of existing share certificates is known as “basic shares” or “shares outstanding.” The phantom shares are the stock that would exist if all outstanding stock options, warrants and other such instruments were suddenly converted into shares.
If those conversions took place, more shares would have interests in Peyto’s cash flow, profits and assets. This would dilute the holdings of other shareholders, as if someone had poured tap water into a bottle of old Scotch.
You calculate stock market multiples in this way: divide a stock’s share price by a fundamental number. These numbers compare the stock price to such accounting values as earnings and cash flow.
Three Price Ratios – Earnings, Cash Flow and Debt-Adjusted Cash Flow: Most investors want those accounting values to be stronger rather than weaker, so they prefer a lower multiple to a higher one. One example is the P/E multiple, which is stock price divided by earnings per share. A stock priced at $10 with earnings of $1.50 has a P/E of 6.67. A company with better earnings has a lower multiple – for example, a $10 share with of $2 per share has a P/E of 5.0. All else being equal, the lower multiple is better.
As Kepler’s report shows, analysts do consider the common P/E multiple for oil companies, but it is less significant for petroleum companies than for manufacturing and marketing firms. The price to cash flow ratio (P/CF) is a superior indicator of a petroleum company’s growth rate, and is widely used among analysts.
This multiple will rise as high as seven or eight in a great bull market, and it rarely drops below two. The exception was 1999-2000, when market scepticism about the future of high oil and gas prices kept those multiples low. In some cases, stocks were trading at small premiums to their forecast annual cash flow. To understand how wildly undervalued they were, let’s use Peyto as an example. According to Kepler’s estimates, that company had cash flow per share of $0.85 in 2001. But on New Year’s Eve, 2000, Peyto’s shares traded for $1.40. Although no one knew it for sure at the time, Peyto’s price to forward cash flow was about 1.7 – an absurdly low number. With such large increases in cash flow in the works, Peyto’s stock price rose rapidly.
The analyst’s job is to look for risks to growth. One such risk is debt. For this, they have created a killer multiple by dividing debt-adjusted cash flow into the share price. This is known as the DACF multiple.
The background is fascinating, and well represented by the spectacular collapse of Dome Petroleum in the mid-1980s. In an environment of high interest rates and declining commodity prices, Dome owed more than $7 billion (Canadian) to the moneylenders.
Dome’s stock price tumbled, which should have brought its debt-adjusted cash flow multiple into balance. But this did not happen, because using this calculation the company’s cash flow was negative. In theory, DACF reached infinity and the company went bust. Before the debt crisis, Dome had been a market darling. Amoco Corporation bought the bankrupt producer for $5.4 billion (Canadian), in 1988.
To guard against such risk, Kepler’s table calculated Peyto’s debt-adjusted cash flow per share. Debt-adjusted cash flow is “discretionary cash flow plus all financial charges, including interest expense and preferred share dividends, and current income taxes,” according to Pentti Karkkainen.
Since the DACF multiple factors debt-related costs and income taxes into the cash flow forecast, it helps protect the investor from Dome-style debacles. Kepler estimated Peyto’s 2002 DACF multiple at 4.9. This compared favourably with the company’s peers. The company was not overly burdened with debt.
Sensitivities: There is a saying that you should be wary of forecasts if they attempt to predict the future, and that is one of the problems with fundamental analysis. Estimating a company’s future financial multiples is a treacherous job, because it depends so heavily on assumptions about intrinsically risky commodity cycles and exploration results.
Analysts like Kepler forecast a company’s financial future by making assumptions about a company’s likely exploration success rate, its production volumes and the prices it will receive for oil and gas. Of course, Kepler and his colleagues also have a clear understanding about one of the immutable truths of oil and gas price forecasting: You will always be wrong. Accordingly, his table includes an entry for the coming year abbreviated “CFPS Sensitivities” – cash flow per share sensitivities.
What this means is that for every dollar his firm’s oil price forecast is off, his cash flow per share estimate will be off by one per cent. For every ten cents its gas price forecast is off, his cash flow per share estimate will be off by two per cent.
Analysts like Kepler also make educated guesses about probable costs, taxes, royalties and interest expenses. These initial assumptions are frequently off by a country mile, so they make adjustments from time to time.
All this raises an important question: do analysts follow the fortunes of their companies, or do they predict them? According to one school, analysts are continually adjusting their analysis because they are staying on the story. They need to fine-tune their forecasts as the business story unfolds. According to the other school, they are hiding their past, grievous errors in analysis.
The next portion of Kepler’s table deals with operating results. To understand operating results, you need to understand the petroleum company’s financial results in their simplest form. The company’s business is to employ pools of talent and capital for oil and gas production. You produce oil and gas through processes known as “operations.” Kepler’s operational tables calculate the company’s natural gas production in millions of cubic feet per day (mmcf/d).
“Oil and Liquids” refers to the production of oil and natural gas liquids. Liquids are such by-products of natural gas as condensate and propane, which are liquid in form at normal atmospheric temperature and pressure. Oil and liquids are expressed in thousands of barrels per day (mbbl/d).
Operational Information
Abbreviation | 2000 | 2001E | 2002E |
Natural gas (mmcf/d) | 6.8 | 21 | 39 |
Oil and Liquids (mbbl/d) | 0.2 | 0.8 | 1.3 |
Kepler’s table showed a company that grew dramatically for two years. In Kepler’s view, Peyto would also grow in the year ahead.
Oil and gas are related but different commodities, with different price cycles. But to better understand companies that produce them both, you have to be able to lump oil and gas into a single production total. This is known as barrels of oil equivalent per day – abbreviated below as “BOE/D (6:1).”
Operational Information, continued
Abbreviation | Translation | 2002E | Growth: 2000/2002 |
BOE/D (6:1) | Barrels of oil equivalent per day |
| 463% |
Percent Oil | Oil’s share of total production | 17% |
|
The notation “6:1” means that Kepler converted natural gas to oil using the convention that six million cubic feet of gas were equal to one thousand barrels of oil. This is an aggressive ratio. Most analysts still assume that ten (not six) million cubic feet of gas are equivalent to a thousand barrels of oil. A ratio of 10:1 is more conservative, and it is easier to calculate in your head: 39 million cubic feet of gas equal 390 barrels of oil.
Whichever formula you use, at best you will be comparing Gala apples to Granny Smiths. But at least it isn’t apples to oranges. The table above shows Kepler’s calculation of Peyto’s forecast growth in production. According to his analysis, by year-end 2002 Peyto’s total production will have grown by 463 percent over a three-year period.
The above table also calculates oil’s growing share of the company’s total production. A company can change its cyclical risk by changing the amount of oil and gas production at its field facilities. This is because blending the crude oil price cycle with the natural gas cycle smoothes out the two price charts. This means less volatility.
Net Assets and Enterprise Value: The previous discussion covered calculations of Peyto’s financial and operational results. But Kepler also made estimates of the company’s real value. The first of these was net asset value per share (“NAVPS”).
Kepler began by calculating net asset value – the estimated total value of a company’s assets, less its liabilities. Explains Pentti Karkkainen, “for pure exploration and production companies, the value of their assets is simply the discounted value of the cash flow stream expected to be produced from the existing reserve base, plus the estimated value of undeveloped land and other assets.”
Asset Value
Abbreviation | Translation | Value |
2000 NAVPS | Net Asset Value Per Share (for year 2000) | $3.59 |
Price/NAVPS | Share price divided by NAVPS | 108% |
EV/BOE Proved Reserves (6:1) | Enterprise value divided by barrels of oil equivalent of proved reserves. | $20.40 |
EV2002E/BOE/D (6:1) | Estimated 2002 Enterprise Value divided by estimated daily production | $30,428 |
Target EV/2002 BOE/D (6:1) | Target 2002 Enterprise Value divided by estimated daily production | $31,232 |
Enterprise Value (EV) ($mm) | Enterprise value in $millions | $237 |
To calculate net asset value per share, you divide NAV by the number of shares outstanding. The calculations in the next three tables are based upon basic shares – “shares outstanding” – rather than by the fully diluted number used to arrive at cash flow per share.
According to the table, net asset value per share is $3.59. With the share price of $4.10 that we noted earlier, Peyto was trading at a modest eight percent premium over its basic value. It is therefore not overpriced.
Kepler uses two other methods to calculate Peyto’s per share value in the table above. They are based upon a calculation known as enterprise value (EV), which is “market value of equity (share price times shares outstanding) plus preferred share capital, long-term debt or debt equivalent, less working capital.”
In the table, Kepler makes two calculations. The first is Peyto’s estimated enterprise value in 2002 divided by its daily production. Using a recent stock price ($4.10), this formula gives an estimate of the cash value of just one daily barrel of oil or gas production: $30,428. Kepler makes the second calculation using his target share price for the stock, $4.25. That calculation values a barrel of daily productive capacity at $31,232, which is a reasonable number.
Capitalization and Leverage
Abbreviation | Translation | Value |
Shares O/S (mm) | Shares outstanding | 41.8 |
Market capitalization | Market capitalization in $millions | 171 |
2002E Long-term Debt + WCD ($mm) | Estimated long-term debt plus estimated working capital deficiency | 66 |
2002E Debt/CF | Estimated debt divided by cash flow | 1.4 |
RLI (yrs) | Reserve Life Index | 7 |
The final segment of Kepler’s table, shown above, introduces miscellaneous ideas. The company has forty-eight million shares outstanding. At $4.10 per share, its market capitalization is therefore $171 million.
Kepler estimated that the Peyto’s long-term debt and working capital deficiency in the coming year would be $66 million. From that number, he calculated that the company had a forward debt to cash flow multiple of 1.4, which is reasonable.
His final calculation is Peyto’s reserves life index (RLI). You get this number by dividing total reserves by the volume of oil and gas it produces in a year. Kepler’s result is 7, which means that if the company produces at today’s levels and does not find any more oil or gas, its reserves will dry up in seven years.
For a Canadian junior producer, this is a long reserve life, and it isn’t necessarily a good thing. One interpretation, for example, is that companies with shorter RLIs are turning their gas into cash more aggressively than Peyto. They therefore provide greater short-term gratification.
In the beginning, this chapter discussed how a price bubble in natural gas had pushed through the oil and gas system like a pig through a snake. The TSE’s Oil and Gas Index, whose components were working with record cash flow and profit levels, broke one record after another.
The next chapter describes a companion phenomenon to the exploration and production cycle, a cycle that follows the flow of money from the capital-intensive petroleum industry into the service sector.
Californians suffered rolling electricity blackouts in the winter of 2001, and natural gas prices shattered records day after day. An earlier chapter explains why.
First, natural gas is an increasingly important fuel for electricity generation in North America. Second, record cold weather covered most of the Lower 48 and parts of Canada. Gas demand went wild, and the gas industry could not get any more gas to market because pipelines were full. The following chart illustrates the outcome, which included natural gas prices in California as high as $55.26 (US) per thousand cubic feet
Source: Reuters; permission required.
The North American economy quickly responded to the price signals generated by the apparent energy crisis. Petrochemical and fertilizer manufacturers closed plants. Instead of manufacturing, they sold their gas into profitable spot markets. On the electricity side, power-intensive aluminum plants stopped manufacturing aluminum so they could sell their electricity into the grid. Employees received full wages and benefits in idle plants, yet their employers made record profits from selling raw energy and power.
Energy consumers were able to locate natural gas during the energy crisis, but this silver lining had a cloud: they had to pay prices that had been inconceivable only months before. Small trades on the spot market actually exceeded US$150 per billion BTUs on a few occasions, compared to “normal” prices of two dollars or less. As you would expect, high prices fuelled conservation drives in industry and business and at home.
Those prices also fuelled the push for energy production and the search for new supply. Gas production set new records. So did drilling.
In Canada, the number of wells “rig-released” (completed) during 2001 was 18,137. Three Canadian independents – large producers listed on Canada’s stock exchanges, and headquartered in Calgary – drilled about a quarter of the total. These were PanCanadian Energy Corporation (1,274 reported completions), Alberta Energy Company (1,306) and Husky Oil Operations (1,108). They were by far the biggest drillers in the oilpatch. Five of the top twelve operators in Canada during that year were American-owned. These included Devon Canada Corporation (697 wells drilled), Conoco Canada (630), Burlington Resources Canada (500), Anadarko Canada (500) and Apache Canada (424).
As the industry’s experience in 2001 illustrates, cash flow and other price signals combined with the warm winter of 2002 to provide an astounding corrective to the energy crisis of the previous year. Barely a year after the industry released the tethers on exploration spending, both the oil and gas industries were gorged with petroleum production capacity. Oil and gas prices dropped. Producer cash flow declined, so operators planned deep cuts in exploration and development drilling.
Low finding and development costs are always the key theme in such an environment. According to Ryan Shay, an oil and gas analyst with Sprott Securities, “Financial flexibility, debt leverage, room on bank lines and the ability to spend and buy in this market (are also) a real competitive advantage.” Shay pointed to the falling cost of land at land sales as an example of opportunity for smaller oil and gas companies. As prices declined, it was in their interest to buy assets for future growth. "If you have a good balance sheet, you can go out and buy land” for exploration.
Convoys of trucks rumbled through the north of Alberta and into northeastern British Columbia and Yukon in the winter of 2000. Temporary roads of ice blazed through boreal forest were often their freeways, and some crossed rivers by driving over bridges made of the same. Thermometers registered forty below, and you could hear the trees cracking with cold. Exposed flesh would freeze in minutes.
The trucks were delivering drilling rigs to prospective locations in the north, a job that can require as many as fifty large trailers to move a single rig. They were also taking supplies to the men and women of the rigs, who sometimes live in temporary camps. Thus began the year’s drilling, which broke a five-year-old record. That drilling was the physical manifestation of the huge cash flows these pages discussed in the last chapter.
Extreme conditions are old hat to the Canadian petroleum industry, which prefers the winter drilling in many areas. There are two reasons for this. One is that winter drilling prevents damage to rural roads; another is that hard ice makes it possible to drill in the swamps – known as “muskeg” – of the north.
According to Robert Bott, “about seventy-five workers are directly employed in the drilling of one well, although only four to seven may be on duty at any given time.” Drilling alone requires site preparation workers, drilling crews and geologists, well services, oil field hauling and rig moving, and supplies of everything from fuel and specialty chemicals to water and food, tools and safety equipment.
But drilling is only part of the equation. What the investor needs to know is that drilling and other oilfield-related activity generates the revenues for the large and usually profitable petroleum service sector. From the time a well is no more than a gleam in a geologist’s eye to the day when it is finally depleted and abandoned, oil and gas wells go through life cycles of their own. And those cycles frequently take decades.
Not only do wells experience cycles; so do producing basins like the one in Western Canada. And at each part of that cycle, they provide opportunities for the service sector. In 1997 (the last year for which firm statistics are available), that sector included about 11,600 drilling and service company workers. Another 22,100 worked in oil field service and supply. And yet another 4,000 were employed in industrial and construction activity.
An earlier chapter listed the nine service sector components of the TSE’s oil and gas index. This chapter describes the service cycle, which is a natural complement to the exploration and development cycle we considered in the last chapter.
Earlier in these pages, we discussed the exploration and production cycle in terms of activity and payoff. In an authoritative analysis of the service sector, Miles Lich and Wilf Gobert elaborated upon that cycle. They began by describing three key characteristics of the petroleum industry: It is capital-intensive, it is cyclical and it is seasonal. Let’s look at these.
First, simple economics means oil companies hire expertise in petroleum exploration and production from service companies, rather than keep such expertise on staff. Thus, the petroleum industry’s capital spending plans are a leading indicator of the health of the oilfield services industry. Second, “the petroleum industry is cyclical.... (Exploration and production) companies depend on revenues from sales of commodities with highly volatile prices.... Third, the industry is seasonal. Drilling in Canada falls off dramatically during the spring thaw, which means that (second quarter) revenues generally fall markedly below those of other quarters” – especially the first three months of the year, which includes the winter drilling season.
Individual wells have life cycles of their own, and at different stages require different services. This cycle is a complement to the exploration and development business cycle we discussed in an earlier chapter – the cycle that shifts between activity and payoff, risk and reward. Let’s revisit that cycle, to see where the services fit. People in the oil industry once proclaimed, “Oil is found in the minds of men.” Although today they would add “and women,” the adage is still true. Ideas make it possible to find and produce oil, and those ideas begin with geoscience. While oil companies have geologists and geophysicists on staff or contract, the work of those experts relies heavily on seismic surveys.
Seismic surveys are the records of shock waves (created by small explosions or large, specialized vibrating machines) as they reflect off underground layers of rock. From seismic records, geophysicists can create detailed models of the geology of an area, and anticipate whether petroleum is present. From raw beginnings in the 1920s, seismic-based geophysics has become high tech. Surveys are now possible in two, three and four dimensions. (Four-D surveys show how production affects a large reservoir over time.)
Explorers use specialized software to interpret seismic data, which they buy from seismic companies – only a few of which are publically traded. Two trends began to emerge in the 1990s, each of which contributed to the need for fewer seismic crews.
First, companies began ordering large 3-D seismic surveys rather than the more modest 2-D surveys that have been around for years. Second, they began using existing libraries of 2-D seismic data rather than commissioning new data. This was possible because the Western Canada sedimentary basin was mature while 2-D technology had not changed much.
If these trends continue, the seismic sector in general will not perform well. One example of a publically traded seismic company: Arcis Corporation. Like other seismic firms, Arcis built its business on shooting seismic on contract, and selling data from an extensive library.
Once a company has decided to drill, it acquires the mineral rights to the piece of land, usually from a public auction of Crown (government) land. Land sales in Alberta take place every two weeks, and auction results consist of total number of hectares sold, plus price per hectare. These values are important forward indicators of the amount of activity that will take place in the year ahead: You generally don’t buy land unless you plan to explore it.
At one time, as much as 30 percent of the capital spent by exploration and production companies went into land. However, in Western Canada land became relatively cheaper during the 1990s; by the year 2000, it represented about 14 percent of a company’s exploration costs. By contrast, drilling is the industry’s biggest single capital cost – nearly half the total.
For the exploration and production company, drilling is decisive – the moment of truth. As Robert Bott explained, “drillers turn theory into hard economic reality. Even when a development well is located right between two producing wells, there is still a risk that nothing will be found – and also the possibility of greater-than-expected success.” Until you drill, you just don’t know what’s down there. Because drilling is such a critical part of oil and gas, it is worth investigating how drilling rigs do their work.
The following illustrations explain how jointed pipe drilling does two things. First, it turns a long length or “string” of steel pipe with a drilling bit on the end of it. Second, it clears rock cuttings out of the resulting hole while keeping oil, natural gas and water safely in their underground rock reservoirs.
The first drawing shows the main components of a standard drilling rig, emphasizing the rotary system. The rotary system turns the drill bit.
The second drawing illustrates the rig’s circulating system, which cleans out the hole and controls underground formations and fluids. Let’s first explore the rig in a general way, and then focus on the circulation system.
Illustration #1: Basic drilling. Use illustration cutline to explain rotary system.
Before serious drilling begins, a well site needs to be constructed. This generally involves clearing trees, building an access road and creating a stable base for the rig and related buildings and equipment. Once this is done and the rig is on site, the crew sets “surface casing.”
Surface casing is one of the most important of many safety measures used in oil and gas drilling. To set surface casing, the crew first drills a relatively shallow hole – perhaps 60 to 400 metres (175 to 1200 feet) deep.
Drilling relies on mechanical force, which enables crews to handle large pieces of equipment and turns (rotates) a string of pipe. At the end of that string of pipe is the drill bit. As the bit turns, it eats into the rock.
As the hole deepens, workers on the rig stop drilling from time to time to add new lengths of pipe to the drilling string. These lengths of pipe are typically 9.5 metres (30 feet) in length. Depending on the size of the drilling rig, up to three of these sections of pipe can be added at a time.
Illustration #2: Somewhat like the electric drill you may use at home, this process cuts a hole into Earth’s surface. Like the wood shavings spinning out of the bit of your electric drill, a lot of waste material forms as a rotary rig drills into the ground. One of the purposes of the circulatory system is to flush those wastes from the hole.
The circulatory system also prevents underground fluids – oil, natural gas and water, for example – from rushing out of the hole in a “blowout” or the much-less-severe “uncontrolled flow”. The most important feature of drilling that keeps the well balanced is known as “mud”, or circulating fluid.
Experienced drillers can add such chemicals as barite to water to increase or reduce the weight of the drilling mud. The weight of the mud is the first line of protection against an uncontrolled flow of sour gas. Some kinds of mud create a thin seal along the side of the hole, creating a protective barrier between the well and the layers of rock it is penetrating.
As we shall see in a later discussion, the circulation system has other safety features. The most important are blowout preventers, which have special significance during sour gas drilling.
Completions: If drilling successfully finds oil or gas, the well is completed for production. Completing the well involves cementing steel pipe into the hole. Known as “casing,” this steel skin acts as a barrier in two ways.
First, it prevents water, rock and other debris from caving into the well. This could clog the well or contaminate the oil and gas, making production more difficult or even impossible.
Second, it prevents the oil and gas from escaping into other reservoir rocks. This has obvious economic benefits to the company, since lost oil and gas means lost revenue. It is also environmentally indispensable. When oil or gas leak through steel casing, they can contaminate reservoirs of groundwater used for household and farmyard use.
The main variable in drilling is well depth. As well depths deepen, costs rise exponentially. Compared to shallow wells (as shallow as 500 metres in Western Canada), deep wells can mean drilling as much as 6000 metres into the ground. These wells require big rigs, large-horsepower engines, hefty quantities of supplies and tools (many of which, like drillbits, quickly wear out) and drilling time.
While the average well in Western Canada takes less than eight days to drill, deep wells in the Alberta foothills have been known to take months to drill. Drilling costs include a “dayrate” for the rig: up to $15,000 for a large rig, depending on market conditions. In addition, supplies and services are costly. Because of the high cost of deep drilling, there are many cases on record of multi-million-dollar dry holes.
Headquartered in Calgary, Precision Drilling became North America’s largest operator of onshore drilling rigs through a series of acquisitions in the 1990s. Investors following this company should stay alert to dayrates and rig utilization rates.
Dayrates are the source of the average daily revenue that a company’s rigs generate. They fluctuate wildly during the boom-and-bust commodity cycle, less so during the seasonal cycle. For example, drillers can charge from $5,000 to $10,000 per day for a small rig, and from $9,500 to $15,000 per day for the biggest land rigs. It all depends on market conditions.
Rig utilization rates refer to the percentage of a company’s rigs that are operating at any one time. These rates are also dependent on commodity cycles, but seasonal cycles dominate. The speed with which seasonal and commodity-price factors affect the sector can be dramatic. For example, in 1999 (a bust year) Canada’s drilling fleet utilization rate dropped to about 10 percent in May – partly because of the weather and other seasonal factors, partly because of a gloom price outlook. Yet only nine months later, during the peak-drilling season, almost all of the fleet’s rigs were at work.
During the 1990s, average annual rig utilization rates were all over the map. In one boom year (1997,) the rig utilization rate was 72 percent. In the bust that arrived less than two years later, the rate was less than 40 percent.
Seasonal and boom-and-bust cycles are part of life for the petroleum industry, as we have discussed elsewhere. But for service companies, they lead to wild swings in financial results and therefore stock prices. The following table, based upon a hypothetical drilling company, illustrates why.
The Drilling Revenue Cycle
| Boom Year | Bust Year |
Utilization Rate | 70% | 40% |
Deep Rig Dayrate | $15,000 | $9,500 |
Medium Rig Dayrate | $10,000 | $7,500 |
Shallow Rig Dayrate | $8,000 | $5,000 |
Deep Rig Revenue* | $315,000 | $114,000 |
Medium Rig Revenue* | $350,000 | $150,000 |
Shallow Rig Revenue* | $112,000 | $40,000 |
Total Daily Revenue | $777,000 | $304,000 |
*Assumes 30 deep rigs (“triples”), 50 medium rigs (“doubles”)
and 20 shallow (“single”) and slant rigs.
In each rig category, gross revenue declined by more than half in the bust – or, positively, it more than doubled in the good year. Cash flow and profits are even more dramatically affected during the ups and downs of the cycle, because many costs need to be covered whether the rigs are working or not.
Once drilling is complete, the operator has to evaluate the well to see whether the reservoir formation it has encountered justifies completing the well as a producer or abandoning it as a dry hole. This requires the use of specialized equipment, which analyses the well’s oil and gas potential using “open-hole logging” technology.
If the well was a success, the company cements casing (steel pipe) into the well and commissions a second evaluation (a “cased-hole log”) of the well to locate the hydrocarbons. The service company lowers a perforation gun into the well, to the producing horizon. This gun opens up the reservoir with a series of directed explosions. The well is then flow-tested, to establish what kind of equipment is needed to bring it on production.
It is not until this point that the well’s operator makes a final decision whether to bring the well on production. At this time the well’s owner requires other services to complete the well. One common technique is know as acidizing the well – pumping an acid solution into the wellbore, then flowing it out again. This repairs damage often done to the reservoir during drilling. Another completion technique is known as fracturing, or “fracing” the reservoir – pumping in a solution of sand and gel at such high pressure that it creates small fissures in the rock.
While completions can be performed on old wells to stimulate production just as easily new ones, completion companies can serve wells throughout their productive life. But “ the fortunes of those completion companies whose services are most closely related to drilling follow those of the drilling companies,” report Lich and Gobert. “In a weak drilling market, completion and workover companies are in oversupply. Their margins and earnings come under pressure as utilization rates and dayrates are forced lower by the weak business environment.”
The final steps required to bring a well into production are to install artificial lift (pumps) on oil wells, if needed, and to construct small pipelines from the well to either an oil battery (tanks) or to a larger pipeline. When oil is collected in batteries, the company needs to truck production to a central processing facility.
In many cases, other specialized equipment must be installed near the wellhead – for example, units that dehydrate natural gas. The systems used to produce a single well are generally designed with the entire field in mind.
There are two final stages in a well’s life. One is regular service and maintenance, which keep the well producing efficiently. This step includes removing sand from the wellbore, repairing and replacing pumps and stimulating the well through acidizing or fracturing. Well servicing almost invariably requires the use of service rigs.
The last stage in a well’s life is abandonment and reclamation, a process that applies equally to dry holes and wells that are no longer economic. This stage involves restoring the land on which the well was drilled to its original state, eliminating any leakage of gas or fluids, and filling the wellbore with cement. Because Western Canada’s petroleum industry is now quite mature, this is a growing business.
But that is only the beginning of the story: drilling companies have fixed costs, whether the sector is doing well or badly. Because of fixed costs drilling companies suffer losses – often horrific – during a bust. The same combination of strong margins during the boom and intense competition during the bust contributes to high volatility in petroleum-related service-sector stocks.
Since the service sector is essentially a handmaiden to the producers, which lives on wages established by the petroleum industry’s spending needs, changing patterns in oil and gas spending are of considerable interest to the investor. We will now turn to that matter.
In oil industry parlance, capital spending takes two forms: exploration spending and development spending. The two forms of spending are treated differently for tax purposes, and they occupy different places in the business cycle.
Exploration spending – investment in geophysics and geology, land and exploration drilling – takes place in what Pentti Karkkainen called the “activity” segment of the business cycle. The following chart illustrates the wild ride the industry experienced in this area after the last big boom tapered off in the 1980s.
Source: Canadian Association of Petroleum Producers
Because the chart does not account for the impact of inflation, in real terms these leading indicators in 2000 were still below the levels of the previous major boom.
Development spending takes place after a reservoir has been discovered. During development, the operator drills additional production wells, adds field equipment, implements enhanced oil recovery (“EOR”) schemes and constructs gas-processing plants. These are the developments that you need for what Karkkainen calls the “payoff” side of the business cycle.
Source: Canadian Association of Petroleum Producers
As the chart illustrates, development spending changed substantially during the 1990s, beginning with the boom of 1993. Payoff spending increased dramatically, and stayed high even during periods of low exploration spending. There were two main reasons for this change.
One was the maturation of large fields, and the subsequent focus on smaller fields. Small, low-productivity fields produce less oil or gas per well. To maintain production at high levels therefore requires more wells and more field equipment – pumps, gathering lines and the like.
The other reason for the change in spending patterns was the growing importance of the natural gas industry. Until the late 1980s, government regulators would not permit natural gas to be exported unless there were 25 years of the commodity in reserve, and they were heavily involved in setting prices. However, a 1985 agreement between the federal government led to free market policies as the best incentive to ensure adequate supplies of gas and at the same time yield the best possible price for consumers. This decision made huge amounts of gas suddenly available to the US market. To bring it all into production required new gas plants, more wells and corresponding new field equipment.
Although the amount of spending available to the service sector is far higher than in earlier years, the boom and bust cycle continues. Elsewhere we saw tabular evidence that the service sector is far more volatile than the producing sector, but pictures are more compelling. To illustrate the high volatility of the service sector compared to the oil and gas index (itself considered volatile), consider the following chart.
This chart compares the TSE’s Oil and Gas index to the oil and gas service subindex – which, you will recall, is made up of the service-related components of the Oil and Gas Index. As you can see, the service sector contributes considerably to the volatility of the broader index. Even more than the producing sector, service-related companies are ideal candidates for investors who use market-timing strategies.
Of course, a proper analysis of service companies needs to be used in concert with market timing. Here is a tidy summary of what to look for in the sector. “Oilfield services profits are driven by high utilization rates (keeping in mind that 100 percent utilization is not attainable due to the time required for maintenance and rig moves), strong dayrates, low operating costs and therefore good margins,” wrote Lich and Gobert. “Good products, strong commitment to service, and the formation of strategic alliances with E&P companies will grow the customer base. Technology continues to improve and will improve the bottom line not only by offering new techniques but also by saving money for the E&P companies.” In fundamental analysis of the sector, they suggest, the investor should begin by investigating balance sheet, working capital and cost management. Properly interpreted, these areas show where a company’s strengths and weaknesses lie.
Balance Sheet: Take the balance sheet, which is essentially a snapshot of a company’s financial situation on a given day. Unlike exploration and production companies, firms in oilfield services have assets that depreciate – the “thumper trucks” equipped with specialized vibrating machines for use in seismic surveys, for example. As importantly, the market value of a company’s hard assets can swing wildly between boom and bust: a drilling rig that cost $8 million in a boom can sell for $500,000 or less in a bust.
Boom and bust cycles can be more dramatic in Canada than in America, and there is a smaller investor base in the smaller country. For these and other reasons, Canadian oilfield services companies typically take a more conservative approach to capital structure than do their US cousins. In general, the Canadians have the stronger balance sheets.
Working Capital: The classic definition of working capital is “current assets minus current liabilities.” A more investor-friendly definition is that working capital is the money the company has available to meet its near-term obligations. Short-term in nature, working capital has not been put to work in the company's profit-making business operations. As with most measures of corporate well-being, the need for working capital varies widely among companies within the service sector.
Drilling and well services companies need the least working capital. For practical purposes, their equipment is in storage if it is not in use, and does not require a great deal of money for upkeep. On the other end of the spectrum, distribution and manufacturing companies need the most working capital. Much of this capital is held in the form of inventories of oilfield equipment, for example. Thus, when you evaluate a company’s working capital, you should take into account the business cycle. A company that has a great deal of money tied up in oilfield equipment could be in bad shape if the cycle is turning down, but well positioned if the cycle is going up.
Oilfield service companies use working capital to purchase and build equipment, and to research and develop new technologies. Since each of these functions is likely to lead to depreciating assets, the serious investor should take a keen interest in how the company calculates depreciation.
Depreciation is a non-cash charge on the balance sheet that reduces the value of fixed assets (rigs, trucks, buildings) due to wear, age or obsolescence. Conservative companies depreciate such assets quickly, even though depreciation charges reduce reported net income. As a knowledgeable investor, you should be on the watch for firms playing fast and loose in this grey area.
Managing Costs: In extremely cyclical industries, nothing is more important than managing costs – indeed, the ability to control costs can spell the difference between corporate death and corporate survival. As we saw earlier, a drilling company can see its revenue more than halved when a bust year follows a boom. Even in a “normal” year in Western Canada, the second quarter is typically slow because of the spring thaw and wet weather. If weather conditions are particularly bad, a service company’s second quarter financials can even bleed red ink during a boom.
Dramatic shifts in income call for dramatic approaches to cost control, and a well-managed service company structures its general and administrative costs in such a way that they are self-correcting during a slowdown. Rigorous spending controls during slow periods frequently means lost opportunities when business picks up, because of equipment, inventory and personnel shortages. Nonetheless, it is essential.
Since their most important variable cost is labour, service companies typically pay their field staff a base salary and tie the rest of their compensation to work done. Even unionised workers in manufacturing and fabrication have flexible agreements that enable the company to scale back as needed. Service companies also rely on an army of contract and casual labour during periods of high activity.
Like the industry it serves, the petroleum service sector has undergone dramatic change. Petroleum industry revenue and spending collapsed in 1986, leading to a near-death experience for the sector as a whole. Many companies within the group experienced business failure, with the survivors gobbling up the assets of those that failed.
Among producers, the notion became common that the company that would produce the last barrel of oil or cubic foot of gas in Western Canada would be the lowest-cost producer. Cost cutting became a way of life during the long bear market, which lasted in one form or another until 2000. This environment rewarded service companies with efficient management and cost-saving technology, and it encouraged consolidation within the sector. During the long bear cycle, merger and acquisition activity intensified.
Competition among service companies is quite complex. There are many private drilling companies, for example: mom and pop operations with a single rig. On the other end of the scale, wholly owned subsidiaries of such huge transnational corporations as Halliburton and Schlumberger own drilling rigs and provide suites of services to petroleum producers. Transnational companies like Schlumberger, which has long been known for its advanced open-hole logging technology, often invest heavily in new technology to stay ahead of the crowd. Because much of this technology is proprietary, expensive or both, small players cannot afford to get into the game.
One consequence was consolidation in the sector, which is likely to continue because of the existence in Canada of many private service sector companies. “The appetite here is being driven by the success of certain large US services firms, including Halliburton, Schlumberger, and Baker Hughes,” wrote Lich and Gobert. “The strategy is for a company to provide a wider range of services in hopes of becoming a turnkey solution for exploration and production companies that have large land positions and many wells.”
They continue, “This has worked rather well in the US and is now being undertaken in Canada by Precision Drilling and Plains Energy Services, among others.... The advantage of the strategy is that the multi-service oilfield services company is able to provide many services and handle a large volume of work.” There is also a downside, however: bids on large projects are quite competitive, and margins therefore lower than in contracts for a single service.
These pages explain elsewhere the basic technology for rotary drilling. Drillers used a crude version of the rotary rig in the l9th century petroleum industry, often powered by a mule walking in a circle. But the best-known pioneering effort in rotary drilling took place in 1901 with the drilling of the Spindletop well near Beaumont, Texas. Besides being the first big success in the oil patch with rotary equipment, Spindletop was also a legendary American gusher. It proved the existence of petroleum in salt domes, and it was the first rotary well to use drilling mud as a circulation medium. Rotary drilling arrived in Canada in 1925.
Although drilling rigs became larger and the equipment became more powerful and more reliable, basic rotary drilling technology did not change greatly during most of its first century of existence. However, in the 1980s and 1990s the pace of change began to accelerate. Six important service technologies are helping transform the economics of oil and gas exploration and development, each of them related to drilling.
Auto steering: Auto steering tools enable the drillers to drill perfectly straight holes – a particularly difficult trick in hard, folded geological layers like those in the Rocky Mountain foothills. In the past, folds, faults and fractures in the rock made straight drilling a chronic headache; on tough jobs, drilling crews mechanically adjust the wellbore several or even many times, adding greatly to already high drilling costs. Companies with deep rigs and auto steering tools will increasingly control the deep drilling market.
Directional and Horizontal Wells: Drillers have known since rotary drilling began that the give in steel pipe made it possible to drill at an angle. In the 1950s, they began to perfect the techniques of angled drilling. This led to technologies for directional and horizontal drilling, which are now important instruments in the driller’s toolkit.
Directional drilling enables the driller to reach reservoirs that would otherwise be inaccessible or less economic. These wells begin with a vertical wellbore, then deviate from there toward their intended target – for example, reservoirs under lakes, rivers or swamps or even under towns or environmentally sensitive areas. Directional drilling has other uses – for example, drilling a relief well if a well blows out or catches fire.
Horizontal drilling involves drilling a hole at a ninety-degree angle to a vertical wellbore. By drilling a horizontal well into the reservoir, you get much better reservoir drainage. This means more production and more reserves.
Underbalanced Drilling: These pages describe elsewhere the use of mud (“drilling fluid”) during drilling, a practice that keeps oil and gas within the reservoir until the well is ready for testing or production. Traditionally, mud is composed of dense water- or oil-based liquids, with chemicals added to increase (or decrease) the weight of the mud depending on drilling conditions. In traditional drilling, the weight of the mud must exert greater pressure than that exerted by reservoir fluids wanting to escape. The downside to this practice is that it often forces fluids into the reservoir rock, damaging the formation and reducing potential production.
By contrast, in underbalanced drilling the crew are able to keep the pressure of the mud below the pressure in the reservoir. This procedure uses as a drilling fluid nitrogen or some other non-flammable gas combined with a liquid. This light mixture allows the well to flow during drilling, and so far has proved itself particularly useful in drilling oil wells. The technique can increase production rates, reduce the risk of reservoir damage, increase reservoir penetration, and lower well completion costs.
Coiled Tubing Drilling: This is another important new drilling technology making an impact in Western Canada. Coiled tubing drilling replaces the traditional jointed pipe with steel pipe that is flexible enough to be wound around a ten- to 15-foot drum or wheel. Pipe from the continuous roll is drawn into the hole as the drillbit deepens, providing the casing needed to enclose the well.
Although only practical for shallow wells, coiled tubing drilling increases drilling speed, reduces damage to petroleum-bearing rock formations and is compatible with underbalanced drilling.
Drilling with Casing: The last important new drilling technology on the horizon, experiments using the well’s casing as its drilling string began in 2000. If successful, the technology would replace the drilling string with the well’s casing, reduce downhole drilling problems and lower drilling costs by as much as thirty percent.
Service contractors with expertise in these drilling technologies (either as drillers or suppliers) have competitive advantages over contractors without. The reason is that these technologies offer one or more of the following important benefits to the oil and gas producer: they save time, they save money, they increase production or they increase reserves. When you are analysing service companies, therefore, you should consider expertise in these areas is one seal of approval.
Of course, you should also be looking at their financial health.
It seemed to all be settled. The Intergovernmental Panel on Climate Change (IPCC) released "The Science of Climate Change 1995” in June 1996. As the media reported this event, it offered solid evidence on a series of critical environmental issues. At first it seemed to be unarguable evidence about the impact of Greenhouse Gases (GHGs) on the environment.
The major GHGs are carbon dioxide and methane and other gases. Scientists have been debating for decades whether these gases will trap the sun’s heat in the atmosphere, causing climate change. The IPCC report said that climate change is a real concern, and Earth is getting warmer. But the issue didn’t stay settled for long.
The IPCC imprimatur was expected to carry a great deal of respect, so this report was widely anticipated. People expected it to be the best source of scientific information about the impact of human beings on climate. Environmental activists, corporate environmentalists and government wonks had all waited impatiently for copies to roll from the presses.
A week after the books arrived, however, a respected scientist sent an important letter to The Wall Street Journal. That letter had a huge influence on future events.
“This was (IPCC’s) first new report in five years,” Frederick Seitz wrote in a warm-up to his main message. “The report will surely be hailed as the latest and most authoritative statement on global warming. Policy makers and the press around the world will likely view the report as the basis for critical decisions on energy policy that would have an enormous impact on US oil and gas prices and on the international economy.”
Seitz was finished warming up; now he turned and attacked. “This report is not what it appears to be – it is not the version that was approved by the contributing scientists listed on the title page. In my more than 60 years as a member of the American scientific community, including service as president of both the National Academy of Sciences and the American Physical Society, I have never witnessed a more disturbing corruption of the peer-review process than the events that led to this IPCC report.”
Seitz claimed that much of the science was bogus, and that the report had been extensively tampered with to satisfy a particular political agenda. Elsewhere he added, “There is good evidence that increased atmospheric carbon dioxide is environmentally helpful."
Now the cat was in among the pigeons. Apart from having the credentials listed in his letter, Seitz is president emeritus of Rockefeller University. He is also chairman of the George C. Marshall Institute, which conducts technical assessments of scientific issues that could have an impact on public policy. Thus, he carries a lot of weight within the scientific community.
His letter raised a hail of concern from scientists around America and elsewhere in the world. When the IPCC was used as a major exhibit at the Kyoto Summit in Japan in December 1997, his protest became a cause célèbre.
Within five months of the announcement of the Kyoto Protocol at that summit, more than 17,000 American scientists had signed a petition urging the US government to reject the Kyoto Accord. The petition urged the US government to reject the accord, which would force drastic cuts in energy use on the United States.
Not a great deal of encouragement was needed. The Senate had already passed a resolution a resolution denouncing the plan by a margin of 95-0. The Senate said it would turn down any agreement that would damage the economy of the United States while exempting most of the world's nations – including such major emerging economic powers as China, India and Brazil.
In his first few months in office, George W. Bush followed the advice of the scientists, politicians and many others by terminating any thought of American participation in the treaty. In his view, the Kyoto Protocol was unfair to the United States and to other industrialized nations because it let 80 per cent of the world off the GHG emissions hook.
India, China and the US produce more than 40 percent of the greenhouse gas in the world and they're not involved in the treaty. Yet Canada soldiers on – along with the rest of the industrialized world. This raises real concerns for Canada’s oil and gas industry.
The reason is that the two largest sources of carbon dioxide in Canada are, respectively, automobiles and the petroleum industry. If Canadian companies have to use much greater pollution controls to produce oil and gas than their American peers, they will be at a relative disadvantage. For this reason, Premier Ralph Klein of Alberta and many people in the petroleum industry have stood up against participating in a deal rejected by the US, and that exempts such other major oil and gas producing countries as Mexico, Kuwait, Saudi Arabia and Venezuela.
In its Orinoco heavy oil and tar belt, Venezuela has one of the few hydrocarbon resources that could conceivably compete with Canada’s four oil sands deposit. Located in the north, Alberta’s Athabasca deposit is the largest known oil resource in the world. However, to produce heavy oil and tar sands you need a lot of heat, which you generally manufacture in oil or gas-powered boilers.
If Canada ratifies the Kyoto agreement, the companies that have already invested $30 billion in Alberta's oil sands will have to pay more for pollution controls. This would limit growth in Canadian oil sands, goes the argument, and thus give Venezuelan competitors the opportunity to produce more heavy oil using operating practices that do not meet minimum North American standards. It makes you wonder whether the environment would really benefit from such an outcome.
"Those investments would be at risk – it's going to be," said Lorne Taylor, Alberta’s environment minister. Taylor questioned Canada's involvement in the deal, saying it would deal a serious blow to Alberta's economy unless it were revised. "If it goes through the way it is presently written it will put Alberta and Canadian industry at a significant disadvantage."
Taylor’s comments were part of a litany of public comments from government expressing the view that the Kyoto Accord was not acceptable to Alberta, which would be disproportionately affected by the treaty.
At the end of 2001, Alberta premier Ralph Klein made public his view that the Accord was unacceptable. His forum was an audience of energy executives in Dallas. On this occasion, he shared the stage with Prime Minister Jean Chrétien and the other three premiers of the western provinces.
Klein said US energy executives are worried Canada's support for the world plan to reduce greenhouse-gas emissions will stifle the energy industry in North America.
"They think it is inherently unfair for Canada to enter into the Kyoto Protocol," Mr. Klein said as the Prime Minister looked on. "Ratifying the Kyoto protocol would have significant financial impact on the province of Alberta."
Chrétien replied, "We have to talk with the provinces before we ratify it, but our goal is to ratify it.”
WHO KNEW WHAT AND WHEN?
There was news item on Friday about the suicide of a former Enron executive who resigned in May 2001 over concerns about Enron's accounting deceptions. This got me thinking about how long this problem existed before it became news late last year. This individual resigned in May. Presumably he was aware of the problem for some time. A year or more? We can also presume that, because of the depth and breadth of the problem, a lot more people in and out of the company knew about it as well. I would bet that the numbers would be in the hundreds and maybe into the thousands of people who had heard at least a whisper of problems at Enron.
We often say that the price always reflects all that is known about a stock. Specifically, you and I do not usually (ever?) know everything there is to be known, but the price reflects all knowledge that is public and private.
If you look at a chart of Enron, you will see that it topped out in the summer of 2000, which is where I would guess concern began to grow internally, and information began to leak to outsiders. The price moved sideways to slightly down into March 2001, which is where the trading range finally broke down. There is no question in my mind that massive amounts of ENRON STOCK were distributed during this time.
The average technician with a longer-term approach may have sat out the trading range, but the price breakdown should have awakened even the sleepiest among us. Acting at that time would have permitted an exit at a point where the price was about 33% off its all-time highs -- not brain surgery, but certainly a far cry from a total loss. And this was six months ahead of when the scandal finally broke into the news.
My point is that you and I can legally trade on insider information, and we don't even have to know what it is. All we have to do is watch the stock price and act accordingly. All the secrets that anybody knows will show up in price movement as people begin to act on that knowledge. Most of us were surprised when the Enron news finally broke, but the stock's price deterioration gave us plenty of advance warning.
--Carl Swenlin, DecisionPoint, January 26, 20023
Max Cohen focused strongly on his key assumptions. “Number One, math is the language of nature,” he said. “Two, everything around me can be represented and understood through numbers. Three, if you graph the numbers of any system, patterns emerge. Therefore, there are patterns everywhere.”
“So what about the stock market?” he asked, and described the markets as a “universe of numbers that represents the global economy, millions of hands at work, billions of minds, a vast network screaming with life, an organism, a natural organism.”
Cohen is the lead character in a stylish art film called “p” (“Pi,” in the Roman alphabet). Severe migraines and severe mathematical genius haunt the young mathematician, Max, whom Sean Gullette plays very cleverly. Max has an obsessive hypothesis: “Within the stock market there is a pattern, right in front of me, hiding behind the numbers, playing with the numbers, always has been.”
Unknown to him at the beginning of the film, Max is actually searching for a 216-digit number. It turns out that some bad people also want that number, so they can cause the stock market to crash. This helps create adventure.
Max then learns why his mainframe computer, which he has assembled in his tiny New York apartment to try to solve his hypothesis, printed out a 216-digit number before it crashed. His mentor, retired mathematician Sol Robeson, explains that after going through certain feedback loops a computer can become conscious. “Just before they crash they become aware of their own structure, the computer has a sense of its own silicon nature, and it prints out its own contents.” Those contents turn out to be – you guessed it! A 216-digit number.
Finally, we learn about a rite that took place in Ancient Israel once a year – or so said Rabbi Cohen, the leader of a Kabalarian sect. Like other Kabalarians, Rabbi Cohen’s group believed the Torah of the Old Testament is a code based on numbers, with each letter of the Hebrew alphabet representing one number.
In ancient times, said Rabbi Cohen, the chief priest of the Jews would enter the Holy of Holies to perform a simple ritual, and he would do it on the holiest day of the year, Yom Kippur. The priest’s mission was to “intone a single word, the True Name of God, which was 216 letters long, and the key to the Messianic Age.” Unfortunately, that name was lost in Roman times. Would Max mind accommodating the good rabbi by sharing the number with him? Hmm?
Said Max, “The number is nothing. It is the meaning, the syntax, what’s between the numbers” that counts.
That offers enough financial incentive to figure out how to beat the market. One of the best ways to get a handle on the sector is called technical analysis, and involves the use of charts. Here comes the basic introduction to technical charting.
Simply put, “technical analysis is the study of prices, with charts being the primary tool,” says analyst Steven Achelis, who gives a fine introduction to the discipline.
“The roots of modern-day technical analysis stem from the Dow Theory, developed around 1900 by Charles Dow,” he says. “Stemming either directly or indirectly from the Dow Theory, these roots include such principles as the trending nature of prices, prices discounting all known information, confirmation and divergence, volume mirroring changes in price, and support/resistance. And of course, the widely followed Dow Jones Industrial Average is a direct offspring of the Dow Theory.”
In a lively publication, Technical Analysis from A to Z, Achelis vividly explains these concepts. For example, “Charles Dow's contribution to modern-day technical analysis cannot be understated. His focus on the basics of security price movement gave rise to a completely new method of analyzing the markets.”
Countless other publications also describe stock market charting, and this book will both use and explain many of those tools in coming pages. The place to begin is with two simple but powerful techniques. One of these is called candlestick charting. Another is the Moving Average Convergence / Divergence, or MACD.
Candlesticks are a subtle form of charts developed centuries ago in Japan. This book will use candlesticks frequently, because they can be so helpful in explaining the psychology of the market.
The following is an example of a candlestick chart. It also gives a reading for MACD.
Figure 2: TSE Oil and Gas Producers Index
The areas in the chart showing peaks and valleys offer a lot of information about the chart. We’ll come back to this in the discussion of basic charting, later on.
The individual units of this chart are called “candles.” A candle has a “body” which captures any major change in price during the day. A white body represents a rise in activity, while a coloured one represents a decline. The thin solid lines extending from the bodies are known as "shadows," and represent activity outside the opening and closing prices.
For example, a section of the candlestick chart for the producer’s index looks like the following.
Figure 3:
The candles with white bodies along the left of the chart show bullish sentiment. You can draw that conclusion from considering that a white body on a candlestick means buyers were willing to pay more for the item as the day wore on.
Similarly, the right half of the chart segment includes a group of coloured candles, signaling bearish sentiment. Dead centre is a pattern known to candlestick technicians as an Island Reversal. It is circled in the segment above.
An Island Reversal takes place at a critical juncture in the chart – either the top or bottom of a wave. It consists of a cluster of two to four candlesticks separated by small gaps from the rest of the chart. As you can see in the chart of the TSE’s Oil and Gas producers Index above, when this pattern formed in September 2000, it accurately called a major index decline.
An Island Reversal in a high market means investors are about to beat a hasty retreat. If it occurs when the index is at a low, it usually means the chart has hit bottom, and a relatively quick recovery is in the works.
Let’s take another look at the Oil and Gas Producers Index, focusing at first on MACD, a powerful market indicator that works with any system of charting. You will find it at the bottom of the chart, below, which is another take on the chart we looked at earlier.
Figure 4: TSE Oil and Gas Producers Index
The developer of MACD was Gerald Appel, an American analyst. The most powerful of popular indicators, MACD involves comparing two moving averages. Those averages either converge (trend together) or diverge (trend apart). The result can be uncannily accurate in predicting the direction of the market.
Just as you don’t need to know how to build a car to drive one, you don’t need to know how to calculate MACD to use it. The MACD indicator (also known as an “oscillator”) compares two moving averages. This is not something you want to do by hand.
One of the MACD trend lines moves more slowly than the other. This slow-moving average is calculated as the difference between a 26-day and a 12-day exponential moving average. The other trend line is a nine-day moving average. Also called the "signal" or "trigger" line, the second of these trend lines oscillates through the slower moving average, giving “buy” and “sell” signals.
The basic MACD trading rule is to sell when the signal line falls below the slower moving average. Similarly, buy when the trigger line rises above the slower moving average. It is also popular to buy or sell when the trigger line goes above or below zero. If you look at the chart, you will see that the “sell” signal that MACD gave in September 2000 exactly coincided with the Island Reversal described earlier.
The peaks and valleys on the chart can provide important information to the reader. In the example above, the fact that the second peak is lower than the first is a bearish signal. It could mean that the index is about to begin a longer-term decline.
Illustration 4 also shows some basic charting. In the chart, the arrow represents a strong intermediate uptrend, also known as “ascending support”. The horizontal line suggests an area of strong support. If the index goes below it, there are reasons for concern.
The dashed line indicates long-term resistance. The industry will have to do mighty deeds to beat the surge of 2001. And the descending line indicates descending resistance, which is bearish. Opposing forces are beginning to impinge on each other’s territory. Something will have to give. The chartist can see that, and her analysis of the probabilities can help her make good investment decisions.
The question then becomes, “Which charts should we analyse?” The short answer is that you should analyse everything, from commodity prices to the patterns of individual stocks. Technical tools will help you understand them all. However, this book will balance its analysis between one Canadian and two American stock market indexes.
To keep a finger on the pulse of the vibrant Canadian petroleum industry, we will use the TSE Oil and Gas Index. In international terms, this index uses mostly modest-sized companies involved with energy – explorers and producers, drillers, pipelines, refiners and your local natural gas utility.
By contrast, this book will also use two American Stock Exchange (Amex) indexes to understand the markets. Because they follow big corporations, these indexes describe the collective behaviour of much bigger worlds than those represented by the TSE’s Oil and Gas Index.
Amex’s oil index (XOI) represents a group of large companies that produce, transport or refine and market oil, including the multinational super-major, Exxon Mobil Corporation. Its natural gas index (XNG) includes gas producers, pipelines, distribution companies and energy marketers. These two indexes give a global idea of how the oil and gas sectors are doing.
As investors turn their interest to oil and gas, the market steadily shifts from the bigger to smaller companies. As the bull moves on, investors will pile into progressively smaller capitalization companies. Small Canadian producers can thus become a safe haven in a bull market, until the final frenzy arrives. When the market goes into its final frenzy, tiny one-prospect companies double and triple in share price before going into decline. The frenzy comes as the cycle peaks.
American Ralph Elliott was the originator of this system. A semi-retired accountant, Elliott developed his wave theory while obsessively studying stock market patterns during the early years of the Great Depression.
According to Elliott Wave theory, market cycles form rhythmic patterns that can be studied in graphic form. Each full cycle has a bull phase and a bear phase. The bull phase comprises three waves, each higher than the one before. After the up waves come two down waves; together, these five waves form the investment cycle.
Figure 5: Amex Oil Index
In accordance with Elliott Wave convention, the charts below show the three bull waves in the 1995/1999-investment cycle with Roman numerals, showing first their peaks (odd numbers), then their valleys. Also by convention, the two bear waves are lettered. The valleys are noted first, then the peaks. On the right, the numbers suggest that the first wave of the present cycle is complete. The second wave, which the chart shows to the end of year 2000, is still surging.
The following chart shows an Elliott Wave analysis of the Amex gas index for the same period. By comparing the two charts, you will notice that their waves cover roughly the same periods, and involve waves of similar duration. However, the natural gas industry was much more volatile at the end of the chart, as a record cold winter drove natural gas prices to previously unimaginable heights.
Figure 6: Amex Natural gas Index
If you believe that cycles tend to repeat themselves, you might be tempted to look for ways to estimate how high the next peak will be, so you can sell on the way up.
Who can forget seeing that face, reading that translation of the words: “We calculated in advance the number of casualties from the enemy, who would be killed based on the position of the tower”, said Osama Bin Laden, as he celebrated the event with a group of supporters in the city of Kandrahar, Afghanistan. “We calculated that the floors that would be hit would be three or four floors.”
“I was the most optimistic of them all,” he continued, “due to my experience in this field, I was thinking that the fire from the gas in the plane would melt the iron structure of the building and collapse the area where the plane hit and all the floors above it only. This is all that we had hoped for.”
Acknowledgements:
Tony North, Standard and Poors Index Operations, Manager of New Product Developments.
Exchange Traded Fund S&P GSE 60 index.
SP/TSE Energy sector index
NY Times, January 18, 2002
By RICHARD BUTLER
n "The Great Game," published just as the Cold War ended, Peter Hopkirk chronicled the struggle, throughout the 19th century and into the 20th, between Britain and Russia for influence, control and profit in Central Asia. The jewel in the crown was the Indian subcontinent; but the pathway to it ran through Afghanistan. Now the prize is oil - getting it and transporting it - and Afghanistan is again contested territory. The difference is that, this time around, it is the United States that will be playing the game with Russia.When the Soviet Union collapsed, it lost its southern provinces - Kazakhstan, Tajikistan, Uzbekistan, Turkmenistan, Kyrgyzstan, Azerbaijan. These states have oil and gas deposits that, taken together, are thought to be equal to the remaining reserves of Saudi Arabia and Iraq, America's two leading Middle Eastern suppliers of oil.
The main feature of post-Soviet transition was the immediate establishment of oligarchies and criminality. When Vladimir Putin assumed the presidency two years ago, he moved quickly to break up the oligarchies and political fiefdoms within Russia.
Crucially, he also addressed the other deep loss felt by ordinary Russians - that of their seat at the top table as an equal with the United States. Mr. Putin courted the Germans and the French. He signed a friendship pact with China. But just as important, if less spectacular, was his decision to market Russian oil outside the dictates of the Arab-dominated Organization of Petroleum Exporting Countries.
Sept. 11 was a godsend to Mr. Putin. By deciding to join the United States in the war on terror, he could achieve at least two major objectives: Russia returned to the top table with the United States; and American criticism of Russian actions in Chechnya evaporated.
But again, in some ways oil politics may prove to be the most important field for Russia's evolving relationship with the West. Russia's independent oil-pricing policies have succeeded in stabilizing the Russian economy over the past two years. Oil prices generally have been high, and Russian growth in 2000 hit about 8 percent. For 2001 it may come down to less than 5 percent. But these are still the first two years of real growth in decades, and much of it is owed to oil production and export.
At the same time, Russia under Mr. Putin has at last learned to negotiate credibly and responsibly with American oil companies - and to work with its former southern provinces in a way that is respectful and productive. One result of this evolution is the 980-mile pipeline from Kazakhstan's Caspian Sea oil fields across Kazakh and Russian territory to the Black Sea port of Novorossiysk, which opened late last year. It was pushed hard politically by Prime Minister Yevgeny Primakov, and construction began in 1999. But Mr. Putin has kept the project going against significant resistance by local politicians.
The pipeline is the largest single American investment in the region. The pipeline's partners include Russia, Kazakhstan and several oil companies; its main client is Tengizchevroil, half of which is owned by Chevron and a quarter by Exxon-Mobil, with Russian and Kazakh partners. Kazakhstan's economy is itself expected to have grown last year by nearly 13 percent, mainly because of the oil industry.
In short, Mr. Putin seems to have found a way to make oil and politics mix rather well. Oil prices are expected to continue downward for a while, but the long-term picture remains clear: the Central Asian oilfields will be exploited, and Russia will have a large share in the profits. American oil companies will be heavily involved. The question now is whether the United States can turn this to American advantage.
The war in Afghanistan is most relevant in two respects. First, it has made the construction of a pipeline across Afghanistan and Pakistan politically possible for the first time since Unocal and the Argentinian company Bridas competed for the Afghan rights in the mid-1990's.
Second, the war has led many Americans to feel that Saudi Arabia is not the best of allies. The Saudi regime - undemocratic, an exporter of fundamentalism that is also hated by some of its own fundmentalists, like Osama bin Laden - is important to the West because of its oil. Accordingly, to lessen Western dependence on Saudi (not to mention Iraqi) oil can only be to the good. The route to greater independence may well lead through Afghanistan.
This is not necessarily the Great Game, Part 2. The incentives for American cooperation with Russia, Kazakhstan, Turkmenistan and the other regional powers far outweigh the incentives for confrontation. A great deal of 20th century Mideast conflict can be explained by American-Soviet rivalry - another great game that brought much misery. There is no need to repeat that in Central Asia and every reason not to. To move away from gamesmanship and toward cooperation, Russia might begin by reconsidering its close relations with its regional customers, Saddam Hussein and the Iranian military. And the United States should use great discretion in establishing its bases in Central Asian nations like Kyrgyzstan. Better to build more joint pipelines and fewer military bases.
Richard Butler is diplomat in residence at the Council on Foreign Relations and has recently published "Fatal Choice: Nuclear Weapons and the Illusion of Missile Defense."
. Before we continue with that story, it might be useful to have a geography lesson. Geography and history explain much about the Canadian oil industry, including the reasons why Canadian gas was worth so much less than American natural gas until about 2000.
The top half of the map of the North American continent depicts mostly isolated country. With few exceptions, its bigger islands of population occur along the border between Canada and the Lower 48 states.
In that vast, resource-rich expanse, many people are hewers of wood, drawers of water. Major exports include fish from the sea, grains and other edibles from the farm, lumber and paper, metals and minerals, gold and diamonds. Oil and gas are the most valuable of these products. In 2001, Canadian sales to the US represented exports of nearly $24 billion (Canadian) – x percent of total resource exports, and y percent of the export total. In that same year, Alaska’s oil production (mostly shipped to the Lower 48) were worth $x billon (US).
Now shift your eye south of the Canadian border, and you will see where most of those exports go. Parts of the Lower 48 had rich endowments of oil resources fifty years ago, but those fields in 2001 were mostly depleted or in decline. Alberta produced more oil than once-mighty oil producer Texas, much of it from the oil sands.
The huge American market is a tremendous competitive advantage for Canada, whose energy reservoirs drain directly into the world’s biggest energy market. The United States has always offered opportunity for Canadian producers, and consumes more than half of Canada’s oil and gas production. Without those markets, Canada would be inconceivably poorer. So would the state of Alaska. Alaskan oil, which is dominated by a small number of large players, goes by pipeline through Alaska and by tanker mostly to the US West Coast.
North America’s oil industry needs to go farther north, farther offshore and deeper into Alberta’s vast oil sands for oil supplies that will be secure from disruption in the Middle East. The gas sector also needs to develop large northern and offshore resources.
A previous chapter discussed the implications of a supply peak for world oil production. Another suggested that until the last weld on a northern gas pipeline (perhaps in 2007), rapidly growing and seasonal demand could lead to more shortfalls in natural gas supply. That would mean spiking prices, like those that took place in the winter of 2000.
Canadians often seem to be embarrassed by the large role that resources play in the national economy. One wonders why. It is not true that resource economies require employees with lower skills, as many people believe. The towns created by felling trees, mining, and hydrocarbon production are not necessarily low-skill communities. “The exploitation of natural resources is increasingly a high-skill and capital-intensive process,” according to one report.[122] “To achieve higher productivity, firms in the resource-based sector continually update their capital stock, which embodies new knowledge and advanced technology. Trade in natural resource-based goods and services, therefore, can also support high real incomes.”
This is particularly true for oil and gas, which is a classically capital-intensive industry. To get oil and gas out of ground, you don’t need labour; you need capital. To explore, develop and produce petroleum you need to spend a lot on equipment and facilities, goods and services. And all of the industry’s technologies and processes are rapidly changing.
This is an industry in which, more than most, new technology and the application of new geological and engineering ideas drive costs down. That is why the real prices of oil and gas have mostly declined since the great oil age began.
Cold Cities, Towns and Farms
Look again at that map and you will notice huge stretches of Arctic wasteland – summer swamps, winter ice and spectacular beauty, but miniscule human populations. Well below those uninhabited areas, most of the northern cities, towns and farms experience cold, raw winters. They value home heating. Canadians certainly do.
Canadians have generally viewed natural gas in a restrictive way — probably because it is a premium fuel for space heating in a large, cold country. As early as 1901, Ontario concerns about resource depletion led to consumers in Windsor successfully petitioning the Dominion government to prohibit the export of natural gas to the Detroit area. This happened again a few years later, this time in respect to gas exports from the Niagara area to Buffalo. Canadian gas exports did not resume for nearly 50 years — until Alberta gas was shipped to Montana to meet industrial needs related to the Korean War.
This concern about fuel for home heating was the reason Alberta and the federal government insisted in the 1950s that the industry must have a 35-year supply of gas reserves before regulatory authorities would approve export permits. (The requirement was later reduced to twenty-five.)
Under this arrangement, there was so much natural gas around that it sold for pennies per thousand cubic feet in Western Canada. To make the business economic, pipelines were desperately needed. But reserves development, regulatory concerns (expressed by both Canadian and US agencies), territoriality issues (whether a pipeline to eastern Canada should cross US soil) and haggling among pipeline project consortia meant delay after delay in construction approval.
These obstacles overcome and construction complete, in 1957 Westcoast Transmission and TransCanada PipeLines both began piping gas. Together, they formed the nucleus of Canada’s export pipeline infrastructure: westwards to the lower mainland of BC and the US Pacific Northwest, and eastwards to Manitoba, Ontario and Quebec and to adjacent areas of the United States. That system today includes only three additional major export pipelines from western Canada, but it delivers more than thirty times as much gas.
The requirement of a 25-year inventory of gas was the situation until the mid-1980s, when a political agreement – the Western Accord – paved the way for the deregulation of the natural gas industry. And with deregulation came development. Vast expansions in the pipeline systems made it easier for gas suppliers in western Canada to get their product to US markets, and the overhang of supply began to disappear. By the year 2001, the Canadian industry had a natural gas inventory that would only last nine years without major additions to reserves.
The cycle was preparing to repeat itself, but it would be starting with higher prices than their lows in the later 1990s, when Canadian gas sold for about $1.60 (Canadian) per thousand cubic feet. After climbing steadily downhill from $12.90 at the end of 2000, at year-end 2001 gas was still quite profitable at $2.90.
Until Canada’s Western Accord on energy policy in 1985, Canadian governments greatly restricted Canadian gas producers from selling into US markets. This reflects a national characteristic of Canadians: awareness of the weather. When Canadians began exporting natural gas in the 1950s, it was under the proviso that they guarantee that they would always have a thirty-five year supply of this premium heating fuel in the ground – later dropped to twenty-five years. This policy greatly affected the way the industry developed.
Pipelines from Canada to the United States couldn’t deliver all the natural gas available. This kept gas prices in Canada well below their prices in the US. So in the nineties new gas pipelines went in and the industry focused on development. New gathering lines and sour gas plants enabled more wells to begin producing gas. Export pipelines mopped up most of the surpluses in the Western Canada Basin, and the life of Canada’s existing natural gas reserves dropped below ten from twenty-five. The industry began managing for just-in-time gas production.
Natural gas prices rose for two reasons. One was that large and growing markets were available. Another was that reserve lives (calculated by dividing total reserves by recent annual production) had declined dramatically. Theoretically, Canada had less than a ten-year inventory of natural gas to meet domestic and export commitments. This meant there was less competition for export sales, and therefore higher prices.
Canada’s traditional production region, the Western Canada Basin, is still able to produce more natural gas each year, in large part because development has extended well into Northeastern British Columbia, and in Southern Yukon and Northwest Territories.
Add to this the Scotia Offshore Energy Project, which connected natural gas offshore Nova Scotia to New England markets in 1997. In addition, within the next decade gas will begin flowing from the Canadian Arctic to continental markets.
It will flow down first from Alaska, however. While the super-giant Prudhoe Bay oilfield is in decline, the state has huge reservoirs of natural gas that can be developed at the get-go, and various pipeline projects are under consideration. A pipeline from Alaska may include a link to Canada’s Mackenzie Delta. However the pipeline projects develop, substantial new gas supplies will flow from the North into the market. This will have quite an impact on natural gas prices and therefore the natural gas commodity cycle.
Canadian oil production is also continuing to rise. Conventional oil reserves are in decline, but the industry is more than making up for those losses with non-conventional production. Alberta’s oil sands are the major source of new oil supplies in Western Canada. Vast amounts of production can be developed from this resource, at considerable cost but very low risk.
New oil supply is also coming from fields in the heavy oil belt that straddles the Alberta and Saskatchewan border. And they are coming from development in the Atlantic, off the coast of Newfoundland. Most of that oil is delivered to refineries on the US eastern seaboard.
As this picture of the industry illustrates, North America has become a continental free-trade zone for both oil and gas. In practice, this means that Canada supplies the United States with as much oil and gas as she can deliver, and the United States consumes. Canada’s natural gas industry competes with natural gas basins all over the United States already. Soon, the sector will be competing with Alaska, which has a great deal of gas for the market.
The sketch of the United States as a rapacious consumer is misleading. Because of cold winters and great distances, Canadians consume more energy than Americans, per capita. Indeed, Canada is the per capita energy consumption capital of the world.
Militant Islam
The difficult future of holy struggle
Jan 31st 2002
From The Economist print edition
The jihadi movement continues to attract some of the Arab world's richest and most privileged. The hijackers who flew into the World Trade Centre were western-educated. Fifteen of them, out of 19, came from the Arab world's richest state, Saudi Arabia. Two of Gaza's suicide-bombers have been sons of millionaires. The vast majority of Arabs fighting with the Afghan mujahideen were graduates, and their leaders came from the Sunni aristocracy. Mr bin Laden belonged to the richest non-royal family in Saudi Arabia. Mr Zawahari was born to a landowning family. This is no peasants' revolt.
But if, as many jihadis claim, the Muslim street is boiling, it is hard to detect the agitation. The forecasts of mass demonstrations against America's bombing of Afghanistan never materialised. For almost a generation, the region's authoritarian rulers have defied predictions of their downfall. Syria, a secular republic, has already produced a dynasty. Iraq, Egypt and Libya threaten to do so. The Islamists, so far, have proved incapable of harnessing people's frustration. The Arab world, it seems, is still immune to popular change.
In the industry’s earliest years, producers turned oil and its refined products into cash by shipping wooden barrels by wagon, train and ship to global markets. The barrel was standardized in the 1870s, and remains the basic measure of oil. It contains 42 US gallons, 36 Imperial gallons or 159 litres of liquid. The average barrel of oil weighs about 310 pounds or 140 kilograms. A barrel of oil is priced in US dollars.
Does it make sense to measure and price oil by the barrel? There are metric alternatives that make this question worth investigating. For example, Canada uses another measure of volume, the cubic metre, and has the distinction of being the only country in the world to measure oil with this unit. The Canadian “cube,” as it is known, is equivalent to 6.29 barrels of oil or 35.49 cubic feet of natural gas.
The European metric system also measures natural gas in cubes, but it measures oil in tonnes; one tonne is equal to slightly more than seven barrels of an average grade of oil. As a commercial standard, tonnes make more sense than measures of volume, because smaller pricing differences exist between tonnes of different kinds of oil than between barrels of similar products.
Although an integrated North American natural gas market has developed, Canada and the United States retain different systems for measuring natural gas. In addition, different groups within a single producing company may use entirely different measures for the same gas production. The two systems for measuring natural gas are known as Canadian Metric and US units (a modification of the British Imperial system which is now the official standard only in the United States).
In Canada, a company’s production and accounting groups are likely to refer to natural gas volumes in terms of Canadian Metric, while the planning, exploration and marketing groups of that same company may use US units. Canadian Metric measures natural gas in terms of cubic metres and joules. Cubic metres are a measure of volume, while joules are a measure of the energy content of the gas. In general, Canadian producers and processors measure their production in terms of cubic metres. Canadian pipelines measure the natural gas they transport in the same way. However, Canadian end-users measure the natural gas in terms of joules.
In contrast, exports to the United States are sold in cubic feet (the measure of volume) and British thermal units (BTUs, the measure of energy content). Despite Canada’s conversion to metric in the late 1970s, US units have remained significant to Canada’s natural gas industry because more than half of Canada’s natural gas is sold to US markets. Cubic feet and cubic metres are calculated at a standard temperature (usually room temperature) and pressure (most often sea level atmospheric pressure). However, an oddity of the system is that to convert a cubic metre into cubic feet requires different conversion factors. One cubic metre equals 35.30 US cubic feet but 35.49 cubic feet in Canada. The numbers vary because Canadian and US standards assume slightly different atmospheric pressure.
The most common unit for pricing gas is one thousand cubic feet (Mcf). For Canadian natural gas, the reference point for commercial prices is a central storage and distribution point in southeastern Alberta called the AECO Hub operated by Alberta Energy Company. If priced in US dollars, the point of reference is usually the Henry Hub in Louisiana.
The deregulation of the electrical generation industry is creating what is often called the “convergence” of the natural gas and electrical sectors.
Here is an example of what convergence means: Many industrial plants manufacture their own electrical power from natural gas or oil. Instead of connecting a power line to the plant gate, they connect a small pipeline. The natural gas coming through the pipeline drives a turbine that generates their electrical power. Many corporations also harness waste heat from such industrial processes as smelting steel to generate electricity, which they then sell to the local power grid.
Theoretically, consumers could do this too. Instead of having an electricity line to your home, you could have a gas line that fed a fuel cell to provide electricity and a furnace to keep you warm. This is the magic of convergence, which is taking place because technologies are combining with deregulation to enable consumers to substitute natural gas and electricity for each other.
Just as deregulation created a continental natural gas market, deregulation of the electricity market is creating an integrated North American energy market. Natural gas and electricity are flowing with fewer and fewer obstacles from point of origin to customer, with significant benefits to the consumer.
Because gas is so readily available, it is converging with electricity into a commodity you might call raw energy. For many reasons (some of them environmental), natural gas is becoming the preferred fuel for turbines that manufacture electrical power.
This means that electricity and gas prices have begun to track each other, in part because in some fascinating cases the commodities are becoming interchangeable. Such is the brave new world of energy convergence that energy brokers can swap hydroelectric contracts in British Columbia for natural gas contracts in Florida.
This is having a powerful impact on demand for natural gas, as you can see in the following chart.
Oil is still the dominant source of primary energy, but it is mostly used for transportation. Natural gas, which is mainly used for home heating, holds the number two spot. In the latter 1990s, North America experienced three warm winters in a row, causing natural gas demand to decline. Only its rapidly growing use in the generation of electricity kept demand from falling out of bed. What the investor needs to understand is that electricity generation is going to add substantial demand for natural gas even if warm winters continue to depress gas demand for home heating. Demand for electricity is climbing, but for environmental reasons it makes more sense to use natural gas rather than coal, nuclear fuels or hydro for electricity generation.
Each of these latter energy sources contravenes the high environmental standards that Canada and the United States take pride in. Coal is renowned as a dirty fuel – one responsible for emissions that may contribute to global warming, acid rain and other environmental ills. Nuclear energy gets a bad rap because of the risks associated with radioactivity: remember the 1979 Three Mile Island disaster in the United States and, six years later, Chernobyl in Ukraine. The disposal of concentrated radioactive waste is another serious potential hazard.
Even hydroelectricity causes environmental problems. Damming rivers to create generators can create such ecological problems as making it impossible for salmon to travel upriver to spawn, or eliminating the wetlands that serve as critical ecosystems for thousands of species of wildlife. Some jurisdictions have taken these issues seriously enough that they have ordered hydro dams dynamited.
This is where convergence comes in. Oil is essentially a transportation fuel, and natural gas has no peers for space heating. But the main use of the three other fuels is to generate electricity. Existing electricity-generating facilities are being supplemented with gas-fired turbines at a remarkable rate. Increasing supplies of natural gas are being burned to generate electricity.
As this chart shows, North American demand for electricity rose by more than a quarter during the 1990s, largely because of increasing computer power and other electronic systems.
As the North American economy grows, there is constant growth in demand for both electricity and natural gas. According to Robert Taylor, a senior official with the Alberta Government, “The shifts over time in the relative economics of the various energy sources are often based on advances in technology. Demand has grown because of declining relative cost and availability, but also because of advances in technology itself. For example, about fifteen percent of US electricity consumption appears to be related to computer use, with six of the fifteen percent a result of surfing the net.”
Many people still believe that Opec – whose members include Iran, Iraq, Kuwait, Saudi Arabia, Venezuela, Qatar, Indonesia, Libya, the United Arab Emirates, Algeria and Nigeria – sets world oil prices. This was true for the decade until 1986 (during the last seller’s market for oil) but it is no longer the case.
To act as a cartel, Opec’s members cut their crude oil production with some understanding of how this will influence prices. However, competition on the open market between buyers and sellers (also known as producers and consumers) determines what those prices will be.
Three major international petroleum exchanges “discover” the market price for oil. These are the New York Mercantile Exchange, the International Petroleum Exchange in London and the Singapore International Monetary Exchange.
In the big scale of things, the amount of time during which the world will consume oil is extremely small. This is true whether you are an optimist or a pessimist on the matter.
Here’s one way to look at the big picture. Take Earth since multi-cellular life first appeared in its primordial seas and oceans, making the creation of crude oil possible. This was about 540 million years ago, at the beginning of the Cambrian Period of geologic time. Now think of the ages since as if they were ticking by on the face of a grandfather clock, starting in the earliest moments of the morning.
In the early afternoon, dinosaurs evolved and began to roam, dominating Earth. However, at seven minutes after nine in the evening, a giant meteorite probably struck the planet in today’s Gulf of Mexico. The last true dinosaur died less than a minute later, leaving as its only direct descendent a class of animals known as birds.
The oil industry didn’t emerge until the last five hundredths of a second before midnight. And by midnight, the last of the world’s conventional oil will be gone. That will be the case whether oil production lasts for another hundred years, or two hundred.
For two centuries – since the defeat of Napoleon – the globe has been dominated by English-speaking nations. 
![[Figure 1]](file:///C:/Users/Peter/AppData/Local/Temp/msohtmlclip1/01/clip_image015.jpg)
