In many ways, energy markets are in a state of constant change. Technology, regulation, innovation, economics and geopolitical developments are constantly shaping and reshaping our view of the market—in the present and the future. In fact, the same can be said with regard to a wide range of markets, but few if any play such a central role in broad macroeconomic growth and stability as do energy markets. As a result, national political leaders, corporate executives, academics and policy wonks pay close attention to developments in energy supply and demand, and substantial effort is devoted to strategic thinking about future pathways for providing affordable access to secure, sustainable energy.

Satisfying more than one of those three constraints—affordability, sustainability, and security—is an increasingly tenuous prospect. There are almost always tradeoffs, and as the definition of sustainability evolves to include a low carbon profile, those tradeoffs start to look especially challenging for the U.S., which currently derives about 85 percent of its energy consumption from fossil fuels. Coal, oil, and natural gas have the advantage of being scalable and energy-dense. But the burning of fossil fuels is one of the primary sources of anthropogenic greenhouse gas emissions, and the volatility in oil prices during 2007 and 2008 is increasingly being viewed as a chief contributor to the current recession. 

However, not all fossil fuels are created equal. And a growing chorus of analysts and observers has been pointing to natural gas as a potential game-changer in energy markets because of its ability to satisfy multiple constraints.

The Case for Oasis

First, consuming natural gas emits about 30 percent less CO2 than oil and 45 percent less than coal on an energy equivalent basis. And this doesn’t factor-in the platform in which the fuel is consumed. There is a world of difference between an inefficient internal combustion engine, a pulverized coal power plant, and a natural gas power plant. On average, in fact, the fleet of U.S. coal power plants achieves efficiency of just 25 percent. The current gas fleet achieves efficiency of roughly 40 percent, and it has been improving substantially as combined cycle gas plants are deployed in greater numbers. Combined cycle plants reach efficiency levels of 60 percent, which, when combined with the lower carbon profile of gas, results in an emissions reduction of about 75 percent per unit of electricity generated versus the coal fleet.

Second, natural gas is currently a largely domestic fuel, giving it the advantage of security. About 80 percent of the natural gas we use is produced in the United States. Of the remaining 20 percent, the vast majority is imported from Canada. Only a small fraction—about 1 percent—of U.S. gas supplies came from the global LNG market in 2008. This was just off the high in 2007 of about 3 percent. Domestic natural gas prices have historically tracked international oil prices, which raises concerns about price volatility. During the summer of 2008, U.S. gas prices spiked as high as $13 per million Btu at Henry Hub, whereas today they are trading between $3 and $4 as oil prices are also well off their all time highs.

Still, the price picture has been growing less clear for natural gas. Henry Hub spot prices trended well below European and Asian spot prices beginning in late 2007 and continuing through most of 2008 and to date in 2009. In part, this reflects the fact that there is relatively little fuel-switching between gas and oil in the U.S. But it also reflects our insulation against the often fierce competition for access to spot LNG cargoes. In Asian economies in particular, where LNG imports account for a more substantial share of gas consumption, high demand has lead to large price swings. Spot cargoes fetched prices as high as $20 per million Btu last year.

And finally, as anyone who has managed to sit through a T. Boone Pickens commercial knows, the U.S. may have an abundance of domestic natural gas.

Just a few years ago, most analysts had concluded that U.S. gas production was in an irrevocable free-fall. Gulf of Mexico production, which once provided nearly 30 percent of U.S. supplies, was in a state of rapid decline. By 2007, Gulf output provided just 15 percent of U.S. supplies, and new discoveries were in short supply. Onshore conventional reservoirs were also tapping out, and discussion of the need for a trans-continental pipeline from Alaska’s North Slope (perhaps 100 tcf) grew intense.

In 2008, energy markets, true to form, were completely reshaped. The change stemmed from advancements in the recovery of gas resources from unconventional reservoirs like shale gas, coal bed methane and tight gas. The estimates vary widely, but consensus seems to be settling on undiscovered technical recoverable reserves in excess of 1,000 trillion cubic feet (tcf). By way of comparison, BP reports that current U.S. proved gas reserves are just over 200 tcf.

One look at the graph below tells the story. The data is from EIA’s Annual Energy Outlook 2009.

With conventional production in rapid decline, shales, coal bed methane and tight gas are expected to keep lower-48 onshore production steady for the next two decades. Gulf of Mexico production continues to decline, now providing perhaps as little as 10 percent of total U.S. gas output. No doubt, expanded offshore development in the Atlantic and Pacific regions of the U.S. could boost overall offshore output, but expectations are growing that onshore unconventional production could provide the U.S. with a scalable, affordable, secure and clean source of energy for everything from electric power generation to home heating and industrial processes. Mr. Pickens and others have even suggested a role for natural gas in transportation.

Evidence of Mirage

At least two significant question marks exist regarding the future of unconventional gas. Only time and experience will ultimately provide answers to both. But two years into the great U.S. gas boom, some signs are pointing a less rosy outlook than many observers have suggested.

First, what makes shale, coal bed methane, and tight gas ‘unconventional’ is rock property. In essence, unconventional reservoirs are defined by reduced porosity vis-à-vis conventional reservoirs. In order to extract natural gas from these reservoirs, producers must over-pressurize 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. In addition, producers typically inject a proppant, or propping agent, into the well in order to keep the fractures from closing when pressure is reduced.

As unconventional gas production grows more common, some externalities of hydraulic fracturing may be coming into focus. As NPR reported this morning, concerns about the impact on water wells are mounting in some areas. There is a growing call for EPA to start regulating hydraulic fracturing at the national level under the Safe Drinking Water Act. Congress exempted the practice from federal regulation as part of EPAct 2005. You can read more on EPA’s fact-sheet here.

Of course, in addition to drinking water safety, the broader issue of freshwater access is likely to emerge as a challenge for the industry. Lifecycle water use for unconventional gas recovery is significantly higher than for conventional oil and gas recovery. Water treatment options certainly exist, but recycling is not always the norm. Here is a very good summary of the issue from Venture Engineering, a Pennsylvania consulting firm with clients involved in Marcellus shale development.

The second question mark for unconventional gas is likely to be cost of production—or perhaps more importantly, the price of natural gas required to support ongoing capital expenses in unconventional production. Natural gas production wells have steep decline rates. According to Chesapeake company reports, the first year decline rate for a typical Haynesville well is 81 percent; the second year rate is 34 percent and the third year rate is 22 percent. In other words, steady production requires steady capital investment in new wells. Factoring in these costs, along with taxes and operating costs, a recent Bernstein Research note estimated Haynesville operators needed a natural gas price of nearly $8 per million Btu to earn a 9 percent return on average capital employed (a modest return for a mid-sized operator in the natural gas business).

So is unconventional gas affordable and sustainable? The jury is still out. New technologies and increasing scale may ultimately solve the issues of fracturing and marginal production costs respectively. But if the historical nature of energy markets is any guide, we should be skeptical. There are no free lunches, and there are almost always tradeoffs.

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