The New American Oil Boom implications for energy security


MARCH 2012   

In 2011, net U.S. imports of crude oil and refined petroleum products declined for the sixth consecutive year, reversing a decades-long trend of rising reliance on foreign suppliers. A number of factors played a role, including reduced demand for petroleum fuels as a result of the recession and rising levels of efficiency in the nation’s automotive fleet. Recently, however, increased domestic production of liquid fuels has accounted for a substantial portion of the shift, rising by 1.4 million barrels per day (mbd) between 2008 and 2011 while net imports declined by 2.7 mbd. Based on current U.S. dynamics, both trends—rising production and falling imports—appear to be sustainable for the next decade and possibly longer.

I. origins.

A number of factors surely played a role in the changing U.S. outlook, a   the combination of trends and developments that truly catalyzed the rapid   represents a kind of ‘perfect storm’ of price, technology, and opportunity.

Oil Prices: High and rising oil prices sustained over a period of several years sent a clear investment signal to the U.S. oil industry, which tends to be among the most price-sensitive in the world.  

Technology: On its own, a strong price signal would not necessarily have translated directly into meaningful increases in U.S. oil production. Higher prices needed to be complemented by an increase in producible resources—  together beginning in the mid-2000s.

While a number of factors surely played a role in the changing U.S. outlook, a handful of major developments stand out. In fact, the combination of trends and developments that truly catalyzed rapid expansion of U.S. oil production over the past several years represents a kind of ‘perfect storm’ of price, technology, and opportunity.

Oil Prices: High and rising oil prices sustained over a period of several years sent a clear investment signal to the U.S. oil industry, which tends to be among the most price-sensitive in the world. No doubt, there have been periods of immense volatility, and prices have occasionally retreated as they did at the height of the global financial meltdown in late 2008. But taken as a whole, the majority of the past decade has been characterized by a steady upward march in oil prices, which averaged less than $30/bbl in 2003, doubled to more than $60/bbl by 2006, surpassed $90/bbl in 2008, and averaged a record $111.26/bbl in 2011.24 This progressive increase in prices—which, critically, has been viewed by most industry participants as predominantly driven by long-term global economic fundamentals—created a strong incentive to invest in upstream oil exploration and development.

There are number of reasons why oil production in the United States tends to be price sensitive. A stable and transparent regulatory environment and generally low barriers to entry relative to other oil producing regions facilitate a high level of capital mobility. More important, however, is the relatively high marginal cost of incremental U.S. production.

A 2010 analysis from Sanford Bernstein concluded that the U.S. marginal production cost for oil was between $83/bbl and $86/bbl, including operating costs, production taxes, and depreciation.25

More specifically, IEA recently estimated the breakeven cost (including royalties) for U.S. tight oil resources at $50/bbl.26

 For the U.S. offshore, the Department of Energy reports total upstream costs (finding and lifting) averaged $74.20/bbl between 2006 and 2008.27

This figure retreated to $51.60/bbl between 2007 and 2009, in large part due to sharply reduced capital and operating costs in the wake of the financial crisis. Given current dynamics in global upstream costs, the 2006-2008 figure is likely a closer representation of current U.S. offshore costs.

It is important to place these costs in a production context.

Currently, approximately one-fifth of U.S. crude oil production originates from extremely price sensitive marginal wells that produce less than 15 barrels per day.28

An additional 22 percent of production originates from higher flowing, but also expensive, projects in the deep and ultra deepwater federal Gulf of Mexico.29

Tight oil production currently accounts for approximately 11 percent of U.S. supplies.30

In other words, more than half of U.S. crude supplies are identifiable as high marginal cost resources that require oil prices of at least $50/bbl just to break even.

Clearly, a high level of confidence in supportive oil prices is needed to develop U.S. resources,  and that is exactly what the market has provided since at least 2003.

Technology: On its own, a strong price signal would not necessarily have translated directly into meaningful increases in U.S. oil production. Higher prices needed to be complemented by an increase in producible resources—either through new discoveries, new recovery methods, or better drilling technology. In fact, a combination of all of these things came together beginning in the mid-2000s, most impressively in the onshore region of the lower-48 United States.

The story begins not with oil, but with the massive increase in development of unconventional natural gas. For decades, industry geologists were aware of the existence of natural gas resources deep in underground shale formations.31 However, the resource was viewed as technologically difficult to access and economically unattractive. In essence, shale and other tight reservoirs are defined by reduced porosity vis-à-vis conventional reservoirs.32 This reduced porosity made it difficult to collect commercial quantities of natural gas without expending tremendous capital.

Throughout the 1990s, the public and private sectors each invested significantly in research and development efforts designed to improve existing drilling technologies in order to profitably unlock shale gas.33

A 1999 report from the Office of Fossil Energy noted that the DOE-led Natural Gas and Oil Technology Partnership promoted a number of advances in hydraulic fracturing.34 The report also cites advances made by the DOE-funded Gas Research Institute during the 1990s, including better diagnostics and greater ultimate recovery. Beginning in 2003, surging natural gas prices added a final incentive for the industry to focus on achieving commercial production of natural gas from unconventional reservoirs. After averaging $3.96 per million Btu (MMBtu) in 2001 and $3.36/MMBtu in 2002, prices rose to average $5.47 and $5.89/MMBtu in 2003 and 2004 respectively.35 Between 2005 and 2007, the annual spot price for natural gas in the United States never fell below $6.73/MMBtu.

By 2008, rising prices and better application of drilling technology resulted in a virtual revolution in the natural gas industry. Proved reserves increased by 54 percent between 2000 and 2009—from 177 trillion cubic feet (tcf) to 273 tcf. 36 Moreover, proved reserves present only part of the picture.

The Colorado School of Mines Potential Gas Committee estimates that potential U.S. gas resources could be closer to 2,000 tcf, resulting in a theoretical reserves-to-production ratio of nearly 100 years at today’s consumption levels.37

The recovery technology that the industry used to unlock shale resources is known as hydraulic fracturing. Although fracturing existed in the industry for decades, its combination with new drilling techniques and other process improvements proved revolutionary. In order to extract natural gas from deep shale reservoirs, hydraulic fracturing over-pressurizes the source rock, creating multiple fractures in which gas supplies can accumulate. The fracturing process is typically achieved using fluids (like water under high pressure) along with viscosity-enhancing chemical agents (surfactants).

In addition, producers typically inject a proppant, or propping agent, into the well to keep the fractures from closing when pressure is reduced.38 Instead of using traditional vertical wells, hydraulic fracturing and recovery take place via horizontal wells, which increase exposure of the well bore to the gas-producing zone.

The growing attractiveness of horizontal drilling is reflected in the U.S. well count beginning in 2005, when the number of horizontal and directional wells drilled began expanding slowly. In the first week of January 2005, 127 horizontal wells were drilled. For the same period in 2006, the number was more than 320.

By 2008, high and rising natural gas prices drove an influx of investment in natural gas production, and the horizontal well count surged. In the week ending December 5, 2008, 625 horizontal wells were drilled in the United States.39

By the end of 2009, companies that had been active in unconventional gas production began to shift capital and drilling programs toward liquids production. Compared to persistently low natural gas prices, high and rising oil prices provided an attractive target.

In a  henomenon largely unique to the United States, the ratio of oil prices to gas prices began to expand dramatically. Between 2005 and 2007, a barrel of oil was on average worth about 1.5 times an equivalent amount of natural gas. By the fourth quarter of 2009, the oil-to-gas price ratio in the United States had expanded to 3.1.49 It would average 3.2 in 2010 and 4.9 in 2011. In March 2012, a barrel of oil was worth an astounding 10 times the equivalent volume of natural gas.

Fortunately, some of the most significant unconventional gas plays were known to contain 
sizeable liquid-bearing formations, and a number of other unconventional resource plays throughout the United States were known to be primarily liquids-rich.

In April 2011, the number of rigs drilling for oil in the United
States surpassed the number drilling for gas for the first time since 1995, and the oil rig count has only continued to grow.50

49 SAFE analysis based on data from: DOE, EIA, online statistics, “Natural Gas Spot and Future Prices (NYMEX)” and “Oil Spot Prices”
50 Baker Hughes, “North American Rotary Rig Count—U.S. Oil and Gas Split”

By early 2012, there were more rigs drilling for oil in the United States— approximately 1,296— than at any time since Baker Hughes began reporting the count in 1987.51

22 DOE, EIA, AER 2010, Table 5.2.
23 SAFE Analysis based on data from: DOE, EIA, AER 2010, Table 5.2; and World Oil Online, “U.S. Well Counts Rise in All Regions,”
Volume 233 No.2, February 2012
24 DOE, EIA, online statistics, “Spot Prices,” at
25 Sanford Bernstein, “Bernstein Energy: 2010 U.S. Marginal Cost Curve – Oil Floor and Gaspiration?” May 27, 2011

26 IEA, World Energy Outlook 2011, at 128
27 DOE, EIA, Financial Performance of Major Energy Producers 2009, Table 11
28 DOE, EIA, “Distribution of Wells by Production Rate Bracket,” at
29 DOE, EIA, AEO 2012, Table 132
30 SAFE Analysis based on data from: IEA, Monthly Oil Market Report, December 2011, at 25
31 DOE, Office of Fossil Energy and National Energy Technology Laboratory, Modern Shale Gas Development in the United States: A Primer, at 13 (April 2009)
32 Id. at 14
33 See, e.g., Massachusetts Institute of Technology, The Future of Natural Gas, at 73-75 (2010) and Jesse Bogan, "The Father of Shale Gas: Interview with George Mitchell," Forbes, July 16, 2009

34 DOE, “Environmental Benefits of Advanced Oil and Gas Exploration and Production Technology,” Drilling and Completion
Technology Fact Sheet, at 7 and 8, (1999)
35 DOE, EIA, online statistics, “Natural Gas Spot and Futures Prices (NYMEX),” at
36 DOE, EIA, AER 2010, Table 4.2
37 Potential Gas Committee, “Potential Supply of Natural Gas in the United States,” December 31, 2010
38 DOE, Modern Shale Gas Development, at 56

BP Statistical Review 2012

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