Chapter 8. Formula for Success: Rise Early, Work Hard, Strike Oil

The chapter’s title contains a quote from oil tycoon J. Paul Getty. This formula for success is as true today as it was in the early to mid-twentieth century, when Getty made his billions as an oilman. During late 2008 and early 2009, however, oil and energy stocks were relegated to a sideshow in the deflationary aftermath of the financial crisis and ensuing global recession. Mostly attributable to myopic behavior and analysis, mainstream investors saw little opportunity in energy and oil after the substantial crash in oil prices from $145 per barrel in July 2008 to $31 per barrel in December 2008. The consensus response to the 78% decline in the West Texas Intermediate benchmark for oil prices was fear and apathy regarding the sector. Despite the obvious near-term effects of weaker cyclical demand from around the globe, there is little reason to turn away from oil as a long-term investment, because the secular trend is what counts in this equation.

As most hard asset investors realize, investing in commodity stocks has a particular nuance. The investor in any commodity stock takes on two components in his or her purchase: the future price of the commodity, and the skill set of the business manager combined with his or her productive assets. It is relatively easy for an analyst to determine the business manager’s competence and ability, because these traits usually reveal themselves in the financials or other conventional forms of analysis. Turning to the other question, the future price of a given commodity, the picture can quickly become complicated. Rather than trying to explicitly forecast the future prices of commodities such as oil, it is more productive to examine the relevant and discernable factors affecting supply and demand. Then we can determine whether these factors portend a bullish or bearish backdrop for future prices over the coming years. Again, the focus remains on long-term price determinants. For example, it is more pertinent to weigh lasting variables such as the nationalization of energy assets across the globe and their potential effects on supply and production levels. It is not as effective to use a technician’s view on an oil chart, or even a near-term fundamentalist’s view on oil prices over the next 6 to 12 months. This chapter does not forecast exact price levels. Instead, it espouses reaching a 5- to 10-year conclusion about why investors should maintain oil and energy stocks in their holdings over this time period, and may perhaps even thrive by doing so.

With that said, let us discuss oil. Fortunately, any discussion of the price of oil rests on the simplest concept in economics—supply and demand. From a global perspective, oil has been a relatively steady, low-single-digit growth commodity over the past 40-plus years. Since 1965, global oil consumption has grown at a 2.3% compound annual growth rate (CAGR), compared with a 2.2% rate of production. On average, demand has slightly outpaced production by a modest 10 basis points. However, digging deeper into the global figures, we can find evidence that demand may continue to outpace supply over the coming decades. This should lead to higher prices over time and increasing profits for these companies.

Our examination of global demand factors begins with a dividing timeline of two economic periods delineated by the free-market reforms in the Asian economies of the 1980s and ’90s. Our assertion is that we can view global oil demand in two slices of time highlighted by the economic reforms that took hold in the 1980s and ’90s in China, India, and Asian tigers such as Singapore, Thailand, and South Korea. Prior to the 1980s and ’90s, Asian oil demand outside of Japan was driven primarily by China. But during the emergence of market reforms in India and the Asian tigers, oil demand from the Asian Pacific region accelerated sharply. Since the 1980s, many of these economies have maintained oil consumption growth rates compounding in the mid single digits. Table 8.1 shows representative growth rates and their sharp contrast to developed-market and world averages.

Table 8.1. Oil Consumption CAGRs 1980–2007

The impact of Asia’s economic growth on oil consumption is at least somewhat appreciated by long-term investors or those with experience in the emerging markets. Perhaps what is less well known or, at a minimum, is underappreciated is the rapid acceleration in oil consumption among the oil-producing nations themselves. In a sense, the importance of oil as a worldwide commodity and its success in the marketplace have come full circle. Organization of the Petroleum Exporting Countries (OPEC) nations such as Saudi Arabia have continuously raised their standards of living based on this product’s economic proliferation. Not surprisingly, because these societies also have begun to prosper from dominating the world trade in oil, they too must consume increasing amounts of oil to maintain their newly industrialized and advancing societies. Essentially, the loss of oil production in the developed world coincided with increased world demand from Asia. The Middle East assumed this market share from the developed world, which propelled it to higher incomes, wealth, and standards of living beginning in the 1980s. These economic changes spurred a sharp acceleration in the growth rate of oil consumption in these oil-producing nations to fuel their rapidly growing economies, as shown in Table 8.2.

Table 8.2. Middle East Oil Consumption CAGRs

The coalescing of these developing-market demand fundamentals, coupled with a long-term slowing of growth in developed-market consumption from the United States and Europe, culminated in a subtle shift. Production outpaced demand from 1965 to 1980, but then demand outpaced production from 1980 to 2007 (see Table 8.3). As shown in Figure 8.1, the balance of oil between consumption and production did not register a worldwide deficit until the early 1980s. Essentially, this was when the onus of production fell sharply onto the Saudis and other OPEC producers. The same supply deficit phenomenon appeared again in 2007, setting the stage for the sharp rise in oil prices that ended in 2008. During 2007 and 2008, the balance between supply and demand fell into deficit from nothing more than anemic growth in production in the preceding four years.

Table 8.3. Oil Market Shifts from Subtle Surplus to Subtle Deficit

Figure 8.1. Oil market balance: surplus/deficit in tons

Source: BP Statistical Review

From 2004 to 2008, production increased at a paltry 0.4% compounded rate. This small growth in annual production was matched against a compounded growth in consumption of 0.8%, or a rate of consumption that was twice the rate of production over a four-year span. On the surface, these appear to be subtle mismatches in small numbers. But if we look at what happened to the price of oil over this four-year stretch, the result was anything but subtle, as shown in Figure 8.2.

Figure 8.2. West Texas intermediate crude oil price

Source: Bloomberg

These figures demonstrate the driving force that has emerged in the past couple of decades from an assortment of emerging-market nations and their strong demand for oil. Likewise, worldwide production constraints have combined with this growth to create periodic deficits and a sharp rise in prices in response. Nevertheless, we have only described phenomena that have occurred up to this point. Now let’s shift our discussion to the future.

In the Long Term, Healthy Demand Meets Higher Cost Supply

As we focus on this discussion, we can find more reason for optimism in respect to future demand, because many of the nations in question are rising from a surprisingly low base of consumption. Table 8.4 shows that despite the rate of prosperity (gross domestic product [GDP] per head) compounding at 8.8% and 4.9% in China and India, respectively over the past 27 years there remains a substantial divide between the standard of living in these countries and a higher standard-bearer such as the United States.

Table 8.4. GDP Per Capita in U.S. Dollars in 2007

So although myopic observers may argue over the inflection points of business cycles in China and India (including the recent one), the bigger picture from a secular perspective is that substantial room exists for continued growth in these economies. Importantly, oil consumption has increased nearly in lockstep with the rising levels of GDP per head in China and India during these time periods. To bring these relationships between oil consumption and rising levels of prosperity into better focus, we can reference a key driver of oil consumption—automobile ownership. If we look at the number of cars owned per 1,000 people in both China and India (see Table 8.5), we can again see the tremendous potential for economic development and, hence, oil consumption that may lie ahead.

Table 8.5. Automobiles Per 1,000 People

With only about eight cars per 1,000 people in China, this country is about where the United States was in 1910. Although we cannot count on the world to remain static regarding its methods of energy consumption, it is clear that the United States in 1910 was on pace to steadily increase its oil consumption over the remainder of the century as its economy matured and reached heightened levels of prosperity. Likewise, in a developed market such as the United States, approximately 70% of oil consumption comes from transportation.

The sum of these demand factors is clear on a forward-looking basis. The primary engines for oil consumption from the emerging markets still have decades of strong demand for oil on tap. The underlying factors for future oil demand are a critical component to consider. The emerging demand from developing markets over the past few decades has become the centerpiece of the demand story. However, any discussion of future oil prices must include the remaining side of the equation—future supply.

Many people have taken for granted the safe, accessible, and cheap supply of oil in the world market. Except for temporary supply shocks created by the occasional embargo or natural disaster, cheap oil became a way of life in the twentieth century. However, for those paying attention, the sharp run-up in oil prices during the first decade of the twenty-first century revealed in no uncertain terms an inability for supply to meet surging demand. Part of the problem is a multidecade decline in production from developed markets, such as the United States and Western Europe.

From 1965 to 2007, oil production from the United States and Western Europe fell by more than 50%, as shown in Figure 8.3. The numbers cannot speak any more clearly: the supply of oil has been steadily declining for nearly 50 years in the developed markets.

Figure 8.3. Global oil production by source in 1965 and 2007

Source: BP Statistical Review

From a long-term perspective, it is not hard to see that various secular trends are at play in the global oil market. More specifically, the oil market and the upward trend in prices over the past seven years has reflected the growing influence of new sources of demand from the developing world pitted against declining supply in the developed world. These factors have not only ongoing implications for the future long-term direction of oil prices, but also for what will come to define the profile of a potentially successful investment in the oil and energy space.

The story of supply and declining production in the developed markets is straightforward. For all intents and purposes, industry players have spent the past 144 years exploring for, discovering, and exploiting oil reserves. The basic translation is that current reserves are more geologically complex, found in smaller accumulations, deeper water, or even arctic regions. What this means in a modern context is that benefits accrue to exploration and production (E&P) companies that can obtain a competitive advantage in their application of technology and/or efficient production. Taking this thought process one step further, we can see that in the absence of innovation, reinvestment, and the efficiency gains that follow, the price of oil could rise from a mere stagnation in productivity gains. During the past several years, growing evidence has shown that firms across the industry have found it difficult to drive costs lower. Taken on a comprehensive basis, including both finding and development costs, total costs per barrel of production have risen at an annualized rate of 17.5% since 1998, as shown in Figure 8.4. The bottom line is that the price of oil in the market will follow the production costs over time. If production costs continue to rise over the long term, the floor for oil prices will rise as well. The latter years shown in Figure 8.4 probably reflect some cost inflation from heightened activity at the top of the recent cycle. However, the long-term trend is still upward over time because of the relative difficulty surrounding finding and developing new sources of oil.

Figure 8.4. Finding and development costs per barrel

Source: Company reports, Credit Suisse First Boston (CSFB)

This geographic risk and its effects on the cost of production is an important trend to realize because it accompanies another widespread secular trend of geopolitical risk in the energy industry. We use the term geopolitical risk because an overwhelming majority of oil-producing nations have nationalized their energy assets. This trend for countries to nationalize their energy assets has largely coincided with the increasingly lower amounts of production flowing from the privately owned profit-driven developed-market producers. Put another way, just as the world has been finding it more difficult to locate and produce additional oil, the large majority of existing reserves are now held by entities that, in a head-to-head comparison with Western operators, forfeit innovation and reinvestment in favor of exploiting current reserves (the bird in the hand).

This trend of nationalization and declining production from Western players has culminated in a market paradigm in which national oil companies now control 77% of the world’s proven oil reserves. Not surprisingly, the Western “big oil” companies most often vilified by the press during periods of excess profits control less than approximately 10% of reserves. In effect, Western big oil is increasingly taking a backseat on the world stage from a reserve standpoint. But to counter this paradigm, Western big oil companies also tend to corner the market on human capital, because the competition for new resources has intensified to the point of causing them to seek an intellectual edge whenever possible. The fact that national oil companies control 77% of the world’s proven reserves does not necessarily mean that these resources are left in incapable hands. However, it is fundamentally certain that the national oil companies are beholden to fulfilling social promises in their respective home-lands in lieu of pursuing more profits. The by-products of this social policy lead to excessive employment and selling product at subsidized prices to the consumer. The end result is a business that addresses political objectives first, and invests less in its future reserves, and favors current exploitation. To be sure, gifted engineers and technically minded innovators are working in these nationalized outfits. But their expertise is smothered by serving political objectives first and running a good business second. Based on a revealing study¹ conducted by the Baker Institute at Rice University, we can see the empirical effects of the national oil companies’ market paradigm versus the Western companies that are privately held and driven by consideration of shareholder profits (see Tables 8.6 and 8.7). Table 8.6 shows that, by and large, the national oil companies are remarkably inefficient when examined on a revenue-per-head and revenue-per-reserve basis.

Table 8.6. National Oil Companies’ Revenues Per Employee and Reserves

Table 8.7. Private Oil Companies’ Revenues Per Employee and Reserves

In sum, it is easy to discern that the privately owned companies generate considerably higher revenues per employee and revenues per reserve. In fact, revenues per employee are, on average, 76% higher, and revenues per reserve are 123% higher, among the private companies versus the national oil companies. These observations lend empirical support to our earlier assertions that the national oil companies’ adherence to social policies lead to wasteful head counts and inefficient production. Moreover, the national oil companies often face a squeeze on the amount of top line they can generate, because subsidies tend to dominate the pricing landscape for nationalized oil markets. This is yet another by-product of managing a business in which the government prioritizes social benefits ahead of profitability.

As shown in Figure 8.5, the large majority of countries with gasoline prices below the U.S. level possess high levels of government ownership and low levels of operating efficiency. Taking all this into consideration, a clearer picture begins to emerge. Seventy-seven percent of the world’s proven reserves lie in the hands of operators who cannot obtain market prices, who are coerced into carrying too many employees, and who cannot produce nearly the amount of revenue their reserves would suggest. In other words, the overwhelming majority of the world’s oil and gas reserves are being mismanaged. When an operator in the commodity business is said to be “mismanaged,” this usually has one clear interpretation: It is a high-cost operator. In free markets, these operators normally face a swift, judicious exit from the marketplace if they cannot right their ship. In this case, however, with so much of production lying in the hands of these operators and dwindling supplies available to the world’s most efficient operators, a perverse reality is emerging. The low-cost producers are fighting for survival, and the high-cost producers are crowding out the market. Irrespective of this strange distortion in the marketplace, the simple fact remains that unless the world’s dominant suppliers shift their models away from generating positive social externalities in favor of sheer profitability, the price of oil is set to rise. And this sliding scale of inefficiency embedded in the cost structures of the world’s dominant producers will continue. In sum, as long as this market paradigm holds, the price of oil will not decline due to the search for productivity gains through better technology and innovation (the search for lower breakevens).

Figure 8.5. Average gasoline price survey

Source: Baker Institute, Rice University

Market Distortions from the Fed’s Loose Credit and Easy Money

In addition to the geopolitical backdrop for oil production, many producers at large have effectively clipped their own wings through a mix of easy access to capital, response to higher energy prices, and too much competition over limited resources. Put another way, the latest up cycle may have produced some casualties as a large number of firms leveraged their balance sheets in the chase for future reserves. Measured on a barrel of oil equivalent (BOE) basis, firms across the industry increased their debt slightly more than 100% from the beginning of the bull market in oil in 2001 through 2008, as shown in Figure 8.6.

Figure 8.6. Debt per BOE (dollars per BOE)

Source: Company reports, CSFB

Also, the most dramatic increases in debt occurred in the past three years, just as the amount paid for acquiring new assets also surged. Although each transaction could vary by firm, this suggests that many firms were borrowing money to fund purchases at exorbitant prices. This behavior is no different from buying stocks on margin just prior to a stock market crash or taking out loans to speculate in home prices before the real estate meltdown.

This behavior during the run-up and subsequent collapse in energy prices beginning in late 2008 suggests that many marginal producers, using debt to chase the rising acquisition costs in 2008, have been hanging on at best following the financial crisis. On the other hand, early or longtime players that behaved prudently and maintained healthy balance sheets may in time become the consolidators of distressed assets. The key take-away from this discussion, though, is the simple observation that with many players too leveraged, combined with volatile credit markets, it could take some time before production sees another surge in investment. No different from the situation with the national oil companies, with worldwide players possessing less capital to be deployed into future projects, supply faces yet another headwind from lack of investment. With these additional fundamental impediments to supply in place among many Western operators, this suggests that once demand recovers in the developing nations, and more normalized activity resumes in the developed-world economies, prices will again be set to rise for years to come.

As we put everything together in the supply and demand equation, the simple truth is that the key determinants for both demand and supply have shifted away from the old twentieth century model of the United States and friends buying oil from the Middle East. Even so, this new picture of supply and demand does not extricate the United States and the Western establishment from an active role in the oil equation. Instead, the United States and its economic allies will still remain a driving force behind the future price of oil, but perhaps more so from a financial standpoint than from any other perspective. More specifically, aggressive U.S. monetary policy following the financial crisis and any resultant monetary inflation could also come into focus in its relationship to oil prices during the coming years.

Since the United States dissolved the Bretton Woods system of exchange convertibility in 1971 and formally removed itself from the gold standard by doing so, the influence of monetary policy and the effects of inflation have become familiar to most Americans. To be fair, this policy change has had further-reaching implications because it also encompasses countries that possess a managed float or some form of structured convertibility with the U.S. dollar. Despite the overarching importance of oil in the world economy and, in particular, the U.S. economy, the price of oil in and of itself made a particularly lackluster investment in the period stretching from 1928 to 1971 (see Table 8.8). In fact, an investor who had decided to purchase a barrel of oil in 1928 and keep it in the garage for those 43 years would have been disappointed to generate an annualized return of only 1.5%. He probably would have dumped the oil in his yard and used the barrel for something more useful after seeing that his stocks from the Standard & Poor’s (S&P) 500 returned an annualized 8.1% in comparison. Even government bills and bonds had better performance than the price of a barrel of crude oil.

Table 8.8. Annualized Returns 1928–1971

The dissolution of Bretton Woods changed these relationships from 1971 through the present, though (see Table 8.9). Generally speaking, all commodities received a nominal lift in their returns thanks to their ability to create a store of value when placed in the context of a loosely printed fiat currency. The role of a fiat currency doubling as the world reserve, combined with the shifting dynamics in supply and demand discussed earlier, likely changed the role of oil in the financial marketplace, as its return profile began to reflect these factors.

Table 8.9. Annualized Returns 1971–2007

In a dramatic shift from the preceding 43 years, the 26 years following 1971 marked a substantial change in the price return from a barrel of oil (see Table 8.10). Far from being a laggard, oil’s compounded price return of 10.1% was nearly on par with the S&P 500 and outpaced assets that generally suffer in inflationary environments, such as T-bills and T-bonds. For better clarity on the role that inflation may have played in the acceleration of oil prices, we can see that in the period from 1971 to 2007, the Consumer Price Index (CPI) run rate increased nearly 3 percentage points annually. Furthermore, in some ways, the CPI is a massaged data point that can portray a watered-down reality for U.S. consumers and the impact of inflation on their day-to-day purchasing power.

Table 8.10. Annualized Inflation Measured by CPI

Given the ubiquitous nature of oil in the world’s economy, oil is well positioned as a store of value during a period of monetary expansion and any resulting inflation. For that matter, oil has, at least in the past, demonstrated its ability to outpace equity returns during periods of stagflation, such as the 1970s. It has been well documented since the 1970s that the decade was a truly difficult stretch of time for equity investors. However, this was not the case for oil prices, because a barrel of crude enjoyed a significant bull market. Even if we toss out the price spike from the 1979 Iranian hostage crisis and embargo (but unavoidably include the 1974 crisis) and measure returns from 1970 to 1978, it is worth noting that the price of oil compounded at 29.3% versus the 4.7% in the S&P 500.

Aside from the simple compounded returns of oil since the dissolution of Bretton Woods, sometimes a picture is worth a thousand words. You have seen Figure 8.7 before, in Chapter 4, “Quis Custodiet Ipsos Custodes?” but here we offer another brief illustration of the tremendous expansion in the monetary base.

Figure 8.7. U.S. monetary base

Source: Federal Reserve

From Figure 8.7, it is relatively clear that since the early 1970s the expansion of the monetary base has continued unabated, and then of course it was punctuated by the binge printing of late 2008 and early 2009. The implications of a loose money policy are straightforward. It causes higher inflation and the likelihood of drifting from one asset bubble to another over time as the preceding easy access to capital leads individuals into risk taking or speculative ventures.

Now that we have highlighted and discussed the central arguments for higher future oil prices, the question remains as to what to examine regarding investments in this space. In this regard, the job of the investment manager becomes more familiar. First, in light of our previous discussion, one of the primary focus points for an investment would be firms that possess the balance sheet and proven expertise to expand production over time. One simple test is to review the firm’s ability to replace its reserves over time, as well as its average growth in reserves over time. Over the past 17 years, reserve replacement has averaged 242% across the industry, as shown in Figure 8.8. Firms with above-average records and/or a perceived ability to maintain or generate this continued above-average performance should be considered.

Figure 8.8. Worldwide median reserve replacement

Source: Company reports, CSFB

Historically, firms that have been able to create a strong mix of reserve replacement, growth in production, and a low cost of production, combined with a conservative balance sheet, have performed well in the stock market. Tables 8.11 through 8.13 show the market’s preference for these factors in a correlation study between the variables of reserve growth, production growth, and low cost structures. In each study the correlation coefficients between the variables and stock market returns are statistically significant at 0.6 for reserve growth, 0.6 for production growth, and –0.6 for cost structures. (This means that higher dollar-per-barrel costs coincide with lower market returns.)

Table 8.11. Correlation Between Annualized Reserve Growth and Stock Market Returns

Table 8.12. Correlation Between Annualized Production Growth and Stock Market Returns

Table 8.13. Correlation Between Total Cost Structure and Stock Market Returns

Among the E&P names illustrated in these tables, an investor might focus on those with the best mix of reserve growth, production growth, and low cost structures. Similarly, an investor might consider eliminating from consideration firms with poor track records in these variables, as well as firms with above-average financial leverage on their balance sheets. From a fundamental perspective, an investor should also focus on the geopolitical risks described in the earlier discussions as a possible limiting factor insofar as safeguarding against the company assuming too much risk toward the possible nationalization or even expropriation of shareholders’ assets.

Seeking Alternatives in the Hydrocarbon Space

The problem of geopolitical risk in the sense of nationalization, and even expropriation in some cases, has forced the publicly traded energy companies to increasingly think outside the box in their pursuit of future reserves and growing profits on behalf of their shareholders. In other words, these firms are pushing considerably harder into the alternative energy space. The key attraction in the alternative space for the publicly traded companies is that they provide a growth area. But they also circumvent the geopolitical risks to a larger extent, because production can be located in shareholder-friendly developed markets that protect property rights. For the purposes of our discussion, we will contain our thoughts to the alternative energy sources that are tied to hydrocarbons, rather than solar and wind power. Basically we are referring to oil production that will over time come more and more from the conversion of oil sands, natural gas to liquids, and perhaps even coal to liquids. We should make a few points before we get ahead of ourselves. First and foremost, currently no forms of alternative energy can simply step in and totally supplant our need for oil. Second, although the circumstances can vary by asset, these alternative forms of energy also require relatively high prices of oil over some period of time to maintain their commercial feasibility and expand production in a meaningful way. Since we have made the case for higher future oil prices, this is a worthwhile exercise to define and illustrate the potential opportunities. Simply put, these areas possess outstanding potential for growth in the coming years, particularly since the existing capacity in place is beginning from a relatively small base. Based on the most recent data, the unconventional oil in the market was just under 4% of supply in 2006. But based on projections provided by the Energy Information Administration (EIA), this level of supply could reach 13% in the coming 20 years (see Figure 8.9). In other words, based on these projections, this segment of the industry is projected to grow at 8.9% compounded over the next two decades.

Figure 8.9. World supply of liquids in 2006 and 2030

Source: EIA

Clearly, this is an industry projection. We should expect that some producers will grow at rates above this trend line, and others will grow below it. In any event, let us now discuss the unconventional or alternative sources of hydrocarbons that we can reasonably expect to constitute this quickly growing portion of the energy market. We will begin with the Canadian oil sands, because this asset base may present the best opportunity over the coming five to ten years from a growth standpoint. Measured on a reserve basis, the Alberta Energy Resources Conservation Board estimates that based on current technology, 170 billion barrels of recoverable reserves are in the Canadian oil sands. This puts Canada second in the world behind Saudi Arabia. Naturally, this is still a developing industry. As technology advances through continued commercialization and competition, these reserves could actually increase from this number over time. Again, before we get carried away, we should emphasize that the industry is still developing (it only began in the late 1960s). Realizing anything close to this full potential could take a good while. With ostensibly all the major oil sands contained within three locations in Alberta, the North American industry is relatively geographically concentrated. Within Alberta are three deposit locations—in the Athabasca, Peace River, and Cold Lake regions. One reason why the industry will take time to develop is that there are two ways to extract the oil sands. One is close to the surface, where the oil sands are mined in an open pit. The second occurs when the oil sand deposits lie much farther below the surface. Not surprisingly, the open-pit-close-to-surface process is more economical, but only 20% of the total deposits sit close to the surface. The remaining 80% are extracted through an in-situ process at levels too deep for open pits (much greater than 200 feet). The in-situ process involves introducing heat into the mine through the use of steam, which raises the viscosity of the bitumen. This process involves far more energy usage and lower recovery rates, both of which conspire to raise costs. In time, however, the cost of production involved with the deeper deposits should fall, because the burden lies on technology that should be improved over time. This contrasts with the open-pit process, which is more labor-intensive, thereby making the cost of production more difficult to drive down from current levels. No matter where the deposits lie, the process to obtain a barrel of a refined product is rather burdensome. When we use the term oil sands, we mean that within this collection of sand, clay, shale, sandstone, and other surface materials is the presence of bitumen. This bitumen is what matters. The bitumen is what gives the oil sands their tarlike qualities. Obviously this material is not particularly viscous relative to other oil deposits, which are far more liquid. When the oil sands are mined from the ground, all these tagalong materials must be separated to obtain the bitumen. To bring this process into perspective, it takes roughly two tons of this mined material to make one barrel of oil. If that sounds like a lot of work to get one barrel of oil, you are right. If that also sounds like an expensive undertaking to obtain one barrel of oil, right again. There is no way around this at the moment. To bring these cost relationships into perspective, an oil sands operation may require a capital expenditure of $100,000 per daily barrel, which is about four to six times higher than the cost of deepwater drilling. Another complicating factor is the recovery rate from the mined material. Near the surface it is very high at 75% to 95%, but when mined through the in-situ process, the rate becomes far less certain and can range from 25% to 75%. So if we put all this together, it is hard to get a one-size-fits-all picture of the underlying economics-to-oil-sands production because, just as in oil, the rate of return can vary by site. Nevertheless, if we consider what is currently known about the current cost of production, it is believed that the price of oil needed in the market ranges anywhere from $35 to $85. It goes without saying that the low-cost producers making this product at less than $35 per barrel feel relatively comfortable. But the projects on the other side of the cost spectrum at $85 have much to consider before the producers sink billions of dollars into a site that takes years to construct. For that matter, new projects during the last several years became particularly prone to cost overruns due to the wild run in steel prices, which comprise approximately 50% of the capital outlay. Reports of costs rising fourfold on these projects were not uncommon. Despite the risks and complexities involved, a plethora of energy companies currently are involved or getting involved in the oil sands, so clearly these experts recognize the potential of this unconventional product. With that said, at the margin these businesses require a relatively consistently high oil price approaching $90 for many of them to make sense. In time, the breakeven price for a barrel of oil may fall as these professionals become more proficient in the space and begin to innovate. In the meantime, investors with a long-term horizon should examine these companies. In particular, they should do so when they have concerns about the price of oil due to weakening cyclical variables that can fluctuate over the course of a business cycle. In other words, this is an area for secular growth in the energy industry where investors may have opportunities to take advantage of market volatility.

The oil sands are a compelling growth story within the energy industry. But this is still just one of many possible solutions to get more production to the market to counter the stagnating production in the traditional sources. Another solution lies in a technology that was first developed in the 1920s by German scientists Franz Fischer and Hans Tropsch. The Fischer-Tropsch process involves converting a mixture of hydrogen and carbon monoxide into syngas (see Figure 8.10). It is then reacted with a catalyst such as iron or cobalt, leaving a waxy substance that can easily be converted into synthetic liquid fuels. Most important, the mixture of hydrogen and carbon monoxide can be obtained from natural gas, coal, and biomass, thereby creating liquid fuels from these raw materials. One of the key advantages of the coal-to-liquids and gas-to-liquids production through the Fischer-Tropsch process is that the end product is readily useable in the current energy consumption infrastructure. Just like creating refined product from oil sands, filling stations and various transportation vehicles are ready to consume the Fischer-Tropsch end product.

Figure 8.10. Synthetic fuel production in the Fischer-Tropsch process

Source: EIA

Although this process has been around since the 1920s, and the Germans used it during World War II to create fuel, it has only been commercially adopted in the past 50 years. Most notably, the South African firm Sasol has been creating coal-to-liquid synthetic crude since the 1950s. During the past 50 years, the world’s economies have received plenty of proof that this process can be done, but this method of fuel production has not proliferated by any measure. Without question, this technology has been met with heavy resistance from the green parties and their views on what constitutes an appropriate form of alternative energy. In this respect, the use of coal as a feedstock for synthetic crude production faces an uphill climb in developed nations, such as the United States. The major objections include coal’s mostly indefensible reputation as a dirty form of energy. This is well known and creates a barrier to the expansion of Fischer-Tropsch technology producing crude with coal as its feedstock. On the other hand, technology on carbon sequestration is advancing and could potentially weaken these objections. Despite green objections, it will be tough to eliminate the possibility of this technology’s entering the fray sometime in the years to come as one of the developed market’s energy solutions. The United States is appropriately referred to as the Saudi Arabia of coal. Not only does the United States have coal, it has more coal than any other nation in the world by a wide margin, as shown in Figure 8.11.

Figure 8.11. The world’s proven coal reserves as a percentage of the total

Source: BP Statistical Review

Along with the institutional resistance to coal-to-liquid fuels due to environmental factions, we must consider the economics of production. On this front, the cost of production is actually not much of a serious deterrent within the market paradigm of consistently higher oil prices. Most estimates suggest that an oil price of only $45 to $50 is needed in the market. On the other hand, the issue of carbon sequestration has come under debate, because it has never been tried on the scale necessary to bring parties together on the environmental impacts of this technology. There is little question that a great deal of the carbon dioxide created during the production process needs to be removed from the air through sequestration and hypothetically stored in mass containment centers thousands of feet underground. This process in and of itself would raise the breakeven cost per barrel of oil in the market by $5 per barrel. All this assumes that the sequestration process goes according to script. Last, this entire process could face significant cost headwinds if a cap-and-trade policy on carbon emissions goes into effect, since the production process involves heavy emission of carbon dioxide. In the event of the passage of a cap-and-trade policy in the U.S. legislature, the effect would be a blow not only to the prospects for coal-to-liquid technology, but also to the coal industry in general, since it is also a heavier emitter of carbon dioxide relative to other industries in the United States. Basically, a cap-and-trade policy would force the cost of production higher in the coal industry (which must purchase the carbon allowances). The cost of purchasing these credits would then be passed on to end users in electric generation (as elsewhere). Eventually, these costs would arrive monthly in the mailboxes of U.S. consumers, printed on their utility bills. Conversely, in the absence of such legislation and the eventual emergence of coal-to-liquid technology, there would be opportunities for investors, as well as the coal companies themselves, to invest directly in existing technology providers for coal-to-liquid applications. A new layer of consistent demand would emerge for coal that would in turn make the reserves more valuable in the market. Furthermore, although we couched much of our coal-to-liquids discussion around the market in the United States, the coal-to-liquids market also has potential outside of the country and may expand faster in the international markets. One instance lies in China, where coal-to-liquids technology was recently put in place through the construction of a coal-to-liquids plant by the Shenhua Group. China, like the United States, has a relatively large coal resource and is searching for ways to power the growth of industrialization since it too has limited oil resources. Coal can be controversial in some corners, primarily among developed nations’ green parties.

On the other hand, natural gas, the other significant feedstock for the Fischer-Tropsch process of synthetic crude production, is somewhat less of a hot-button natural resource. Gas to liquids (GTL) represents another future growth mechanism in the energy field that investors need to eye for long-term potential. GTL is a synthetic crude product that undergoes the same basic process as coal-to-liquids production in the Fischer-Tropsch process but obviously substitutes natural gas for coal as the feedstock. The South African firm Sasol is a leader in this production process, along with Shell, which both separately constructed GTL plants through joint ventures in Qatar. One of the interesting dynamics at play for the GTL market is its potentially multifaceted application. In the GTL plants in Qatar, we are talking about massive engineering feats that are situated close to large, long-lasting supplies of natural gas. However, the GTL process is also being innovated to monetize unique situations, including remotely located supplies of natural gas, as well as the natural gas supplies that often accompany oil fields and are most often flared. For quick background, it has been common practice for oil producers to install a flaring device that burns off the accompanying natural gas from an oil field. This can be seen as wasteful and polluting. In fact, many producers have reduced or eliminated this practice. Historically, there has been little opportunity to economically produce the accompanying natural gas due to the location of the oil field and the generally cost-prohibitive methods of transporting gas versus a liquid. The market potential for this application is recognizable. Estimates provided by the World Bank suggest that the equivalent of 700 million barrels worth of oil is wasted through flaring in a given year. Through the GTL application, however, oil producers may in the future be able to use the converted natural gas by-product as a readily marketable product for sale. Likewise, a similar approach to using smaller-scale GTL plants or conversion processes may open the market for one-off localized applications in a number of previously inconceivable market circumstances. Despite the market potential in a number of scenarios, GTL faces the same economic impediments as the previous unconventional liquids, such as oil sands and coal-to-liquids products. The necessary cost per barrel in oil prices can range from around $38 all the way to more than $100 per barrel. In other words, the early projects, such as those in Qatar, may represent the lowest cost of production, and the ones on the horizon likely will require higher oil prices. However, given our backdrop of higher oil prices over the coming years, investors need to be opportunistic and look for investments before oil prices make it abundantly clear that these technologies have growth potential and projects are announced left and right. Summarily speaking, our introduction of these unconventional liquid technologies and their promise for growth are meant to provide investors with energy themes possessing growth potential. Unfortunately, it is difficult to establish the static, end-all breakeven price per barrel of oil for these technologies since the circumstances can change quickly. For example, as we mentioned earlier, steel comprises approximately 50% of the cost in the capital outlay, and the price of this commodity has been and likely will remain volatile. Also, the cost of production can vary by the natural resources itself. Producing oil at a relatively low depth in the middle of a wide-open space in Saudi Arabia costs less than putting together an operation in the icy waters of the inhospitable arctic regions. With that said, we can still gain some perspective from estimates compiled by the International Energy Agency (IEA) regarding what it believes to be a range of the cost of production across various oil-producing regions and technologies. Table 8.14 should provide investors with some perspective on how distant the advent of our described technologies (among others) may be in relation to oil prices quoted in the market.

Table 8.14. Breakeven Costs Measured in Oil Prices Per Barrel by Source of Supply (2008)

This chapter tried to highlight the importance of the oil and energy markets and provide a framework for how to approach them over the coming years by identifying the most important drivers surrounding supply and demand. These factors will no doubt be tested over time, because they quickly fade into the background during periods of cyclical weakness, just as they did during the financial crisis and the subsequent collapse in oil prices. However, with a good knowledge of the long-term secular trends in this market, investors should be well-positioned with the psychological fortitude to step into the void and buy, should the market experience further corrections, pessimism, and disruptions—which it always does over time.

Endnote

¹ Stacy L. Eller, Peter Hartley, and Kenneth B. Medlock III. “Empirical Evidence on the Operational Efficiency of National Oil Companies.” Prepared in conjunction with an energy study sponsored by the James A. Baker III Institute for Public Policy and Japan Petroleum Center. Rice University, March 2007.