Even if analysts had been tipped off that the world was about to lurch into a supply-driven state of energy surfeit, they likely would still have been unable to predict the source of this energy largesse. The authors of the Global Trends report produced in 2008 did in fact grapple with the question of whether technological revolutions would change the supply side of the energy equation. Specifically, they, like most analysts at the time, were focused on the growth potential of new sources of cleaner energy. Would the world realize the full fruits of innovations in energy storage, clean water, and biofuels? Would solar, wind, and hydropower allow the world to transition away from fossil fuels to alternative low-carbon energies?
Certainly, there have been important advances in the world of renewable energy in recent years. In the first decade of this century, renewable electricity generation from nonhydro sources nearly quadrupled. Generous subsidies and policy incentives from European, Chinese, and American governments contributed to the maturation of solar and wind energy. This support encouraged expansion and helped drive down costs to the point where, in some sites, both wind and solar are cost competitive with fossil fuels without subsidies. Such growth will continue in the years ahead, with renewables accounting for more than a quarter of electricity generation by 2021. But the actual and anticipated dramatic growth in renewable energy—coming from such a small base—cannot itself explain the sudden and remarkable global shift from energy scarcity to energy abundance. After all, nonhydro renewable energy still only accounted for 3 percent of overall global energy usage in 2016.
The energy revolution that analysts overlooked in 2008 was not in renewables, but in oil and gas. The experts did not foresee the emergence of new resources that would fundamentally change the balance between the supply and demand of oil and gas, as well as the structure of energy markets. These new, unanticipated oil and gas resources are known as “unconventional,” but not because their molecular structure is any different from those considered “conventional.” Instead, the term refers to the method required to extract the oil and gas. Unlike more familiar oil and gas resources, unconventional ones do not reside in large reservoirs that can be tapped and drained with a small number of wells. The challenge of unconventional resources is to liberate the oil or gas from millions of small pockets in shale rock, where they reside, like bubbles in champagne.
It is the type of extraction process that provides the distinction between conventional and unconventional oil and gas, and over time what is considered to be unconventional may change. The next important distinctions are within the category of what is broadly labeled unconventional. Think of “unconventional oil” as an umbrella term with many different unconventional oils grouped under it, including kerogen oil, gas converted to liquids, and tight oil (also known as shale oil). Likewise, the term “unconventional gas” is also an umbrella term that encompasses several different types of natural gas, one of which is shale gas. There is also more than one unconventional extraction technique. The most well-known process is “fracking,” which is used for extracting resources such as shale gas and tight oil. But oil sands, also considered an unconventional oil, is generally extracted by very different means: the intense heating of the resource while it is underground before extracting it.
The diagram below helps explain the relationship between unconventional and conventional energy, and the different forms of energy that fall under each category. For the purposes of this book, and for most conversations in the energy world today, the “unconventional boom” refers to dramatic changes in the production of a wide variety of oil and natural gas resources. Two specific unconventional resources, shale gas and tight oil, are also frequently referred to in this book. They warrant special mention because they have turned out to be the most prolific new unconventional energy sources in the United States and, to a lesser extent, in Canada, and have prospects of being produced in significant quantities outside North America.
The roots of today’s surfeit of oil and, to a lesser extent, natural gas lie in two related stories, half a world apart. The first is a tale of technology, innovation, and human persistence in America’s heartland. The second is a saga of politics, markets, and power in the deserts of the Middle East. The two stories came together to deliver a major shock to the world, spurring us to look at the globe through a lens of plenty, not paucity.
Figure 1.1: Unconventional Resources is an Umbrella Term
Source: International Energy Agency, World Energy Outlook, 2015, 678.
The Man Who Squeezed Oil from Stone
In 1952, George Mitchell, a struggling petroleum engineer running a small company with his brother, received a tip from an unlikely source. A bookie who usually took horse racing bets insisted that a fortune could be made drilling on a piece of land north of Dallas nicknamed “wildcatters’ graveyard.” Neither the name of the land nor the source of the tip was particularly encouraging, but Mitchell checked out the ranch. After his initial survey, he saw some possibility and arranged for a small lease. The first ten wells produced gas, but no oil—explaining why so many others had declined to make a similar investment. But Mitchell was encouraged and convinced he could turn natural gas into a profit, even at the low prices of the time. Within ninety days, he had collected enough money from his investors to purchase 300,000 acres—or a little under five hundred square miles—at about $3 apiece.
Thus began George Mitchell’s romance with the geological formation known as the Barnett Shale. Mitchell’s fixation on that expanse of shale rock south and west of Dallas would nearly drive him to ruin before it eventually propelled him to great fame and fortune. The natural gas Mitchell initially found and produced from the shallow formations of his property soon tapered off. But he was aware that there was a great deal of additional natural gas trapped in the fissures of shale rock deep beneath these formations. Geologists had long known of the resources confined in these rocks. The first reference to them had come from French explorers and missionaries in the mid-1600s.
The difference between George Mitchell and the countless others who had dismissed this shale gas as uncommercial mostly came down to determination. Mitchell would spend half a century and nearly a quarter of a billion dollars researching and experimenting with different modes of coaxing the natural gas out of the shale rock and bringing it to the surface. His main focus was on a practice called hydraulic fracturing. Mitchell did not invent the technique. It had in fact been used as early as the 1860s, with its first commercial application in 1949 in Oklahoma and Texas. The essential idea was—and still is—to pump large volumes of fluid down a well at high pressure to create cracks in the source rock. Those cracks are then prised open by introducing a porous substance, often sand, that allows gas to flow out from the rock when the well is depressurized.
Mitchell and his engineers sought to find the right combination of materials, apply them in the correct fashion, and create fractures of the right size. It was a lonely endeavor, but Mitchell’s team had help. They were the beneficiaries of U.S. government programs created in the 1970s to reduce dependence on Middle Eastern oil by backing initiatives to exploit domestic resources. Government-funded projects mapped and assessed shale formations throughout the country and provided tax breaks and other incentives to entice companies to explore nascent technologies and drilling techniques. As the U.S. government has done in so many other areas from supercomputers to advanced prosthetics, it hoped to catalyze innovation in areas that were not, on their own, significantly attractive to private investors and researchers. Well aware of the resources trapped within the shale rock, the government sought to motivate and support Mitchell in his pursuit to liberate them.
Mitchell was pushing to succeed where much larger oil and gas companies had given up. But it wasn’t only executives from other companies who thought Mitchell was on a fruitless pursuit. His heir apparent, Bill Stevens—and even his own son, Todd, a geologist who sat on the board of Mitchell Energy—argued ardently against Mitchell’s plans
in professional and private settings. George Mitchell, they insisted, was driving his company into the ground with his obsession to tap into shale gas.
Through it all, Mitchell Energy made incremental progress. The most important advance was dramatically bringing down the costs of hydraulic fracturing by continually innovating and readjusting the formula. Mitchell decreased costs by relying on a relatively inexpensive fracking fluid—a combination of sand, water, and other chemicals—after flirtations with nitrogen foam, nitrogen gel, and other substances. Mitchell’s team also increased its overall efficiency, reducing the average time it took to drill a well by nearly a half. These advances helped coax more natural gas out of the wells, and people in the industry began to note a small, but distinct, uptick in Barnett natural gas production. Some began to wonder if that crazy George Mitchell was finally onto something. Devon Energy, an oil and gas company that had earlier declined to buy Mitchell Energy, gave the company a second look and, in 2001, purchased it for $3.1 billion.
Devon combined Mitchell’s advances in hydraulic fracturing with its own enhancements in another technology: horizontal drilling. This combination proved powerful. Mitchell’s innovation allowed for a cheaper and more effective extraction of gas from the source rock. Devon’s knowledge of horizontal drilling, opposed to traditional vertical drilling, enabled the company to maximize exposure to the rock’s surface. This drilling was especially beneficial in dealing with shale gas, as shale formations, which run laterally, are often long and thin, and the gas, trapped in very small pockets, requires contact across large faces of the rock. Combined, these two technologies came to be known as “fracking.”
Devon added one more ingredient to the mix—the use of 3-D seismic data—to help place the horizontal well in the optimal position vis-à-vis the shale formation. The marriage of these techniques—hydraulic fracturing, horizontal drilling, and 3-D seismic data—began to produce dramatic results. By 2003, initial production rates of a handful of wells were more than three and a half times what Mitchell Energy wells had been producing. Devon filed the production rates of these wells with the Texas Railroad Commission (which had evolved to regulate oil and gas production over time) and they became public in July 2003. In the months that followed, more than two dozen other operators applied for permits to drill more than one hundred horizontal wells in the Barnett. Within a decade, the number of wells in the Barnett had increased 750 percent, and the production of natural gas in the Barnett grew almost sevenfold over the same period. This success was soon replicated in similar basins across the country.
Small companies took the lead in applying Devon’s recipe to basins such as the Eagle Ford in South Texas and the Bakken in North Dakota and Montana. At least initially, large oil and gas companies such as ExxonMobil, Chevron, and Shell—often called “the majors”—could not be bothered with such intensive efforts. They were more focused on oil production and, in any case, they had little interest in tending to thousands of wells with such small yields. Instead, they preferred to concentrate on the “big elephant” projects such as the offshore Nigerian field Amenam-Kpono or to tap into the vast natural gas reservoirs in the Arctic shelf. These projects promised enormous returns over time and capitalized on the natural advantages of the majors, which excelled in managing complex projects. In contrast, the smaller oil and gas outfits seemed better suited to develop the shale “plays” due to their comparative flexibility and decentralized decision-making.
A proliferating number of smaller-scale operators seized the opportunity to parlay fortuitous geography into sometimes staggering fortunes. The Wilks brothers—two enterprising bricklayers in Texas—were just two of many, and they entered through a back door. Having learned masonry skills from their father, the two, Farris and Dan, founded Wilks Masonry in 1995. Several years later, new geological imaging technology revealed shale beneath their land. Big oil and gas companies had no interest in fracking their small plot. Being entrepreneurial in spirit, Farris and Dan purchased some equipment, manufactured other tools, and began fracking their own land. Specializing in little jobs, Farris and Dan began to service the wells of their neighbors, eventually founding a company called Frac Tech. The company grew as small landowners—incentivized by U.S. law that grants them rights to what lies below the grass under their feet all the way down to the core of the earth—rushed to exploit their unexpected riches. In 2011, after eight years of building and operating Frac Tech, Farris and Dan sold it to Temasek Holdings, Singapore’s sovereign wealth fund, for $3.5 billion. That same year, Forbes ranked them among the 400 wealthiest Americans.
The collective efforts of dozens of small and midsized American companies fundamentally altered the U.S. energy landscape. Companies took advantage of readily available financing and private ownership of subsurface minerals, and were kept lean and hungry by America’s competitive marketplace. Eventually, larger companies joined in. Natural gas production in the major U.S. shale formations skyrocketed, driving a veritable bonanza in U.S. shale gas production and a stunning turnaround in overall American natural gas output. In 2006, the United States was producing enough shale gas to heat 15 million homes a year; by 2014, this amount had grown sufficient (hypothetically) to heat 200 million homes a year. By 2015, more than half of all natural gas produced in the United States came from shale, compared to just 6 percent a decade earlier.
It didn’t take a genius to surmise that what worked in shale formations that held shale gas, might well work in shale formations that held primarily tight oil instead of shale gas. Companies began to apply the same fracking technologies to such basins in the later part of the first decade of the 2000s, again achieving staggering results. Production of tight oil in the Eagle Ford shale in Texas grew twenty-four-fold from January 2007 to January 2014. Total production from this one basin surpassed that of OPEC member Algeria and nearly matched the entire production of Kazakhstan. Tight oil production in the Bakken fields increased eightfold during the same period. In 2014, U.S. tight oil production alone surpassed Iraq’s overall annual production. In the same year, burgeoning U.S. tight oil production pushed overall American crude output to be 10 percent of the world’s total supply. Accounting for nearly half of overall U.S. crude oil production, tight oil was the driving force behind America’s oil resurgence.
Figure 1.2: Dry Natural Gas Production by Type (trillion cubic feet)
Source: EIA, Annual Energy Outlook 2017, 57.
The gush of new American oil was significant. An additional 4.9 million barrels a day (mnb/d) at its first peak in March 2015 might seem like a small addition to a total global market of 96 mnb/d. But the demand for oil is essentially fixed in the short term, so a quick change in supply can have a dramatic impact on price. Consider how a sudden contraction in the supply of oil can lead to a price spike. For instance, in 2005, damage to production, refining, and storage facilities in the Gulf of Mexico by Hurricane Katrina took 1.3 mnb/d of oil offline overnight, leading the price for American oil to rise 7 percent in a matter of days. A huge, relatively sudden increase in global oil supply could have the opposite effect, all other things equal.
Figure 1.3: U.S. Crude Oil Production (million barrels per day)
Source: EIA, Annual Energy Outlook 2017, 43.
Nevertheless, America’s new energy prowess was not in itself enough to tip the world into significant oversupply and drive down the price to lows not seen since 2003. In fact, as discussed earlier, from 2011 to 2014, U.S. tight oil inadvertently contributed to price stability. Instead of leading to a glut, it was substituting—nearly one barrel for one barrel—for oil coming offline as a result of political disruption in the Middle East, as seen in the graph on the next page. To fully understand the origins of the new oil abundance and the subsequent price decline, we must supplement the story of American innovation and technological advance with one of the politics and decision-making behind one of the world’s frequently derided and long-standing cartels.
Figure 1.4: Supply Disruptio
ns During Arab Upheavals and U.S. Supply Additions During the Same Time (million barrels per day)
Source: BP, BP Energy Outlook 2035, 2014, 34.
The Dethroning of OPEC
Sitting on his couch in Riyadh, Hamad Saud Al-Sayari recounted to me the woes of the 1980s in Saudi Arabia with painful accuracy. In 1983, he had just been appointed governor of the Saudi Arabian Monetary Authority, making him the kingdom’s central bank head. The fat years created by the oil price increases in the 1970s—following the 1973 embargo by Arab members of OPEC on countries supporting Israel in the Yom Kippur War and the 1979 Iranian Revolution—had come to an abrupt end. The global economy was slowing. The efforts to reduce fuel usage and oil dependency that consumer countries had initiated following the 1973 embargo were bearing fruit. Where consumers could, they moved away from oil to other sources of energy. In countries such as France and Japan, demand for heavy fuel oil virtually disappeared, as nuclear power, coal, and natural gas moved in as substitutes. Global demand for oil decreased by more than 10 percent. Further exacerbating the situation, new non-OPEC oil was entering the market. In the first half of the 1980s, Mexico, the U.K., Norway, China, Brazil, and India together increased their production by half to bring almost 4 mnb/d to the global market.
Not surprisingly, the combination of growing supply and declining demand forced prices down. In response, OPEC slashed its production by nearly half to bolster the price, but to no avail. As the world’s leading oil producer, Saudi Arabia bore the brunt of these cuts; by 1985, the country was producing oil at roughly a third of its 1980 levels. Worse, the increasing non-OPEC oil supply meant that Saudi Arabia was losing market share even as the price of oil continued to fall.
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