In May 1980, Exxon Mobil (XOM) acquired Atlantic Richfield's 60% interest in the Colony Oil Shale project in Colorado for $400 million. At the time, the purchase was one step in an ambitious plan to invest $5 billion in oil shale development, a sum worth more than $11 billion in 2009 dollars.
Exxon's plans included the construction of a new town with a total projected population of 25,000 workers and their families and six of the largest surface mines in the world. The scale of the mining project was immense; Exxon estimates that it would process about 66,000 tons of raw shale per day to produce around 47,000 barrels per day of shale oil. The company's most optimistic internal projections showed oil shale generating as much as 8 million barrels per day by 2010.
And while Exxon was the largest company to invest in oil shale, it wasn't the only player in the industry. Unocal, Royal Dutch Shell (RDS.A), Amoco and Ashland Oil, among others, all had projects in the region. In fact, even the US government was involved when Congress approved a $14 billion package of incentives for synthetic fuels development in 1980. Land values in the region sky-rocketed as did local salaries; the towns Exxon created were reminiscent of the Gold Rush boom towns of the 19th and early 20th centuries.
But almost two years later Exxon abruptly pulled out of the Colony Shale project, writing off more than $1 billion of its investment. The sudden about-face on shale turned boom towns across rural Colorado into latter-day ghost towns. The expensive mistake was an embarrassment for Exxon and among the greatest strategic miscalculations in the industry’s history.
As a result of the Colony fiasco, the mere mention of the word "shale" in the same sentence as "oil" sends most investors running for the proverbial hills. Unfortunately, this knee-jerk bias also prevents far too many from taking advantage of one of the more compelling investment opportunities in the North American exploration and production (E&P) industry today: shale oil.
There’s a huge difference between oil shale and oil produced from shale reservoirs, often called shale oil. The former remains a promising, yet expensive-to-produce resource that may eventually see more development. The latter generates significant, real production growth for a host of independent North American E&P firms; with crude around $70 to $80 a barrel, many shale oil projects are generating an after-tax return on investment of as much as 100%.
Oil Shale Today
Oil shale is an inorganic rock that contains a solid organic compound known as kerogen. The term "oil shale" is a misnomer because kerogen isn't crude oil, and the rock holding the kerogen often isn't even shale.
Conventional liquid crude oil is organic material--plant and animal remains--exposed to heat and pressure in the absence of oxygen over millions of years within the earth. Kerogen is among the first stages in the process of petroleum generation from organic matter; bitumen--the hydrocarbon targeted in oil sands projects--is formed from kerogen and represents a later stage in the process.
To generate liquid oil synthetically from oil shale, the kerogen-rich rock is heated to as high as 950 degrees Fahrenheit (500 degrees Celsius) in the absence of oxygen, a process known as retorting. Shale can be heated underground, known as in situ retorting or can be mined like coal and retorted on the surface.
There are several competing technologies for producing oil shale. Exxon has developed a process for creating underground fractures in oil shale, filling it with a material that conducts electricity and then passing current through the shale to heat it and gradually convert the kerogen into producible oil. Shell uses electric heaters that it buries underground to heat the kerogen slowly.
Although estimates of the cost to produce oil shale very widely, it's more expensive and energy-intensive that producing oil sands. Producers would probably require oil prices to reach roughly $100 a barrel before this capital-intensive process would become feasible on a commercial scale. And while extensive testing has been done, there have been no modern commercial-scale oil shale developments.
There are a handful of projects in the works, but none are likely to produce significant quantities of oil for well over a decade. Brazil's national oil company (NOC) Petrobras (PBR), Shell, Exxon and Japan's Mitsui (MITSY) are among the companies involved in US various oil-shale projects. Clearly, none of these companies represent pure plays.
The potential size of the resource is huge. Oil shale naturally occurs in more than 20 countries around the world, and Brazil, Estonia and China all have small commercial projects producing a total of 14,000 barrels of oil per day. However, by far the world's largest oil shale resource is located in the Green River formation of Colorado, Wyoming and Utah. Colorado contains the richest shale.
Total recoverable resources could be as high as 1 trillion barrels, roughly four times Saudi Arabia's total proved reserves. However, don't be duped by those huge reserve estimates and the hype that oil shale will make the US energy independent.
As I've written before, the term reserves is widely misused and misunderstood; what really matters isn't how much oil is in the ground, but how quickly that oil can be produced and how much it'll cost. The media often fuels the hyperbole by stating that a particular field contains oil equivalent to a year or more of US crude oil consumption; the comparison is meaningless because it will typically take several decades for that recoverable oil to be produced even under the most optimistic scenarios.
Here’s a more realistic assessment for oil shale: If crude prices remain elevated for a prolonged period, prompting an increase in oil shale development, it's possible that production will hit 150,000 barrels per day by the late 2020s. The Energy Information Administration (EIA) projects that US oil shale will produce 144,000 barrels per day by 2030. That might be meaningful for a few companies, but it’s hardly a game-changer.
Bakken Shale and Barnett Combo
All-too-often investors confuse oil shale produced in Colorado and plays like the Bakken Shale of Montana and North Dakota. These plays couldn't be more dissimilar. Shale oil plays such as the Bakken have far more in common with shale gas plays like the Marcellus Shale of Appalachia and Haynesville Shale of Louisiana than they do with oil shale of Colorado.
Shale oil plays are unconventional fields. Without getting too technical, natural gas and oil don’t exist underground in some giant cavern or lake waiting to be pumped to the surface. Rather, hydrocarbons are found trapped in the pores and cracks of a reservoir rock. A typical conventional reservoir rock is sandstone; sandstone looks like a mass of sand particles stuck together to form a rock. Sandstone has many pores that are capable of holding hydrocarbons. In other words, sandstone has favorable porosity.
Typically, those pores are also well connected so that oil and gas can easily travel through sandstone reservoir rock. Such rocks have a high degree of permeability. When a producer drills a well in a conventional field, oil and gas travel through the reservoir rock and into the well, powered mainly by geologic pressures.
Shale fields and other unconventional fields aren’t particularly permeable. That means while there is plenty of oil and/or gas in the rock, there are no channels through which that oil or gas can travel. Thus even in shale fields where there’s plenty of geologic pressure, the hydrocarbons are essentially locked in place.
Producers have developed and refined two major technologies in recent years to unlock shale: horizontal drilling and fracturing. The first technology is self-explanatory: Horizontal wells are drilled down and sideways to expose more of the well to productive reservoir layers.
Fracturing is a process whereby producers pump a liquid into a shale reservoir under such tremendous pressure that it cracks the reservoir rock. This creates channels through which hydrocarbons can travel, improving permeability. Fracturing and horizontal drilling are now common in the US and producers have perfected their use on gas shale plays; leveraging the same basic techniques to produce oil from similar reservoirs does not require the sort of multi-billion dollar upfront investment that producing oil shale does.
Shale oil, unlike oil shale, does not have to be heated over a period of months to flow into a well. And the oil produced from these plays is crude; in fact, many producers say that it’s even better quality on average than West Texas Intermediate (WTI), the US standard crude that’s the basis for NYMEX futures.
The Bakken Shale is an unconventional oil play located in North Dakota, Montana and across the Canadian border in Saskatchewan. The US side of the play offers thicker deposits of oil; however, the Bakken looks like a commercial play in Saskatchewan as well. The graph below shows total oil production from North Dakota going back to the early 1980s. (Click to enlarge)
Since 1981, total US crude oil production has plummeted 34%, or close to 3.5 million barrels per day. Oil production from North Dakota appeared to be following the general trend in US production up until 2004 or 2005, when output exploded to the upside. Subsequently, total monthly production has soared from about 2.3 million barrels per month to about 6.5 million, a near tripling in production in about 5 years. Much of this growth has come from the Bakken Shale play.
Let's put these figures into perspective: 6.5 million barrels per month works out to about 216,000 barrels per day. That's not much in the context of an oil market of 20 million barrels per day. But, it does look meaningful when you consider that the EIA is looking for oil shale to contribute a total of just 150,000 barrels per day by 2030.
Further, it's an extraordinarily meaningful resource for the E&P companies involved in the region; some are looking to grow their oil production more than 50% in 2010 alone by exploiting unconventional oil plays like the Bakken. At current oil prices most producers believe that wells in the core part of the Bakken Shale play offer after-tax returns on investment of 100% and remain profitable even at significantly lower prices.