News and Outreach: Christopher Knittel

Peter Dizikes | MIT News Office

The politics of climate change are often depicted as a simple battle, between environmentalists and particular industries, over government policy. That’s not wrong, but it’s only a rough sketch of the matter. Now a paper co-authored by MIT economist Christopher Knittel fills in some important details of the picture, revealing an essential mechanism that underlies the politics of the climate battle.

Specifically, as Knittel and his colleagues demonstrate, at least one climate policy enacted by Congress — on transportation fuels — contains a crucial asymmetry: It imposes modest costs on most people, but yields significant benefits for a smaller group. Thus, most people are politically indifferent to the legislation, even though it hurts them marginally, but a few fight hard to maintain it. The same principle may also apply to other types of climate legislation.

In 2005, Congress introduced the Renewable Fuel Standard (RFS), which mandates a minimum level of ethanol that must be used in gasoline every year, as a way of reducing greenhouse gas emissions. Ethanol can indeed reduce emissions, but as Knittel and other economists have argued, it is not the most efficient way of doing so: He estimates that mandating ethanol use is at least 2.5 times as costly, per ton of greenhouse gas reduction, as a cap-and-trade (CAT) policy, which would price the carbon emitted by all transportation fuels.

But corn-based ethanol production has strong political support in the Midwest, where much of the corn industry is based. In the new paper, Knittel and his colleagues quantify that effect in unique detail. They model what U.S. fuel consumption would likely look like through 2022 under both RFS and CAT scenarios, among others. Compared with a cap-and-trade system, the average American would lose $34 annually due to the RFS policy. But 5 percent of U.S. counties would gain more than $1,250 per capita, and one county gains $6,000 per capita.

Thus, most people are indifferent to the shortcomings of the RFS policy, but those who care tend to support it vigorously.

“Because of the skew in the distribution, you have the typical voter who doesn’t find it in their interest to fight against the inefficient policy, but the big winners are really going to fight for the inefficient policy,” says Knittel, adding: “If the typical voter is losing $30 a year, that’s not enough for me to write to my congressman. Whereas if you have someone on the upper end who is going to gain $6,000 — that’s enough for me to write my congressman.”

The political economy of energy

As the study shows, some folks do more than write to their representatives. Knittel and his colleagues found that members of the House of Representatives in districts that gain greatly from the RFS policy received an average of $33,000 more from organizations that opposed one particular piece of legislation — the 2009 Waxman-Markey bill, which would have created a CAT system, and likely would have reduced ethanol use. That bill passed in the House in July 2009, but was never taken up by the U.S. Senate.   

That difference in campaign contributions holds up strongly even when the researchers controlled for factors such as ideology, state, and overall emissions. That is, other things being equal, representatives of the specific areas benefitting most from RFS were given far more in donations from opponents of the Waxman-Markey bill than other congressmen. Representatives were also 39 percentage points more likely to oppose Waxman-Markey, other things being equal, if they were in districts that benefit strongly from the RFS policy.

“It’s a very robust finding,” Knittel says. “One interpretation is that these people or corporations who were donating money have a model very similar to ours, and are able to predict winners and losers under different policies. This is a very sophisticated group.”

On one level, the results confirmed something that was broadly understood: Areas with corn-based economies support ethanol. On another level, the study reveals the deep asymmetry that structures the politics of the issue: on one side, widespread indifference; on the other, narrow but deep support.

“It wasn’t until we got the results that we were able to think through the political economy of it,” Knittel says.

Tax the externality

The paper, “Some Inconvenient Truths About Climate Change Policy: The Distributional Impacts of Transportation Policies,” is forthcoming in the Review of Economics and Statistics.  

The paper’s co-authors are Knittel; Stephen P. Holland of the University of North Carolina at Greensboro; Jonathan E. Hughes of the University of Colorado; and Nathan C. Parker of the Institute of Transportation Studies at the University of California at Davis.

To conduct the study, the researchers used modeling by Parker that estimates where ethanol production will be located in coming years, as well as projecting the overall costs of various potential transportation fuel policies, were they to be implemented. The work also drew extensively on methods the other co-authors have used in evaluating both the potential impact of biofuels as a gasoline replacement and the relationship between policy options and politics.

On the general question of picking the optimal emissions–reduction policy, Knittel says, “The efficient policy is to tax the externality.” That is, to tax the additional cost or problem imposed on people — in this case, greenhouse gas emissions. That forces consumers to account for the costs of their own decisions, such as buying fuel-efficient vehicles.

Other scholars in the field regard the paper as a significant contribution to the study of energy politics. Mark Jacobsen, an associate professor of economics at the University of California at San Diego who has read the paper, says the “voting and donations models are both quite convincing.”

Jacobsen adds: “A very important contribution of this paper is in pointing out that we need to be alert to distribution [of energy resources] across states, making sure that it does not stand in the way of otherwise good policy.”

Knittel suggests the same kind of political asymmetry is probably at work in other aspects of climate politics. When it comes to coal-burning power plants, most people are only marginally affected by policy changes — but people living in coal-mining areas are deeply affected, and so have a much larger impact on the policy debate.

“We hope this paper sparks a literature that can do the same thing for other fuels,” Knittel says.

“Sound climate policy makes for good politics.” In a nutshell, that was the message conveyed by a high-ranking delegation of government, civil society and business representatives from British Columbia, who discussed experiences with their province’s carbon tax at an Earth Day Colloquium organized on April 13, 2015 by the MIT Energy Initiative (MITEI) and the MIT Center for Energy and Environmental Policy (CEEPR). More than 200 participants convened in the Walker Memorial’s spacious Morss Hall to hear first-hand how British Columbia was able to introduce a carbon price, and what effects it has had on the local economy and the environment. Comments by MIT faculty and a local State Senator underscored the economic merits of carbon pricing and its prospects as a policy option for Massachusetts.

MIT Chancellor Cynthia Barnhart opened the event with a brief welcome address, handing over to Parliamentary Secretary for Energy Literacy and the Environment of British Columbia, Mike Bernier. In his keynote address, Bernier described the history, design and early impacts of his province’s carbon tax, which he praised for shifting costs from desirable to undesirable activities, namely from employment and investment to pollution. Because the tax is revenue-neutral, he explained, it has helped limit carbon emissions and fuel use while reducing individual and corporate income taxes, effectively boosting the British Columbian economy. “What we’ve been doing in British Columbia has not gone unnoticed”, Bernier noted, pointing to growing interest in his province’s experience with carbon pricing from the United States and elsewhere.

Moderating the event, MITEI Director Robert Armstrong introduced the remaining panelists and invited each to address a series of detailed questions about the British Columbian experience. Merran Smith, Director of Clean Energy Canada, began by reflecting on the political context at the time the carbon tax was introduced in 2008. Widespread public demand for climate action, coupled with bold leadership from the province’s then-Premier Gordon Campbell, were among the factors Smith credited with successful passage of the necessary legislation.

Susanna Laaksonen-Craig, Head of the Climate Action Secretariat in the British Columbia Ministry of Environment, provided further detail on the technical design and implementation of the carbon tax. In her remarks, she reminded the audience that the tax had been lauded as a “textbook example of a carbon tax” by former MIT professor and statesman George P. Shultz.

Speaking on behalf of the private sector, Ross Beaty, Founder and Chairman of the Pan American Silver Corporation and Executive Chairman of Alterra Power Corporation, conceded that companies usually oppose new taxes. Still, so Beaty, corporate leaders increasingly acknowledge the need for climate action, and British Columbia’s local economy, in particular, has seen far-reaching impacts from climate change. Enlightened companies were thus ready to embrace political leadership when the carbon tax was introduced, quickly seeking ways to innovate and reduce compliance costs under the stable policy framework it offered.

Christopher Knittel, the William Barton Rogers Professor of Energy Economics at the MIT Sloan School of Management and Director of the MIT Center for Energy and Environmental Policy Research, commented on the carbon tax from an economist’s point of view. Despite almost universal agreement among economists on the merits of carbon pricing, he noted that few jurisdictions have decided to implement this policy option. On the contrary, the United States has recently seen a resurgence of rigid performance standards, which not only tend to impose higher cost than the externalities they avoid, but also have unintended consequence such as rebound effects. By contrast, he argued, a carbon price has positive spillover effects, such as revenue generation to reduce other taxes.

Drawing the discussion to a more local context, Massachusetts State Senator Michael Barrett of the 3rd Middlesex District answered questions on his own bill aimed at introducing a fee on carbon-based fuels in Massachusetts. All the revenue, he explained, would return to taxpayers by way of rebates, distributed in such a way that low-income households pay less for pollution than high-income households. Because of its revenue neutrality, moreover, the fee – so Barrett – does not fit the legal definition of a tax, allowing state officials who have pledged to oppose new taxes to support his bill.

An engaged discussion with the audience ensued, reflecting interest in carbon taxation as a policy option for Massachusetts and the U.S., and leading to detailed questions to the panel about policy design, impacts and ways to avoid hardship for different segments of society. Secretary Bernier’s parting advice to Senator Barrett and the largely Massachusetts-based audience was to “take the politics out of carbon pricing.” But once introduced, he added, it will limit pollution without harming the economy.

A video of the full event can be viewed here.

Francesca McCaffrey | MIT Energy Initiative

Leaders from the energy industry, government, and the scientific community will gather to discuss the world’s most pressing energy challenges at the annual MIT Energy Club Conference, to be held February 27-28 on the MIT campus. Developed and organized entirely by MIT students, the conference is this year celebrating its 10th anniversary. 

Christopher Knittel, MIT’s William Barton Rogers Professor of Energy and a Professor of Applied Economics at the Sloan School, gave MITEI a preview of the panel he’ll be moderating on the opening day of the upcoming MIT Energy Conference.  Called “Unconventional resources: successes and challenges,” Knittel will be focusing on the future of shale gas development in the U.S. and globally.  

Here, Knittel shares some brief advance insight about the future of shale gas development.

Q: Does Shale Gas really provide the largest share of US Natural Gas Production?

Knittel:  According to the EIA, 40% of US natural gas production, in 2012, came from shale resources. Over 60% of our natural gas comes from shale basins and what is known as tight reservoirs, which typically uses the same drilling techniques as shale natural gas.

Q: Why has shale gas experienced such a boom in the US?

Knittel: The short answer is that there has been a tremendous amount of technological progress in the ability to extract natural gas (and oil) trapped in shale and tight formations. Geologists have known for years that hydrocarbons were trapped in shale basins, but not until the development of horizontal drilling, along with hydraulic fracturing techniques have energy companies been able to economically recover these hydrocarbons. 

Q: In a recent MIT News interview, you discussed how a central tenet of the EPA’s forthcoming Clean Power Plan involves shifting states from coal to natural gas. What role do you see federal regulation playing in the future of shale gas in the US?

Knittel: There are a number of important roles for federal regulation. First, if left alone the market will not lead to enough shifting away from coal to natural gas. This is because a number of "externalities"—social costs associated with burning fossil fuels that are unpaid by consumers and firms in these markets—that exist in fossil fuel markets. This is the role that policy makers must take in these markets. Ideally, we would have a set of pollution taxes, not just a carbon tax, but also taxes on particulate matter, mercury, etc. Because these types of policies tend to be politically infeasible, politics drive us to policies like the Clean Power Plan. 

Q: Will the advent of shale gas have an impact on the development of alternative energy sources?

Knittel: Anything that lowers the prices of fossil fuels will slow down the development of alternative energy sources. This is true not just for natural gas, but also for oil. Lower natural gas prices make solar and wind technologies more expensive on a relative basis. Similarly, the drop in oil prices will make it more difficult for alternative fuel vehicles to compete in the market place. In the more long term, these lower fossil fuel prices will reduce R&D into these alternative technologies. 

Q: What are some of the key political and environmental issues that shale gas producers face?

Knittel: In the US - Any drilling activity has environmental risks. Hydraulic fracturing is no different. In addition, the added step of pumping millions of gallons of water down into the well creates a new set of environmental risks. Furthermore, natural gas leaks, known as fugitive emissions, are a much more potent greenhouse gas compared to carbon dioxide. It is important for the Federal EPA and state-level EPA to assure that best business practices are used in drilling for natural gas and that these practices, as well as fugitive emissions, are adequately monitored. 

Q: Do you expect shale gas to truly be a “bridge” fuel, used only as a temporary solution while renewable energy technologies improve, or do you think that shale gas will hold a lasting spot in our energy ecosystem?

Knittel: This will depend on policy. Policy makers must create a set of incentives that will move markets away from natural gas and into renewable technologies. Absent these, natural gas may push coal out of the market and remain the main fuel source in electricity markets. 

Professor Knittel will continue the discussion on shale gas development with panelists Paul Sheng, Director at McKinsey & Co, Jan Erik Johansson, Principal Consultant at TCS, and Helen Currie, Senior Economist at ConocoPhillips, on Friday, February 27 at 2pm. Afternoon lectures on Friday will be held at the Marriott.

To attend Professor Knittel’s panel, or to view the rest of the conference agenda and reserve your ticket, visit the MIT Energy Club Conference website by clicking here.

By Peter Dizikes, MIT News Office

With cap-and-trade legislation on greenhouse-gas emissions having stalled in Congress in 2010, the Obama administration has taken a different approach to climate policy: It has used the mandate of the Environmental Protection Agency (EPA) to propose a policy limiting power-plant emissions, since electricity consumption produces about 40 percent of U.S. greenhouse gases. (The administration also announced a bilateral agreement with China this week, which sets overall emissions-reductions targets.)

The EPA’s initial proposal is now under public review, before the agency issues a final rule in 2015. Christopher Knittel, the William Barton Rogers Professor of Energy Economics at the MIT Sloan School of Management, is one of 13 economists who co-authored an article about the policy in the journal Science this week. While the plan offers potential benefits, the economists assert, some of its details might limit the policy’s effectiveness. MIT News talked with Knittel about the issue.

Q. How is the EPA’s policy for power plants intended to work?

A. The Clean Power Plan calls for different emissions reductions depending on the state. This state-specific formula has four “buckets:” efficiency increases at the power plant; shifting from coal to natural gas; increases in generation from low-carbon renewables such as wind; and increases in energy efficiency within the state. So they applied these four things and asked what changes were “adequately demonstrated” to generate state-specific required reductions.

Q. The Science piece emphasizes that the EPA’s plan uses a ratio-based means of limiting emissions: the amount of greenhouse gases divided by the amount of electricity consumed. So a state could add renewable energy, lower its ratio, but not reduce total emissions. What are the advantages and disadvantages of doing this?

A. The targets are an emissions rate: tons of CO₂ [emitted] per megawatt-hour of electricity generation. Then it’s really up to the states to determine how they’re going to achieve the reductions in this rate. So one strategy is to increase total electricity generated. This compliance strategy, unfortunately, is what makes rate-based regulation economically inefficient.

The states also have the option to convert that rate-based ratio target into what the EPA is calling a mass-based target, total tons of greenhouse-gas emissions. This would effectively imply the state is going to adopt a cap-and-trade program to reach its requirements.

In current work, we — scholars Jim Bushnell, Stephen Holland, Jonathan Hughes, and I — are investigating the incentives states have to adopt to convert their rate-based mandate into a mass-based mandate. Unfortunately, we are finding that states rarely want to [use a mass-based target], which is a pity, because the mass-based regulation is the most efficient regulation, from an economist’s perspective. Holland, Hughes, and I have done work in the transportation sector that shows that when you do things on a rate base, as opposed to a mass base, it is at least three times more expensive, and more costly to society — often more than five times more costly.

Q. Why did the EPA approach it this way?

A. I can only speculate as to why the EPA chose to define the regulation as a rate instead of total greenhouse gas emissions. Regulating a rate is often cheaper from the firm’s perspective, even though it is economically inefficient. Why the EPA chose to define things at the state level is more clear: The Clean Air Act … is written in such a way to leave it up to the states.

But if everyone’s doing their own rate- or mass-based standard, then you don’t take advantage of potentially a large efficiency benefit from trading compliance across states. That is, it might be cheaper for one state to increase its reductions, allowing another state to abate less.

The most ideal regulatory model is that everyone’s under one giant mass-based standard, one big cap-and-trade market. Even if every state’s doing its own cap-and-trade market, that’s unlikely to lead to the efficient outcome. It might be cheaper for California or Montana or Oregon to reduce their greenhouse-gas emissions, but as soon as they meet their standard, they’re going to stop.

Q. The Science article says that certifying efficiency-based gains is a crucial factor. Could you explain this?

A. Given how the regulation treats efficiency, it really puts in the forefront the importance of understanding the real-world reduction in energy consumption coming from efficiency investments. Let’s say I reduce electricity consumption by 100 megawatt-hours through increasing efficiency in buildings. Within the [EPA’s] policy, that reduction is treated as if I’m generating 100 megawatt-hours from a zero-carbon technology. So that increases the denominator in the ratio [of greenhouse gases produced to electricity consumed]. One concern, though, is that often the actual returns from energy-efficiency investments aren’t as large as the predicted returns. And that can be because of rebound [the phenomenon by which better energy efficiency allows people to consume more of it], which is a hot topic now, or other behavioral changes.

Behavioral changes can make those efficiency gains larger or smaller, so getting the right number is very important. I’ve heard stories of people who get all-new windows, and the old windows used to let in air, but now they think the house is stuffy, so they keep their windows cracked. We should be doing more field experiments, more randomized controlled trials, to measure the actual returns to energy efficiency.

Another related concern is that it might be left up to the states to tell the EPA what the reduction was from these energy-efficiency investments. And the state might not have any incentive at all to measure them correctly. So there has to be an increase in oversight, and it likely has to be federal oversight.

Q. While you clearly have concerns about the efficacy of the policy, isn’t this one measure among others, intended to lessen the magnitude of the climate crisis?

A. For many of us, the potential real benefit from the clean power rule is that it will change the dynamic in Paris in the [forthcoming international climate] negotiations. For a long time the U.S. could say it was doing some improvements in transportation, but they really weren’t doing anything in electricity, for climate change. My view is there are a lot of countries out there that aren’t going to do anything unless the U.S. does. This might bring some of those countries on board.

Peter Dizikes, MIT News Office

If you have stopped at a gas station recently, there is a good chance your auto has consumed fuel with ethanol blended into it. Yet the price of gasoline is not substantially affected by the volume of its ethanol content, according to a paper co-authored by an MIT economist. The study seeks to rebut the claim, broadly aired over the past couple of years, that widespread use of ethanol has reduced the wholesale cost of gasoline by $0.89 to $1.09 per gallon.

Whatever the benefits or drawbacks of ethanol, MIT’s Christopher Knittel says, price issues are not among them right now.

“The point of our paper is not to say that ethanol doesn’t have a place in the marketplace, but it’s more that the facts should drive this discussion,” says Knittel, the William Barton Rogers Professor of Energy and a professor of applied economics at the MIT Sloan School of Management.

The 10 percent solution?

The vast majority of ethanol sold in the United States is made from corn. It now constitutes 10 percent of U.S. gasoline, up from 3 percent in 2003.

It is another matter, however, whether that increase in ethanol content produces serious savings at the pump, as some claim. Knittel and his co-author, economist Aaron Smith of the University of California at Davis, contest such an assertion in their paper, which is forthcoming inThe Energy Journal, a peer-reviewed publication in the field.

The claim that ethanol lowers prices derives from a previous study on the issue, which Knittel and Smith believe is problematic. That prior work involves what energy economists call the “crack ratio,” which is effectively the price of gasoline divided by the price of oil.

The crack ratio is something energy analysts can use to understand the relative value of gasoline compared to oil: The higher the crack ratio, the more expensive gasoline is in relative terms. If ethanol were a notably cheap component of gasoline production, its increasing presence in the fuel mix might reveal itself in the form of a decreasing crack ratio.

So while gasoline is made primarily from oil, there are other elements that figure into the cost of refining gasoline. Thus if oil prices double, Knittel points out, gasoline prices do not necessarily double. But in general, when oil prices — as the denominator of this fraction — go up, the crack ratio itself falls.

The previous work evaluated time periods when oil prices rose, and the percentage of ethanol in gasoline also rose.

But Knittel and Smith assert that the increased proportion of ethanol in gasoline merely correlated with the declining crack ratio, and did not contribute to it in any causal sense. Instead, they think that changing oil prices drove the change in the crack ratio, and that when those prices are accounted for, the apparent effect of ethanol “simply goes away,” as Knittel says.

To further illustrate that the previous study was touting a correlation, not a causal relationship, Knittel and Smith conducted what are known in economics literature as “antitests” of that study’s model. By inserting unconnected dependent variables into the model, they found that the model also produced a strong correlation between ethanol content in gasoline and, for instance, U.S. employment figures — although the latter are clearly unrelated to the composition of gasoline.

The previous work also claimed that if ethanol production came to an immediate halt, gasoline prices would rise by 41 to 92 percent. But Knittel does not think that estimate would bear out in such a scenario.

“In the very short run, if ethanol vanished tomorrow, we would be scrambling to find fuel to cover that for a week, or less than a month,” Knittel says. “But certainly within a month, increases in imports would relax or reduce that price impact.”

Informing the debate

The differing assessments of ethanol’s impact have garnered notice among economists and energy policy analysts. Scott Irwin, an economist at the University of Illinois at Urbana-Champaign who has read the paper, calls it a “convincing and compelling” rebuttal to the idea that expanding ethanol content in gasoline drastically lowers prices.

“The paper dispensed once and for all with that conclusion,” Irwin says. Still, he adds, there remains an open debate about the marginal effects of ethanol content in gasoline, and more empirical work on the subject would be useful.

“A case can be made that it can be a positive few cents,” Irwin says, adding that “reasonable arguments can be made on either side of zero” regarding ethanol’s price impact. In either case, Irwin says, his view is that the effect is currently a small one.

Knittel has posted, on his MIT Sloan web page, a multipart exchange between himself and Dermot Hayes, an Iowa State University economist who is a co-author of the prior work. After an initial finding that ethanol reduced gasoline prices by $0.25 per gallon, Hayes and a co-author produced follow-up studies, examining about a decade after 2000, and arrived at the figures of $0.89 and $1.09 per gallon, which gained wider public traction. 

Knittel acknowledges that policy decisions about gasoline production are driven by a complex series of political factors, and says his study is not intended to directly convey any policy preferences on his part. Still, he suggests that even ethanol backers in policy debates have reason to keep examining its value.

“Making claims about the benefits of ethanol that are overblown is only going to set up policymakers for disappointment,” Knittel says.

By Chris Knittel and John Parsons

Professor Robert Pindyck has a new working paper (CEEPR-WP-13-XXX) that has attracted a good share of attention since it steps into the highly charged debate on the reliability of research related to climate change. But in this case, the focus is on what we learn from one class of economic model, the so-called integrated assessment models (IAM). These models have been used to arrive at a “social cost of carbon” (SCC). For example, in 2010 a U.S. Government Interagency Working Group recommended a $21/t CO2 as the social cost of carbon to be employed by US agencies in conducting cost-benefit analyses of proposed rules and regulations. This figure was recently updated to $33/t. Professor Pindyck’s paper calls attention to the wide, wide range of uncertainty surrounding key inputs to IAM models, and to the paucity of reliable empirical data for narrowing the reasonable range of input choices. The paper then suggests profitable directions for reorienting future research and analysis.
 
Reflecting the highly charged nature of the U.S. political debate on climate change, Professor Pindyck’s paper has been seized on by opponents of action. In particular, certain blogs have cited his paper in support of their campaign against any action. Here is one example—link.
 
Interestingly, Professor Pindyck is an advocate of action on climate change, such as leveling a carbon tax. So his own view of the implications of his research are quite different than that of those who oppose any action. This post at the blog of the Natural Resources Defense Council includes more extensive comments by Professor Pindyck on the debate—link.
 
An alternative approach is to think about Professor Pindyck’s review as a guide for future research on the costs of climate change which is better focused to address the important uncertainties in a way that can better contribute to public discussion and analysis. CEEPR researcher Dr. John Parsons emphasizes this point in his blog post about Pindyck’s paper—link.

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By: Elizabeth Rowe

June 25, 2013

We all know that air conditioning eats up an enormous amount of energy. We also know that installing ceiling fans would allow us to use the air conditioner a lot less. And we all know the savings over time would pay for the ceiling fan. So why aren’t there more people buying ceiling fans? 

That question, and many more like it, are at the center of a research project launched by the Haas School of Business at the University of California at Berkeley and MIT’s Center for Energy & Environmental Policy Research (CEEPR). The initiative, known as the E2e Project, will work to understand cost-effective ways to reduce energy use and the obstacles that sometimes get in the way.

Drawing on the skills of both engineers and economists from MIT and Berkeley, the project derives its name from its mission: finding a smart way to go from using a larger amount of energy, or “E,” to a smaller amount of energy, or “e.”

Much of the impetus for this project comes from the McKinsey Curve, a cost curve that asserts that there are “negative cost” energy efficiency investments that essentially pay for themselves. “There’s a fair bit of evidence out there that suggests there’s a lot of low-hanging fruit in terms of energy savings, but much of that evidence is based on engineering models,” says E2e co-director Christopher Knittel, a professor at MIT’s Sloan School of Management and CEEPR co-director. “Much of the engineering research ignores behavioral changes that might come in response to those investments, and those behavioral changes can manifest themselves in many ways.”

For example, Knittel says, households might turn their thermostat down in the summer or up in the winter if heating and cooling homes become more energy-efficient. Such behaviors, which reduce the benefits of energy efficiency, aren’t accounted for in engineering models, he says.

One study undertaken by E2e will determine how much energy the federal Weatherization Assistance Program saves. The project examines low-income households in Michigan that received free efficiency upgrades, such as insulation and weatherproofing, and audits their energy use over time to find out why actual efficiency gains are less than expected. Final results are expected later this year.

According to Knittel, E2e has three main objectives. One is to determine whether these “negative-cost” investments truly exist. The second is to understand which of these investments has the greatest return on investment. And third, E2e will try to understand why consumers and companies aren’t making these investments if they truly have a negative cost.

E2e’s co-director, Professor Catherine Wolfram, an associate professor at Haas and co-director of the Energy Institute, says E2e has a broader goal, too: “At the heart, I think we’re interested in finding the lowest-cost way to mitigate climate change.” She adds, “In the short term we hope to deliver to policymakers some really good information about where human behavior might influence energy efficiency technology and policy.”

By Charles C. Mann

New technology and a little-known energy source suggest that fossil fuels may not be finite. This would be a miracle—and a nightmare.

As the great research ship Chikyu left Shimizu in January to mine the explosive ice beneath the Philippine Sea, chances are good that not one of the scientists aboard realized they might be closing the door on Winston Churchill’s world. Their lack of knowledge is unsurprising; beyond the ranks of petroleum-industry historians, Churchill’s outsize role in the history of energy is insufficiently appreciated.

Winston Leonard Spencer Churchill was appointed First Lord of the Admiralty in 1911. With characteristic vigor and verve, he set about modernizing the Royal Navy, jewel of the empire. The revamped fleet, he proclaimed, should be fueled with oil, rather than coal—a decision that continues to reverberate in the present. Burning a pound of fuel oil produces about twice as much energy as burning a pound of coal. Because of this greater energy density, oil could push ships faster and farther than coal could.

Churchill’s proposal led to emphatic dispute. The United Kingdom had lots of coal but next to no oil. At the time, the United States produced almost two-thirds of the world’s petroleum; Russia produced another fifth. Both were allies of Great Britain. Nonetheless, Whitehall was uneasy about the prospect of the Navy’s falling under the thumb of foreign entities, even if friendly. The solution, Churchill told Parliament in 1913, was for Britons to become “the owners, or at any rate, the controllers at the source of at least a proportion of the supply of natural oil which we require.” Spurred by the Admiralty, the U.K. soon bought 51 percent of what is now British Petroleum, which had rights to oil “at the source”: Iran (then known as Persia). The concessions’ terms were so unpopular in Iran that they helped spark a revolution. London worked to suppress it. Then, to prevent further disruptions, Britain enmeshed itself ever more deeply in the Middle East, working to install new shahs in Iran and carve Iraq out of the collapsing Ottoman Empire.

Churchill fired the starting gun, but all of the Western powers joined the race to control Middle Eastern oil. Britain clawed past France, Germany, and the Netherlands, only to be overtaken by the United States, which secured oil concessions in Turkey, Iraq, Bahrain, Kuwait, and Saudi Arabia. The struggle created a long-lasting intercontinental snarl of need and resentment. Even as oil-consuming nations intervened in the affairs of oil-producing nations, they seethed at their powerlessness; oil producers exacted huge sums from oil consumers but chafed at having to submit to them. Decades of turmoil—oil shocks in 1973 and 1979, failed programs for “energy independence,” two wars in Iraq—have left unchanged this fundamental, Churchillian dynamic, a toxic mash of anger and dependence that often seems as basic to global relations as the rotation of the sun.

All of this was called into question by the voyage of the Chikyu (“Earth”), a $540 million Japanese deep-sea drilling vessel that looks like a billionaire’s yacht with a 30-story oil derrick screwed into its back. The Chikyu, a floating barrage of superlatives, is the biggest, glitziest, most sophisticated research vessel ever constructed, and surely the only one with a landing pad for a 30-person helicopter. The central derrick houses an enormous floating drill with a six-mile “string” that has let the Chikyu delve deeper beneath the ocean floor than any other ship.

The Chikyu, which first set out in 2005, was initially intended to probe earthquake-generating zones in the planet’s mantle, a subject of obvious interest to seismically unstable Japan. Its present undertaking was, if possible, of even greater importance: trying to develop an energy source that could free not just Japan but much of the world from the dependence on Middle Eastern oil that has bedeviled politicians since Churchill’s day.

In the 1970s, geologists discovered crystalline natural gas—methane hydrate, in the jargon—beneath the seafloor. Stored mostly in broad, shallow layers on continental margins, methane hydrate exists in immense quantities; by some estimates, it is twice as abundant as all other fossil fuels combined. Despite its plenitude, gas hydrate was long subject to petroleum-industry skepticism. These deposits—water molecules laced into frigid cages that trap “guest molecules” of natural gas—are strikingly unlike conventional energy reserves. Ice you can set on fire! Who could take it seriously? But as petroleum prices soared, undersea-drilling technology improved, and geological surveys accumulated, interest rose around the world. The U.S. Department of Energy has been funding a methane-hydrate research program since 1982.

Nowhere has the interest been more serious than Japan. Unlike Britain and the United States, the Japanese failed to become “the owners, or at any rate, the controllers” of any significant amount of oil. (Not that Tokyo didn’t try: it bombed Pearl Harbor mainly to prevent the U.S. from blocking its attempted conquest of the oil-rich Dutch East Indies.) Today, Churchill’s nightmare has come true for Japan: it is a military and industrial power almost wholly dependent on foreign energy. It is the world’s third-biggest net importer of crude oil, the second-biggest importer of coal, and the biggest importer of liquefied natural gas. Not once has a Japanese politician expressed happiness at this state of affairs.

Japan’s methane-hydrate program began in 1995. Its scientists quickly focused on the Nankai Trough, about 200 miles southwest of Tokyo, an undersea earthquake zone where two pieces of the Earth’s crust jostle each other. Step by step, year by year, a state-owned enterprise now called the Japan Oil, Gas, and Metals National Corporation (JOGMEC) dug test wells, made measurements, and obtained samples of the hydrate deposits: 130-foot layers of sand and silt, loosely held together by methane-rich ice. The work was careful, slow, orderly, painstakingly analytical—the kind of process that seems intended to snuff out excited newspaper headlines. But it progressed with the same remorselessness that in the 1960s and ’70s had transformed offshore oil wells from Waterworld-style exoticisms to mainstays of the world economy.

In January, 18 years after the Japanese program began, the Chikyu left the Port of Shimizu, midway up the main island’s eastern coastline, to begin a “production” test—an attempt to harvest usefully large volumes of gas, rather than laboratory samples. Many questions remained to be answered, the project director, Koji Yamamoto, told me before the launch. JOGMEC hadn’t figured out the best way to mine hydrate, or how to ship the resultant natural gas to shore. Costs needed to be brought down. “It will not be ready for 10 years,” Yamamoto said. “But I believe it will be ready.” What would happen then, he allowed, would be “interesting.”

Already the petroleum industry has been convulsed by hydraulic fracturing, or “fracking”—a technique for shooting water mixed with sand and chemicals into rock, splitting it open, and releasing previously inaccessible oil, referred to as “tight oil.” Still more important, fracking releases natural gas, which, when yielded from shale, is known as shale gas. (Petroleum is a grab-bag term for all nonsolid hydrocarbon resources—oil of various types, natural gas, propane, oil precursors, and so on—that companies draw from beneath the Earth’s surface. The stuff that catches fire around stove burners is known by a more precise term, natural gas, referring to methane, a colorless, odorless gas that has the same chemical makeup no matter what the source—ordinary petroleum wells, shale beds, or methane hydrate.) Fracking has been attacked as an environmental menace to underground water supplies, and may eventually be greatly restricted. But it has also unleashed so much petroleum in North America that the International Energy Agency, a Paris-based consortium of energy-consuming nations, predicted in November that by 2035, the United States will become “all but self-sufficient in net terms.” If the Chikyu researchers are successful, methane hydrate could have similar effects in Japan. And not just in Japan: China, India, Korea, Taiwan, and Norway are looking to unlock these crystal cages, as are Canada and the United States.

Not everyone thinks JOGMEC will succeed. But methane hydrate is being developed in much the same methodical way that shale gas was developed before it, except by a bigger, more international group of researchers. Shale gas, too, was subject to skepticism wide and loud. The egg on naysayers’ faces suggests that it would be foolish to ignore the prospects for methane hydrate—and more foolish still not to consider the potential consequences.

If methane hydrate allows much of the world to switch from oil to gas, the conversion would undermine governments that depend on oil revenues, especially petro-autocracies like Russia, Iran, Venezuela, Iraq, Kuwait, and Saudi Arabia. Unless oil states are exceptionally well run, a gush of petroleum revenues can actually weaken their economies by crowding out other business. Worse, most oil nations are so corrupt that social scientists argue over whether there is an inherent bond—a “resource curse”—between big petroleum deposits and political malfeasance. It seems safe to say that few Americans would be upset if a plunge in demand eliminated these countries’ hold over the U.S. economy. But those same people might not relish the global instability—a belt of financial and political turmoil from Venezuela to Turkmenistan—that their collapse could well unleash.

On a broader level still, cheap, plentiful natural gas throws a wrench into efforts to combat climate change. Avoiding the worst effects of climate change, scientists increasingly believe, will require “a complete phase-out of carbon emissions … over 50 years,” in the words of one widely touted scientific estimate that appeared in January. A big, necessary step toward that goal is moving away from coal, still the second-most-important energy source worldwide. Natural gas burns so much cleaner than coal that converting power plants from coal to gas—a switch promoted by the deluge of gas from fracking—has already reduced U.S. greenhouse-gas emissions to their lowest levels since Newt Gingrich’s heyday.

Yet natural gas isn’t that clean; burning it produces carbon dioxide. Researchers view it as a temporary “bridge fuel,” something that can power nations while they make the transition away from oil and coal. But if societies do not take advantage of that bridge to enact anti-carbon policies, says Michael Levi, the director of the Program on Energy Security and Climate Change at the Council on Foreign Relations, natural gas could be “a bridge from the coal-fired past to the coal-fired future.”

“Methane hydrate could be a new energy revolution,” Christopher Knittel, a professor of energy economics at the Massachusetts Institute of Technology, told me. “It could help the world while we reduce greenhouse gases. Or it could undermine the economic rationale for investing in renewable, carbon-free energy around the world”—just as abundant shale gas from fracking has already begun to undermine it in the United States. “The one path is a boon. The other—I’ve used words like catastrophe.” He paused; I thought I detected a sigh. “I wouldn’t bet on us making the right decisions.”

A few years after I graduated from college, I drove with a friend to Southern California, a place I’d never been. I saw a little of Los Angeles, then went north and spent a few days bumbling through the San Joaquin Valley. Going about Bakersfield one night, I got hopelessly lost and ended up at a chain-link fence. Behind the fence were thousands of oil pumps, nodding up and down like so many giant plastic drinking birds. Enshrouding the pumps was a spiderweb of pipes and electrical wires, vast and complex beyond reason, lights and machinery stretching out across the desert farther than I could see. A giant, hypermodern petroleum operation barely 100 miles from Los Angeles! I couldn’t believe it. As I stood gawping, a policeman drove by. I asked him when this complex had sprung up. He looked at me like I was an idiot. “They’ve been drilling here since 1899,” he said.

I was standing by the Kern River oil field, one of the best-known petroleum deposits in the United States. Because I had somehow missed geology in school, I had been left with the vague idea that oil is found in big subterranean pools, like the underground lake where Voldemort conceals part of his soul in the Harry Potter series. In fact, petroleum is usually contained in solid sandstone or limestone strata, which are riddled, spongelike, with minute pores. Or it can occur in thin sheets between layers of shale. Looking at the nodding wells, I had the notion that they were drawing a uniform substance from the ground, a black liquid like the inky water in Voldemort’s lake. Instead, petroleum occurs as a crazy stew of different compounds: oil of various grades mixed with methane, ethane, propane, butane, and other hydrocarbons. Squashed into stone hundreds or thousands of feet underground, this jumble of liquid and gas is usually under great pressure. Layers, or “caps,” of impermeable rock prevent it from seeping to the surface. When drilling bores through the caps, petroleum shoots up in orthodox gusher fashion.

For a long time, companies collected oil and discarded the methane that burbled up with it, often by burning the gas in a cinematic flare atop special derricks, or even simply dumping it into the atmosphere. People did use natural gas for energy—gaslights have existed since the days of Jane Austen—but transporting it was costly. Unlike liquid oil, which could be poured into containers and carried on a railroad network that had already been built and paid for by somebody else, gaseous methane had to be pumped through sealed tubes to its destination, which required energy firms and utilities to lay thousands upon thousands of miles of pipeline. Not until the Second World War and war-production advances in welding did this effort gather speed. (Methane can be cooled into a liquid and transported in pressurized tanks that are loaded and unloaded in special facilities, but this is also expensive.) Oil from wells in Texas is readily dispatched via tanker to Europe or Asia, but even today, natural gas from the same wells is often effectively limited to use in the United States.

From the beginning, it was evident that the Kern River field was rich with oil, millions upon millions of barrels. (A barrel, the unit of oil measurement, is 42 gallons; depending on the grade, a ton of oil is six to eight barrels.) Wildcatters poured into the area, throwing up derricks, boring wells, and pulling out what they could. In 1949, after 50 years of drilling, analysts estimated that just 47 million barrels remained in reserves—a rounding error in the oil business. Kern River, it seemed, was nearly played out. Instead, oil companies removed 945 million barrels in the next 40 years. In 1989, analysts again estimated Kern reserves: 697 million barrels. By 2009, Kern had produced more than 1.3 billion additional barrels, and reserves were estimated to be almost 600 million barrels.

What does it mean when oil companies say they have so many million barrels in reserves? How much energy is in the ground? When will we begin running out? As the history of the Kern River field suggests, these questions are not easy to answer. Indeed, Ph.D.‑toting experts have bombarded Americans for half a century with totally contradictory responses. On one side, pessimists claim that the planet is slowly running out of petroleum. “Turn down the thermostat!” they cry. “Stuff insulation in your walls!” “Buy a hybrid!” “Conserve!” From the other side come equally loud shouts insisting that there are vast, untapped petroleum deposits in Alaska and Alberta and off the coast of Virginia, that geysers of natural gas exist in the shale beds of Pennsylvania and North Dakota, and that huge oil patches await extraction in the deep ocean. “Drill, baby, drill!” “The end of oil!” Al Gore or Sarah Palin, Cassandra or Pollyanna, which side is right? The back-and-forth would be comical if the stakes didn’t involve the fate of human civilization.

When gasoline supplies drop, TV news reporters like to wring their hands at the drivers mobbing the corner Exxon. But the motorists’ panic reflects a basic truth: economic growth and energy use have marched in lockstep for generations. Between 1900 and 2000, global energy consumption rose roughly 17-fold, the University of Manitoba environmental scientist Vaclav Smil has calculated, while economic output rose 16-fold—“as close a link as one may find in the unruly realm of economic affairs.” Petroleum has wreaked all kinds of social and environmental havoc, but a steady supply of oil and gas remains just as central to the world’s economic well-being as it was in Churchill’s day. According to the National Bureau of Economic Research, the United States has experienced 11 recessions since the end of the Second World War. All but one were associated with spikes in energy costs—specifically, abrupt jumps in the price of oil.

Understanding this dependence, the oil industry was shaken by a speech in 1956 by M. King Hubbert, a prominent geophysicist at Shell Oil. When a company moves into a field, it grabs the easy, cheap oil first. Tapping the rest gets progressively more difficult and expensive. Eventually, Hubbert observed, conditions get so tough that production levels off—it peaks. After the peak, decline is unstoppable, the fall as ineluctable as the rise. Hubbert used his theory to predict that the crude-oil yield in the continental United States would flatten between 1965 and 1970 (he didn’t include Alaska and most offshore oil areas). Coming at a time when estimates by the U.S. Geological Survey and the petroleum industry were constantly rising, this claim was derided; indeed, Hubbert claimed that just before giving his speech, a Shell official tried to get him to back off.

Hubbert, not the least self-confident of men, stood his ground, even after he left Shell and in 1964 went to work for the Geological Survey. Unluckily for him, his most prominent critic was now his boss: Vincent E. McKelvey, a long-serving geologist at USGS who would become its director in 1971. As the University of Iowa historian Tyler Priest has documented, McKelvey’s USGS issued a stream of optimistic assessments about the country’s oil future. So did its counterparts in the oil industry. Meanwhile, Hubbert cranked out papers taking the opposite stance, none of them published by the Geological Survey. Inevitably, the dispute grew personal. Three days after McKelvey became the USGS director, he took away Hubbert’s secretary, a harsh measure in the days before e‑mail. According to Priest, Hubbert ended up having to write all his correspondence in longhand; his wife typed his reports at home. Hubbert struck back by helping to kill McKelvey’s nominations to the National Academy of Sciences and the American Academy of Arts and Sciences.

In a blow to McKelvey, Hubbert’s prediction proved to be correct. As domestic crude-oil production peaked and then fell, former Interior Secretary Stewart Udall mocked the sunny claims from the Geological Survey as “an enormous energy balloon of inflated promises and boundless optimism [that] had long since lost touch with any mainland reality.” If Udall were reappointed Interior secretary, he said, “the first thing I would do would be to kick McKelvey out.” In 1977, newly elected President Jimmy Carter, a Hubbertian, forced McKelvey to resign—the first such ouster, Priest notes, “in the Survey’s 98-year history.”

Hubbert’s message of scarcity resonated at a time when the United States was haunted by the specter of Middle Eastern oil blockades. In a nationwide address, President Carter proclaimed that the planet’s proven oil reserves could be consumed “by the end of the next decade.” To forestall the disaster, he fired a volley of energy-efficiency measures: gas-mileage regulation, home-appliance energy standards, conservation tax credits, subsidies for insulation and weatherization. Congress enacted incentives and restrictions to induce industry to switch from supposedly scarce oil and natural gas to coal, which the U.S. has in abundance.

Alas, petroleum firms found so much crude oil in the 1980s that by the 1990s, prices (after adjusting for inflation) had fallen to one-fifth of what they had been during the Carter administration. Estimates of reserves rose and rose again. Energy conservation faltered; oil and gas were too cheap to be worth saving.

The argument has nonetheless continued, pessimists and optimists hammering at each other like Montagues and Capulets. Most of the Hubbertians are physical scientists; most of the McKelveyans, social scientists. Central to the conflict is their differing concepts of a reserve. Recall, as an example, the Kern River field. Its thousands of nodding pumps are siphoning up oil so thick and heavy that it almost doesn’t float on water. Although drillers knew from the first that the field was abundant, they could barely wrest any of this goop from the ground, a factor reflected in the first estimate of the reserve (47 million barrels of recoverable oil). Between that estimate and the second (697 million barrels), engineers developed a precursor to fracking: shooting hot steam down Kern River wells to thin the oil and force it out of the stone. At first, the process was hideously inefficient: heating the water to produce the steam required as much as 40 percent of the oil that came out of the wells. Burning unrefined crude oil released torrents of pollution: nitrous oxide, sulfur dioxide, carbon dioxide. But it squeezed out petroleum that had seemed impossible to reach.

At the same time, the industry learned how to burrow farther into the Earth, opening up previously inaccessible deposits. In 1998, an oil rig near the Kern River field drilled thousands of feet deeper than any previous attempt in the area. At 17,657 feet, the well blew out in a classic gusher. Flames shot 300 feet in the air. The blast destroyed the well and everything else on the site. Even after the fire burned out, petroleum flooded from the hole for another six months. Energy firms guessed that the blowout hinted at the presence of big new oil-and-gas deposits. Earlier assessments had missed them because of their great depth. Investors rushed in and began to drill.

To McKelveyan social scientists, such stories demonstrate that oil reserves should not be thought of as physical entities. Rather, they are economic judgments: how much petroleum experts believe can be harvested from given areas at an affordable price. Even as companies drain off the easy oil, innovation keeps pushing down the cost of getting the rest. From this vantage, the race between declining oil and advancing technology determines the size of a reserve—not the number of hydrocarbon molecules in the ground. Companies that scrambled to follow the Kern River gusher found millions of barrels of deep oil, but it was mixed with so much water that they couldn’t stop the wells from flooding. Within a few years, almost all the new rigs ceased operation. The reserve vanished, but the oil remained.

This perspective has a corollary: natural resources cannot be used up. If one deposit gets too expensive to drill, social scientists (most of them economists) say, people will either find cheaper deposits or shift to a different energy source altogether. Because the costliest stuff is left in the ground, there will always be petroleum to mine later. “When will the world’s supply of oil be exhausted?” asked the MIT economist Morris Adelman, perhaps the most important exponent of this view. “The best one-word answer: never.” Effectively, energy supplies are infinite.

Sweeping claims like these make Jean Laherrère’s teeth hurt. Laherrère spent 37 years exploring for oil and gas for the French petroleum company Total before co-founding the Association for the Study of Peak Oil and Gas. ASPO was born after Laherrère and Colin Campbell, another retired petroleum geologist, predicted in 1998 that “within the next decade, the supply of conventional oil will be unable to keep up with demand.” Given the record-high petroleum reserves of the time, the claim was gutsy. Campbell and Laherrère insisted that talk of ever more oil was nonsense. In the 1980s, the Organization of the Petroleum Exporting Countries, the intergovernmental cartel that controls most crude oil, discussed allocating sales on the basis of member states’ reserves: the bigger a nation’s reserves, the more oil OPEC would let that nation sell. In such a system, countries would have every incentive to overstate their holdings. As Campbell and Laherrère noted, six of the 11 OPEC members abruptly hiked their reserve estimates during these discussions. Incredibly, some nations more than doubled their estimates, without a word of explanation for why they now had so much more oil in the ground. (OPEC eventually decided not to allocate oil in this way.) The supposed glut was a charade, Laherrère told me when we spoke in February. The reserves didn’t exist. “We said the [plateau in oil production]would begin before 2010, and we were correct.”

Far from being infinite, Laherrère said, petroleum supplies are finite by definition. The Earth contains only so many hydrocarbon molecules that can be extracted by human effort. “Once we have used up the easy oil, new types of cheap energy will not appear by magic. We will keep drilling for oil, and it will not be easy to get. Look at the enormously expensive equipment they use now only to keep up production.”

Oil prices soared, as if on cue, after Laherrère and Campbell’s prediction. By 2008, they had hit levels unseen since the Carter administration. “The supply of oil is limited,” President George W. Bush declared that year, echoing his predecessor. “There is a growing consensus that the age of cheap oil is coming to an end,” announced the British government’s Energy Research Centre. “A peak of conventional oil production before 2030 appears likely and there is a significant risk of a peak before 2020.” Bookstore shelves shudder beneath the avalanche of warnings: The Big Flatline: Oil and the No-Growth Economy. Peak Oil and the Second Great Depression (2010–2030). The End of Growth. The Crash Course. Peeking at Peak Oil. (All have come out in the past three years.)

McKelveyans remain undeterred. Morris Adelman is in failing health and could not speak to me, but I reached two of his students, Michael Lynch and Philip K. Verleger. Lynch, the president of the energy-consulting firm SEER, agreed with Laherrère that reserve estimates are sometimes manipulated for financial reasons—Shell’s chairman resigned in 2004, after the company was caught misstating its reserves—but didn’t think it mattered much. “Shell is still pumping oil,” he said. “The peak-oil people always say, ‘Look at this super-technological rig—see how expensive the equipment is now.’ I see it and think, Look at how good we’ve gotten at doing this.” Lynch added, “The airlines have jettisoned their wooden biplanes and now use 747s. That’s not because we’re running out of sky and it’s harder to fly. It’s because the technology is getting better and increasing our reach.”

More important, to Verleger’s way of thinking, the peak-oil battle has become irrelevant. Verleger, a former economic official in the Ford and Carter administrations, is now a visiting fellow at the Peterson Institute for International Economics in Washington, D.C. Since Hubbert’s time, the dispute has focused on “conventional” petroleum, the type found in regular oil wells, most of which is in the Middle East and controlled by OPEC. Production of conventional oil has indeed plateaued, as Hubbertians warned: OPEC’s output has remained roughly flat since 2005. In part, the slowdown reflects the diminishing supply of this kind of oil. Another part is due to the global recession, which has stalled demand. But a third factor is that OPEC’s conventional petroleum is being supplemented—and possibly supplanted—by what the industry calls “unconventional” petroleum, which for the moment mainly means oil and natural gas from fracking. Fracking, Verleger says, is creating “the biggest change in energy in almost 100 years—a revolution.” That revolution, in his view, will have a big winner: the United States.

The argument is simple. The need to import expensive foreign oil has been a political and economic burden on the United States for decades. Today, though, fracking is unleashing torrents of oil in North Dakota and Texas—it may create a second boom in the San Joaquin Valley—and floods of natural gas in Pennsylvania, West Virginia, and Ohio. So bright are the fracking prospects that the U.S. may become, if only briefly, the world’s top petroleum producer. (“Saudi America,” crowed The Wall Street Journal. But the parallel is inexact, because the U.S. is likely to consume most of its bonanza at home, rather than exporting it.) Oil may cost more than in the past, but prices will surely stabilize. No more spikes! Still more important, this nation is fracking so much natural gas that its price today is less than a third of its price in Europe and Asia—a big cost advantage for American industry. As companies switch to cheap natural gas, a Citigroup report argued last year, the U.S. petroleum boom could add as much as 3.3 percent to America’s GDP in the next seven years.

Until about 1970, the United States produced almost enough petroleum for its own needs. Then, just as Hubbert predicted, domestic oil production began to wane. Suddenly the United States was vulnerable. OPEC had launched an oil embargo in 1967, but it had next to no effect, because the U.S. produced so much of its own oil. Six years later, with U.S. imports surging, OPEC launched a second embargo. Oil prices quadrupled—and caused a massive panic, complete with fistfights at gas stations that were broadcast and rebroadcast on local TV news. “Energy independence!” was the new call from Washington. Perhaps the only ideal shared by Nixon, Carter, and Reagan, it became the holy grail of American politics. George W. Bush, flanked by Democrats, signed the Energy Independence and Security Act of 2007; Barack Obama, fighting with Republicans, has repeatedly touted the need to “get America closer to energy independence.”

Largely because of little-noticed research by government agencies and small companies, that goal is within sight, says Leonardo Maugeri, a former director of the petrochemical division of the Italian energy firm Eni. The United States will still import oil, he argued last summer in a report from Harvard’s Kennedy School of Government. But domestic production will increase so much that by 2020, all of this country’s oil needs “theoretically could come entirely from the Western Hemisphere.” Within a decade, in other words, the U.S. could, if it wanted, stop importing oil from the Middle East. In November, the International Energy Agency agreed, though it pushed the date of independence to 2035. The fracking-led oil-and-gas boom, Philip Verleger said in January, will lead to an American “economic Renaissance.” The United States will at last escape the world made by Churchill, at least for a while.

Nations like Japan, China, and India will still be stuck in that world, as will much of Europe and Southeast Asia. Many of these nations do not have shale deposits to frack, the requisite technological base, or, even if they have both the shale and the technology, the entrepreneurial infrastructure to finance such sweeping changes. Nonetheless, they want to be freed from their abrasive reliance on OPEC. The United States and Canada, mindful that the good times will not last forever, are also hunting for new supplies. All have been looking with ever-increasing interest at a still-larger energy source: methane hydrate.

The land sheds organic molecules into the water like a ditchdigger taking a shower. Sewage plants, fertilizer-rich farms, dandruffy swimmers—all make their contribution. Plankton and other minute sea beings flourish where the drift is heaviest, at the continental margins. When these creatures die, as all living things must, their bodies drizzle slowly to the seafloor, creating banks of sediment, marine reliquaries that can be many feet deep. Microorganisms feed upon the remains.

In a process familiar to anyone who has seen bubbles coming to the surface of a pond, the microbes emit methane gas as they eat and grow. This undersea methane bubbles up too, but it quickly encounters the extremely cold water in the pores of the sediment. Under the high pressure of these cold depths, water and methane react to each other: water molecules link into crystalline lattices that trap methane molecules. A cubic foot of these lattices can contain as much as 180 cubic feet of methane gas.

Most methane hydrate, including the deposit Japan is examining in the Nankai Trough, is generated in this way. A few high-quality beds accumulate when regular natural gas, the kind made underground by geologic processes, leaks from the earth into the deep ocean. However methane hydrate is created, though, it looks much like everyday ice or snow. It isn’t: ordinary ice cannot be set on fire. More technically, ice crystals are typically hexagonal, whereas methane-hydrate crystals are clusters of 12- or 14-sided structures that in scientists’ diagrams look vaguely like soccer balls. Methane molecules rattle about inside the balls, unable to escape. The crystals don’t dissolve in the sea like ordinary ice, because water pressure and temperature keep them stable at depths below about 1,000 feet. Scientists on the surface refer to them by many names: methane hydrate, of course, but also methane clathrate, gas hydrate, hydromethane, and methane ice.

Estimates of the global supply of methane hydrate range from the equivalent of 100 times more than America’s current annual energy consumption to 3 million times more. A tiny fraction—1 percent or less—is buried in permafrost around the Arctic Circle, mostly in Alaska, Canada, and Siberia. The rest is beneath the waves, a reservoir so huge that some scientists believe sudden releases of undersea methane eons ago set off abrupt, catastrophic changes in climate. Humankind cannot tap into the bulk of these deep, vast deposits by any known means. But even a small proportion of a very big number is a very big number.

Hydrates were regarded purely as laboratory curiosities until the 1930s, when a Texas petroleum researcher realized that they were clogging natural-gas pipelines in cold weather. Three decades later, exploration in Siberia revealed gelid bands of methane hydrate embedded in the tundra. Meanwhile, oceanographers were observing anomalies in sonar readings of the seafloor. Some areas of the bottom bounced sound waves back more sharply than one would expect from muddy sediment. It was like waving a flashlight in a dark room and being startled by the flash from a mirror. Three geologists suggested in 1971 that these reflective zones were layers of methane hydrate. Not until 1982 did researchers obtain a large chunk of methane hydrate—a three-foot section of a core sample. The gas inside was 99.4 percent methane. That year, the United States established a methane-hydrate research program.

The investigation was a small, belated part of a global push into unconventional petroleum that had been spurred by the oil shocks of the 1970s. For civilians, understanding unconventionals is difficult, not least because of the taxonomic hodgepodge the industry uses to describe them: tar sands, tight oil, heavy oil, shale gas, coal-bed methane, shale oil, oil shale. (Exasperatingly, shale oil is different from oil shale.) All of these different flavors of petroleum are “unconventional” simply because in the past they were too hard to pull from the earth to be worth the bother. Nowadays technology has made many of them accessible.

With the odd exception, unconventionals can be broken into two rough categories: forms of petroleum that are heavier and less refined than the crudest of crude oil, and forms that are lighter and more refined than crude oil. Both are worth huge sums and entangled in dispute, much like conventional petroleum. But the second category, which includes the natural gas from methane hydrate, seems likely to play a much larger role in humankind’s future—economically, politically, and, most of all, environmentally.

The first, heavy category consists of petroleum that must be processed on-site to be transformed into oil. Tar sands, for instance, consist of ordinary sand mixed with bitumen, a sludgy black goo that hasn’t withstood enough geological heat and pressure to be converted fully into ordinary oil. The most important tar-sand deposits are underneath an expanse of subarctic forest in central Canada that is roughly the size of England; they make up the third-biggest proven oil reserve in the world. In most cases, mining tar sands involves drilling two horizontal wells, one above the other, into the bitumen layer; injecting massive gouts of high-pressure steam and solvents into the top well, liquefying the bitumen; sucking up the melted bitumen as it drips into the sand around the lower well; and then refining the bitumen into “synthetic crude oil.” Refining in this case includes removing sulfur, which is then stored in million-ton, utterly useless Ozymandian slabs around mines and refineries.

Economists sometimes describe a fuel in terms of its energy return on energy invested (EROEI), a measure of how much energy must be used up to acquire, process, and deliver the fuel in a useful form. OPEC oil, for example, is typically estimated to have an EROEI of 12 to 18, which means that 12 to 18 barrels of oil are produced at the wellhead for every barrel of oil consumed during their production. In this calculation, tar sands look awful: they have an EROEI of 4 to 7. (Steaming out the bitumen also requires a lot of water. Environmentalists ask, with some justification, where it all is going to come from.)

Conveying tar-sands oil to its biggest potential markets, in the United States, will involve building a huge pipeline from Alberta to Texas, which has attracted vituperative opposition from environmental groups and some local governments. The U.S. State Department has long delayed issuing permits to allow this pipeline to cross the border, a stall that has outraged energy boosters, who charge that the Obama administration is spitting in the soup of Canada, America’s most important ally. The boosters say little about the two 100 percent Canadian pipelines—one to shoot tar-sands oil to a port in British Columbia, a second to Montreal—that 100 percent Canadian opposition has stalled. All the while, indigenous groups in central Canada, people armed with special powers granted by the Canadian constitution, have carpet-bombed tar-sands country with lawsuits. Regardless of the merits of the protesters’ arguments, it is hard to believe that they will be completely ineffective, or that tar-sands oil will flow freely anytime soon.

Much more prominent is the second unconventional category, the most important subcategory of which is the natural gas harvested by fracking shale. Every few years, the U.S. government produces a map of American shale beds. Flipping through a time series of these maps is like watching the progress of an epidemic—methane deposits pop up everywhere, and keep spreading. To obtain shale gas, companies first dig wells that reach down thousands of feet. Then, with the absurd agility of anime characters, the drills wriggle sideways to bore thousands of feet more through methane-bearing shale. Once in place, the well injects high-pressure water into the stone, creating hairline cracks. The water is mixed with chemicals and “proppant,” particles of sand or ceramic that help keep the cracks open once they have formed. Gas trapped between layers of shale seeps past the proppant and rises through the well to be collected.

Water-assisted fracturing has been in use since the late 1940s, but it became “fracking” only recently, when it was married with horizontal drilling and the advanced sensing techniques that let it be used deep underground. Energy costs are surprisingly small; a Swiss-American research team calculated in 2011 that the average EROEI for fracked gas in a representative Pennsylvania county was about 87—about six times better than for Persian Gulf oil and 16 times better than for tar sands. (Fracking uses a lot of water, though, and activists charge that the chemicals contaminate underground water supplies.) Because of fracking, U.S. natural-gas reserves have jumped by almost three-quarters since 2000.

Shale gas has its detractors. Far from being a game changer, Jean Laherrère told me, shale gas is a “Ponzi scheme” in which oil companies acquire largely fictional methane deposits to polish their balance sheets for Wall Street. A February study from the Post Carbon Institute, an anti-fossil-fuel think tank, dismissed shale gas as, at best, “a temporary reprieve from having to deal with the real problems”; the group’s general tenor is indicated by the special URL it set up for the report: shalebubble.org. But these views are not widely shared. Two days after I last spoke with Laherrère, the head of the U.S. Energy Information Administration told a congressional hearing that the additions to America’s energy reserves ballyhooed in the agency’s most recent report “were—by a large margin—the highest ever recorded since EIA began publishing proved reserve estimates in 1977.”

As Economics 101 would predict, the arrival of vast quantities of methane from fracking has already made U.S. natural-gas prices plummet. In response, hundreds of wells have shut down, preserving methane deposits that can be tapped someday in the future. But U.S. natural-gas production has hardly been affected. Neither has demand: more and more industries, attracted by low prices, are switching to gas from oil and coal—especially coal.

Today, a fifth of U.S. energy consumption is fueled by coal, mainly from Appalachia and the West, a long-term energy source that has provided jobs for millions, a century-old way of life—and pollution that kills more than 10,000 Americans a year (that estimate is from a 2010 National Research Council study). Roughly speaking, burning coal produces twice as much carbon dioxide as burning the equivalent amount of natural gas. Almost all domestic coal is used to generate electricity—it produces 38 percent of the U.S. power supply. Fracking is swiftly changing this: in 2011, utilities reported plans to shut down 57 of the nation’s 1,287 coal-fired generators the following year. Largely in consequence, U.S. energy-related carbon-dioxide emissions have dropped to figures last seen in 1995. Since 2006, they have fallen more than those from any other nation in the world.

The U.S. coal industry has taken to complaining of a “war on coal.” But the economic hit has been less than one would expect; U.S. coal exports, mainly to Europe, almost doubled from 2009 to 2011. In the sort of development that irresistibly attracts descriptors like ironic, Germany, often touted as an environmental model for its commitment to solar and wind power, has expanded its use of coal, and as a result is steadily increasing its carbon-dioxide output. Unlike Americans, Europeans can’t readily switch to natural gas; Continental nations, which import most of their natural gas, agreed to long-term contracts that tie its price to the price of oil, now quite high. “It’s like someone said, ‘We’ll sell you all the tea you want, based on the price of coffee,’ ” Michael Lynch, the energy consultant, told me. “And you said, ‘What a great idea! I’ll lock myself into it for decades.’ ” He laughed. “Truly, you can’t make this stuff up.”

Here I should confess to personal bias. Twelve years ago, a magazine asked me to write an article about energy supplies. While researching, I met petroleum geologists and engineers who told me about a still-experimental technique called hydraulic fracturing. Intrigued, I asked several prominent energy pundits about it. All scoffed at the notion that it would pay off. To be fair, some early fracking research was outlandish; three early trials involved setting off atomic weapons underground (they did produce natural gas, but it was radioactive). I don’t want to embarrass anyone I spoke with. I failed to exercise independent judgment, and did not mention hydraulic fracturing in my article, so I was just as mistaken. But I also don’t want to miss the boat again. Even though plenty of experts discount methane hydrate, I now am more inclined to pay attention to the geologists and engineers who foresee a second, fracking-type revolution with it, a revolution that—unlike the shale-gas rush, mostly a North American phenomenon—will ripple across the globe.

Japan, which has spent about $700 million on methane-hydrate R&D over the past decade, has the world’s biggest hydrate-research program—or perhaps that should be programs, because provincial governments on Japan’s west coast formed a second hydrate-research consortium last year. (Several researchers told me that the current towel-snapping between Beijing and Tokyo over islands in the East China Sea is due less to nationalistic posturing than to nearby petroleum deposits.) In mid-March, Japan’s Chikyu test ended a week early, after sand got in the well mechanism. But by then the researchers had already retrieved about 4 million cubic feet of natural gas from methane hydrate, at double the expected rate. Japan’s Ministry of Economy, Trade, and Industry is eager to create a domestic oil industry; at present, the nation produces just one one-thousandth of its own needs. Perhaps overoptimistically, the ministry set 2018 as a target date for commercializing methane hydrate. India and South Korea are following along, each spending as much as $30 million a year on hydrate experiments; the Korean program is growing especially aggressively.

By contrast, the U.S. Department of Energy program is small—its annual budget is about $15 million, most of which is devoted to basic research on gas hydrates’ formation and location. About $2.4 million goes to U.S. Geological Survey methane-hydrate researchers, who have been test-mining onshore deposits in frigid Alaska and northwestern Canada. Based in Woods Hole, Massachusetts, and Denver, Colorado, the USGS program has about eight full-time researchers, as well as collaborators from Japan, Canada, Germany, India, and several oil companies.

Although most U.S. research has been in the far north, the most promising U.S. deposits are in the Gulf of Mexico. Hydrates are thought to blanket about 174,000 square miles of the gulf, an area about the size of California. At least part of the deposit, seepage from conventional hydrocarbon reservoirs, is top-quality stuff, though nobody has any idea how much is actually recoverable. What is known, says Timothy Collett, the energy-research director for the USGS program, is that some of the gulf’s more than 3,500 oil and gas wells are in gas-hydrate areas. Extracting these hydrates, in his view, is the logical next step. “To keep feeding the infrastructure, you have to maintain a certain return. Otherwise, you’ll abandon it,” he told me. “For the individual manager of a large installation with a multimillion-dollar budget, it might be well within your interest, as you go into decline on deepwater production, to start looking at gas hydrate.”

If one nation succeeds in producing commercial quantities of undersea methane, others will follow. U.S.-style energy independence, or something like it, may become a reality in much of Asia and West Africa, parts of Europe, most of the Americas. To achieve this dream, history suggests, subsidies to domestic producers will be generous and governments will slap fees on petroleum imports—especially in Asia, where dependence on foreign energy is even more irksome than it is here. In addition to North America, the main sources of conventionally extracted natural gas are Russia, Iran, and Qatar (Saudi Arabia is also an important producer). All will feel the pinch in a methane-hydrate world. If natural gas from methane hydrate becomes plentiful and cheap enough to encourage nations to switch from oil, as the Japanese hope, the risk pool will expand to include Brunei, Iraq, Nigeria, the United Arab Emirates, Venezuela, and other petro-states.

The results in those nations would be turbulent. Petroleum revenues, if they are large, exercise curious and malign effects on their recipients. In 1959, the Netherlands found petroleum on the shores of the North Sea. Money gurgled into the country. To general surprise, the flood of cash led to an economic freeze. Afterward, economists realized that salaries in the new petroleum industry were so high that nobody wanted to work anywhere else. To keep employees, companies in other parts of the economy had to jack up wages, in turn driving up costs. Meanwhile, the surge of foreign money into the Netherlands raised the exchange rate. Soaring costs and currency made it harder for Dutch firms to compete; manufacturing and agriculture faltered; unemployment climbed, except in the oil industry. The windfall led to stagnation—a phenomenon that petroleum cognoscenti now call “Dutch disease.”

Some scholars today doubt how much the Netherlands was actually affected by Dutch disease. Still, the general point is widely accepted. A good modern economy is like a roof with many robust supporting pillars, each a different economic sector. In Dutch-disease scenarios, oil weakens all the pillars but one—the petroleum industry, which bloats steroidally.

Worse, that remaining pillar becomes so big and important that in almost every nation, the government takes it over. (“Almost,” because there is an exception: the United States, the only one of the 62 petroleum-producing nations that allows private entities to control large amounts of oil and gas reserves.) Because the national petroleum company, with its gush of oil revenues, is the center of national economic power, “the ruler typically puts a loyalist in charge,” says Michael Ross, a UCLA political scientist and the author of The Oil Curse (2012). “The possibilities for corruption are endless.” Governments dip into the oil kitty to reward friends and buy off enemies. Sometimes the money goes to simple bribes; in the early 1990s, hundreds of millions of euros from France’s state oil company, Elf Aquitaine, lined the pockets of businessmen and politicians at home and abroad. Often, oil money is funneled into pharaonic development projects: highways and hotels, designer malls and desalination plants. Frequently, it is simply unaccounted for. How much of Venezuela’s oil wealth Hugo Chávez hijacked for his own political purposes is unknown, because his government stopped publishing the relevant income and expenditure figures. Similarly, Ross points out, Saddam Hussein allocated more than half the government’s funds to the Iraq National Oil Company; nobody has any idea what happened to the stash, though, because INOC never released a budget. (Saddam personally directed the nationalization of Iraqi oil in 1972, then leveraged his control of petroleum revenues to seize power from his rivals.)

Shortfalls in oil revenues thus kick away the sole, unsteady support of the state—a cataclysmic event, especially if it happens suddenly. “Think of Saudi Arabia,” says Daron Acemoglu, the MIT economist and a co-author of Why Nations Fail. “How will the royal family contain both the mullahs and the unemployed youth without a slush fund?” And there is nowhere else to turn, because oil has withered all other industry, Dutch-disease-style. Similar questions could be asked of other petro-states in Africa, the Arab world, and central Asia. A methane-hydrate boom could lead to a southwest-to-northeast arc of instability stretching from Venezuela to Nigeria to Saudi Arabia to Kazakhstan to Siberia. It seems fair to say that if autocrats in these places were toppled, most Americans would not mourn. But it seems equally fair to say that they would not necessarily be enthusiastic about their replacements.

Augmenting the instability would be methane hydrate itself, much of which is inconveniently located in areas of disputed sovereignty. “Whenever you find something under the water, you get into struggles over who it belongs to,” says Terry Karl, a Stanford political scientist and the author of the classic The Paradox of Plenty: Oil Booms and Petro-States. Think of the Falkland Islands in the South Atlantic, she says, over which Britain and Argentina went to war 30 years ago and over which they are threatening to fight again. “One of the real reasons that they are such an issue is the belief that either oil or natural gas is offshore.” Methane-hydrate deposits run like crystalline bands through maritime flash points: the Arctic, and waters off West Africa and Southeast Asia.

In a working paper, Michael Ross and a colleague, Erik Voeten of Georgetown University, argue that the regular global flow of petroleum, the biggest commodity in world trade, is also a powerful stabilizing force. Nations dislike depending on international oil, but they play nice and obey the rules because they don’t want to be cut off. By contrast, countries with plenty of energy reserves feel free to throw their weight around. They are “less likely than other states to sign major treaties or join intergovernmental organizations; and they often defy global norms—on human rights, the expropriation of foreign companies, and the financing of foreign terrorism or rebellions.” The implication is sobering: an energy-independent planet would be a world of fractious, autonomous actors, none beholden to the others, with even less cooperation than exists today. 

None of this is what makes Christopher Knittel use words like catastrophe. What Knittel is thinking of is, so to speak, the little black specks of Yulin, China. Five years ago, I traveled with a friend to Yulin, in the northwestern province of Shaanxi, not far from Mongolia. We visited the Great Wall, which passes just north of town. In that area, the wall itself had mostly crumbled to nothing, except for the watchtowers, which stuck up every half mile or so. People in one tower were supposed to be able to signal to the next, passing on messages like ships at sea.

When I climbed up one eroded tower, I was surprised to find that I couldn’t see its neighbor. There were little black specks all over my glasses. I cleaned the lenses, but was still unable to make out the next tower. The black specks were not just on my glasses.

Walking around town, my friend and I had noticed that almost every home had a pile of coal outside, soft dark chunks that people shoveled into stoves for cooking and heating. Thousands upon thousands of coal fires were loading the air with tiny dots of soot. Scientists have taken to calling these dots “black carbon,” and have steadily ratcheted up their assessments of its harm. In March, for instance, a research team led by a Mumbai environmental group estimated that black carbon and other particulate matter from India’s coal-fired power plants cause about 100,000 deaths a year.

Environmentalists worry even more about black carbon’s role in climate change. Black carbon in the air absorbs heat and darkens clouds. In some places, it alters rain patterns. Falling on snow, it accelerates melting. A 31-scientist team from nine nations released a comprehensive, four-year assessment in January arguing that planetary black-carbon output is the second-biggest driver of anthropogenic (human-caused) climate change; the little black specks I found on my glasses and clothes have roughly two-thirds the impact of carbon dioxide.

Natural gas produces next to no soot and half the carbon dioxide coal does. In coal-heavy places like China, India, the former Soviet Union, and eastern Europe, heating homes and offices with natural gas instead of coal would be a huge step. An MIT study chaired by Ernest Moniz, whom President Obama nominated for energy secretary in March, called natural gas “a cost-effective bridge” to a “low-carbon future.”

The Chinese government is aware of this, which is one reason it is pursuing both shale gas and methane hydrate. But environmentalists are less enthusiastic than one might imagine about the prospect of weaning ourselves from coal with gas. The reason is that methane itself—unburned natural gas—has a much greater capacity to trap solar heat than carbon dioxide does. (Because methane does not remain in the air as long as carbon dioxide, the precise comparison depends on the chosen time frame; researchers typically say that methane is about 20 or 30 times more potent.) Activists fear that the negative effects of obtaining natural gas could swamp the positive effects of burning it. They are entirely correct, although perhaps not in the way they suppose.

Almost every friend and neighbor I have spoken with about methane hydrate asked whether tapping these undersea deposits could release vast amounts of methane all at once, disastrously altering the planet’s environment. According to Carolyn Ruppel of the Geological Survey, these fears are understandable—but misplaced. If things go awry in a hydrate operation, some of the methane will escape into exactly the cold temperatures and high pressures that trapped it to begin with. Some will be consumed by bacteria, producing carbon dioxide, which dissolves in water; this raises the ocean’s acidity, but not enough to have much effect. Any remaining methane will rise out of the sediment and, like the carbon dioxide, dissolve harmlessly in the ocean. (None of this should be confused with a different source of methane: the decayed vegetation in permafrost, which will release methane if the permafrost thaws.)

The real concern, Ruppel and other researchers told me, is less an explosive methane release from under the Earth’s surface—the environmental disaster that might have caused havoc eons ago—than a slow discharge at ground level, from the machinery that will pull methane hydrate out of the seafloor. The problem already exists with fracking. “The rule of thumb is that if a well leaks more than about 3 percent” of its methane production into the air, “natural gas actually becomes dirtier than coal, from a climate-change perspective,” says Ramez Naam, the author of The Infinite Resource, a just-published book about the race between environmental degradation and technological innovation. “The amazing thing, though, is that we don’t have any data—nobody is required to monitor methane at the well. So there’s just a few studies, which vary tremendously.” Worse still, the aging natural-gas infrastructure is riddled with holes and seeps; early this year, a survey of gas mains along Boston’s 785 miles of road, the first-ever such examination, found 3,356 leaks. Last August, the Environmental Protection Agency amended the Clean Air Act to require well operators to recapture some methane; because nobody knows how much natural gas is gushing into the air, the new rules’ impact is uncertain.

Still, fixing leaks is a task that developed nations can accomplish. “In the United States,” Lynch says, “it is possible to hire inspectors and send them out in white vans to measure methane emissions. They can tell companies to spray more silicone in the wellheads. Maybe the companies will kick and scream about the bureaucracy and cost, but this is something that can be done.”

What we can’t do, or at least not readily, is overcome the laws of economics. More...

By Brad Plumer
February 22, 2013

What’s the best way to curtail gasoline consumption? Economists tend to agree on the answer here: Higher gas taxes at the pump are more effective than stricter fuel-economy standards for cars and trucks.

Much more effective, in fact. A new paper from researchers at MIT’s Global Change program finds that higher gas taxes are “at least six to fourteen times” more cost-effective than stricter fuel-economy standards at reducing gasoline consumption.

Why is that? One of the study’s co-authors, Valerie Karplus, offers a basic breakdown here: Fuel-economy standards work slowly, as manufacturers start selling more efficient vehicles, and people retire their older cars and trucks. That turnover takes time. By contrast, a higher gas tax kicks in immediately, giving people incentives to drive less, carpool more, and buy more fuel-efficient vehicles as soon as possible.

A great deal also depends on whether biofuels and other alternative fuels are available. A tax on gasoline makes these alternative fuels more competitive, whereas fuel-economy standards don’t. “We see the steepest jump in economic cost between efficiency standards and the gasoline tax if we assume low-cost biofuels are available,” Karplus said in an MIT press release.

And yet… all this economic research never seems to have any effect on lawmakers. Since 2007, Congress and the Obama administration have moved to increase federal fuel economy standards, now scheduled to rise to 54.5 miles per gallon by 2025. According to the MIT estimates, this will cost the economy six times as much as simply raising the federal gas tax from its current level of 18.4 cents per gallon to 45 cents per gallon. Yet no one in Congress has even proposed the latter option.

One explanation is that the public just prefers things this way. Higher fuel-economy standards do impose costs, but they’re largely “hidden” costs — in the form of pricier vehicles in the showroom. A higher gas tax, by contrast, is visible every time people fill up at the pump.

In fact, a recent NBER paper by MIT’s Christopher Knittel found that this has been the case for decades. Between 1972 and 1980 the price of oil soared 650 percent. There was endless public debate during this period about how best to reduce reliance on fossil fuels. And, as Knittel discovered, the public consistently preferred price controls and fuel-economy standards over higher gas taxes. That was true no matter how often people were informed that gas taxes were the superior option.

“Given the saliency of rationing and vehicle taxes,” Knittel concluded, “it seems difficult to argue that these alternative polices were adopted because they hide their true costs.” In other words, the public seems to have an (expensive) preference for inefficient regulations over higher taxes to curb gasoline. Economists find it maddening, but it’s hard to change.

Further reading:

–On the other hand, if you want to see a rare economic argument for fuel-economy standards, check out this 2006 paper (pdf) by Christopher Knittel. He found that Americans were becoming less sensitive to fuel prices over time — which strengthened the case for policies like CAFE standards.