There is now a great deal of research and assessment being done on hydrofracking by government agencies, the industry, academics, inventors, and environmentalists, and the fruits of their labors will be revealed in the next few years.
While the politics and economics of fracking remain volatile, there appears to be a greater willingness to compromise on either side of the debate. In the meantime, scientists are gathering new data: the EPA will issue the preliminary results of its nationwide study in 2014, and impose new regulations limiting air pollution caused by hydrofracking in 2015. The industry has entered a new dynamic phase, and is maturing on almost every level.
The answer to this seemingly simple question is a moving target. In 2011 the EIA estimated that the nation had 827 trillion cubic feet of shale gas; a few months later, the agency sharply reduced the estimate to 482 trillion cubic feet. As of this writing in 2013, the EIA estimates the United States has roughly 665 trillion cubic feet of technically recoverable shale gas (fourth globally, behind China, Argentina, and Algeria).1
The US Geological Survey (USGS), meanwhile, revised its estimates of shale oil in the Bakken and Three Forks formations—which lie beneath Montana, North Dakota and South Dakota—upward, to 7.4 billion barrels of undiscovered oil—double the previous estimate—and 6.7 trillion cubic feet of gas, triple the previous estimate. The EIA adds that the United States now has an estimated 48 billion barrels of shale oil reserves (second worldwide, after Russia’s 58 billion barrels).
These revisions were made as information and technology changed, or previously unexplored formations, like Three Forks, gained attention. Moreover, the definition of what constitutes a “technically recoverable” resource is shifting.
Geologists typically gather data on how much gas a well produces at the outset of operations, and base their estimates on it. But those estimates can be too low or too high. Some estimates have included gas in pockets that are so deep or small, or in areas that are off-limits (i.e., critical watersheds or environmentally sensitive zones), that they are unlikely to be drilled. Energy analysts have criticized EIA and USGS estimates as overly optimistic. “If the country is going to embrace natural gas as the fuel of the future, there needs to be a lot more transparency in how these estimates are calculated and a more skeptical and informed discussion about the economics of shale gas,” said Bill Powers, editor of the Powers Energy Investor.2
A group affiliated with the Colorado School of Mines doubts that the oft-quoted figure, that the United States has a “100 year supply” of natural gas, is realistic and says the nation may only have 23 years’ worth of gas that is economically viable to recover.3 And Gail Tverberg, an actuary who writes Our Finite World, a blog about resources, is skeptical about the hype around shale reserves: “The idea that the US is about to become a net oil exporter is simply a myth,” she writes.4
According to a report in the Wall Street Journal, there is a growing consensus that the United States will see steady growth in natural gas supplies until they plateau sometime around 2040, after which they will slowly decline.5 This conclusion was reinforced in February 2013, when an exhaustive study underwritten by the nonpartisan Alfred P. Sloan Foundation examined data from 15,000 wells in the Barnett Shale, near Fort Worth, Texas, plus research on shale in Pennsylvania, Louisiana, and Arkansas.6 The study was among the first to examine both the geology and economics of hydrofracking, and it revealed that shale deposits can be highly variable in size and potential, even within the same region.
The gas industry uses the term Ultimate Economic Recovery (UER) to describe the economic performance of a well. Because no shale well has as yet undergone a complete life cycle, UER estimates are based on computer models and educated hunches.7 While drillers are constantly on the hunt for new well sites, hydrofracking remains a risky business. The market can shift; productive wells can sit adjacent to unproductive wells; and some firms are contractually obliged to pump resources whether their wells turn a profit or not.
In the relatively large 5,000-square-mile Barnett play, for instance, energy companies have spent roughly $40 billion to lease and drill claims, yet critics such as petroleum geologist Art Beman say just a quarter of them are likely to prove economical.8 Nonetheless, the Sloan study—which was praised by both pro- and anti-hydrofracking groups—suggests that in its lifetime the Barnett will likely see another 13,000 wells drilled, and produce some 44 trillion cubic feet of natural gas—equivalent to two years’ worth of US natural gas consumption, and more than three times what has been produced there thus far.
Although hydraulic fracturing is highly partisan on the local level, it is a low-boiling issue on the national stage. In general, Republicans favor leaving most fracking regulation to the states, believing they can tailor rules to local needs, and do so more speedily than federal regulators. But many Democrats worry that without oversight cash-strapped states will engage in a “race to the bottom” and will trim their rules or fail to enforce them in order to compete for jobs and revenue.9
There is as yet no national standard for this industrial process, and 31 states with significant shale resources have responded with widely different requirements.10 While a heavily fracked state like Pennsylvania requires full disclosure of chemicals, for instance, most states that are new to the process, such as Kansas, do not. In 2009, Ohio issued just a single hydrofracking permit. In 2010 it issued two. But in 2011 Ohio issued 42 permits, 27 of them between July and September. As a result, the Ohio Oil and Gas Association anticipates a $14 billion gain for the state by 2015.11
As of mid-2013, California had no rules specifically regulating fracking, and legislators were caught flat-footed. By that point, 851 wells had been hydrofracked in the state (mostly in Kern County, near Bakersfield); alarmed, California’s strong environmental movement pushed hard for a moratorium. Now a dozen new laws are being debated by state legislators, and regulators are rushing to create a new set of regulations by 2014.12
In spite of such divisive politics, the hydrofracking debate has seen a few notable compromises. In 2013, Illinois was saddled with the worst pension problem in the nation—roughly $100 billion in unpaid pension liabilities—when a partisan fight erupted over hydrofracking.13 Republicans, backed by industry, stumped for a loosening of regulations in order to attract natural gas producers. The Illinois Chamber Foundation said increased hydrofracking could bring more than 45,000 jobs to the state. But Democrats, backed by environmentalists, were deeply concerned about water depletion and pollution. In May, the state senate passed the nation’s most stringent fracking regulations by a vote of 52 to 3. After “hundreds of thousands of hours” of negotiations, said Mike Frerichs, a Democrat from Champagne who sponsored the bill, the result was “tough regulations that are going to protect and preserve our most valuable resources.… We are going to increase home produced energy in our state in one of the most environmentally friendly ways possible.”14
On the national stage, Democratic and Republican politicians alike take large campaign contributions from the gas and oil industry, and politicians of nearly every stripe seem to be pushing for the expansion of cheap gas. In his 2012 State of the Union address, President Obama said, “This country needs an all-out, all-of-the-above strategy that develops every available source of American energy—a strategy that’s cleaner, cheaper, and full of new jobs. We have a supply of natural gas that can last America nearly one hundred years, and my Administration will take every possible action to safely develop this energy.”15
The energy industry is quick to argue that the “shale gale” is the direct result of smart policy and intentional strategy. In a widely quoted op-ed piece in the New York Times, Christof Ruhl, BP’s group chief economist, wrote that the American shale revolution “is not a happy accident of geology and lucky drilling.” Rather, it comes from a particular set of circumstances that may be difficult to replicate elsewhere in the world. “The dramatic rise in shale-gas extraction and the tight-oil revolution,” he wrote, “happened in the United States and Canada because open access, sound government policy, stable property rights and the incentive offered by market pricing unleashed the skills of good engineers.” In Ruhl’s view, policy and not geology is what is “driving the extraordinary turn of events that is boosting America’s oil industry.” While Asia, Latin America, and Africa have greater unconventional reserves than the United States, he noted, “the competitive environment, government policy and available infrastructure mean that North America will dominate the production of shale gas and tight oil for some time to come.”16
Both Democrats and Republicans take credit for this policy, and agree that environmental and health questions need to be addressed for hydrofracking to succeed over the long term.
As mentioned above, the development and production of oil and gas is regulated by a matrix—to some, a crazy quilt—of federal, state, and local laws. Most federal laws are administered by the EPA or the Department of the Interior (DOI), though development of federal lands is overseen by the Bureau of Land Management (BLM) and the US Forest Service (USFS).
In the case of California and Illinois, state legislatures are scrambling to adapt to new technology and the public’s mood swings, and it isn’t always pretty. In 2012 alone over 170 bills to regulate oil and gas drilling were introduced in 29 states; but only 14 of them became law, according to the National Conference of State Legislatures.17 Some state laws are tough, perhaps burdening the drilling industry unnecessarily. Others are lenient, perhaps leaving much of the country subject to environmental dangers.
The hydrofracking industry, meanwhile, argues that their operations are becoming cleaner and safer every day. According to a Wall Street Journal analysis of Pennsylvania DEP records from 2008 to 2012, the rate of environmental violations in the Marcellus Shale has dropped steadily as the industry matures.18 Increasingly, large, well-funded, experienced companies are snapping up medium- and small-sized companies that don’t have the resources or depth of knowledge to implement effective safety regimes. The analysis found that major energy firms—such as ExxonMobil, Shell, and Chevron—were cited for infractions in 6.5 percent of inspections; midsize companies—with a stock market value of $2 billion to $50 billion—were cited in 14 percent of inspections; and small firms—with a stock market value of less than $2 billion—were cited in 17 percent of inspections.
Opponents say that another factor—less aggressive regulation by Pennsylvania’s pro-hydrofracking governor, Tom Corbett—could explain the drop in violations. Environmentalists point to a March 2011 memo that directed state DEP inspectors to clear all violation notices with senior department officials before issuing them, implying that the regulatory system had become politicized. The governor defended the practice and asserted that the decline in violations is the result of more rigorous inspections.19
In 2012 then-interior secretary Ken Salazar said that shale gas provided the United States the opportunity of energy independence, but added, “If we are going to develop natural gas from shale, it has to be done in a safe and responsible manner.”20 But when the DOI issued a new set of hotly anticipated rules governing hydrofracking on public lands in May 2013, environmentalists were dismayed. The new rules continue to allow energy companies to keep certain fracking chemicals secret, and allow them to run integrity tests on one representative well rather than all wells in a gas or oil field.
This ruling may be an indicator of how the Obama administration will regulate fracking going forward. The new rules were the first significant bit of regulation issued under the new interior secretary, Sally Jewell. (She worked in the oil industry in the 1970s, and is not afraid to say she fracked a few wells in Oklahoma.) She told reporters that it is critical for rules to keep up with technology, and that the federal government will continue to lease large tracts of public and Indian lands for energy development.21
“Water is now emerging as a significant opportunity and risk for oil and gas companies,” said Laura Shenkar, an expert on corporate water strategy at the Artemis Project consulting firm.22 In 2012, about 4.5 billion gallons of water were used for hydraulic fracking. By 2060, that number will spike to some 260 billion gallons, according to an estimate by Lux Research, a Boston consulting firm that monitors emerging technologies.23
As climate change and shifting weather patterns stress water supplies, a lack of water will impede hydrofracking. During the brutal drought of 2011, Texas regulators suspended water withdrawal permits in the Eagle Ford Shale, located near San Antonio.24 In search of more efficient, sustainable water use, a few companies are experimenting with using recycled water. One company, Alpha Reclaim Technology, buys treated effluent from cities and towns in Texas and sells it to drillers in the Eagle Ford play.25 Another plan is to develop mobile recycling units that will treat flowback, then reuse it. Companies in the same region are experimenting with using brackish water, a common underground resource in Texas. The drawback is that brackish water contains more salts and other elements, such as boron, which can harm the drilling process; some brackish reservoirs lie deep and are expensive to tap. A shallow well in the Eagle Ford play costs about $75,000 to drill, according to ConocoPhillips, while a deeper well could cost as much as $1 million.26
In an effort to make hydrofracking more environmentally friendly, the EPA instituted new “green completion” (or “reduced emission completion”) rules in 2012, designed to cut down on air pollution. In essence, the nearly 600-page set of rules requires hydrofrackers to capture natural gas at the wellhead rather than flaring it off or releasing it into the atmosphere.
Green completions are used in the week or so between the initial drilling of a well and the time the well goes into production, a period when pollutants—and valuable methane—billow out of the borehole into the atmosphere, “like popping the top on a soda can,” as the Natural Resources Defense Council (NRDC) puts it. That escaping gas represents half a trillion cubic feet of wasted gas annually, NRDC estimates.27
Every well is different, and there is no one-size-fits-all green completion process. When a well is drilled, it produces a mix of water, sand, hydrocarbon liquids, and gas. The elements are separated in a cylindrical vessel that allows the pressure from the well to drop: the liquids and solids drop while the gas rises. When hydrofracking dry gas, like that from the Marcellus Shale in New York, a green completion involves a two-step process to separate gas from flowback. In the case of wet gas, like that found in the Marcellus Shale in northern West Virginia, a three-phase separation separates gas from hydrocarbon liquids from flowback.28
Another target of green completion is the dramatic “flaring” of excess gas or oil. Typically used in a well’s early production, this venting clears impurities from the well before production begins. But it also releases methane into the atmosphere. In composing the new rules, the EPA acted on its Clean Air Act mandate to reduce emissions of VOCs (volatile organic compounds) and potential carcinogens, such as benzene. The agency estimates that green completions would eliminate 95 percent of smog-forming VOCs emitted from over 13,000 new gas wells annually.29
During a green completion, wastewater is routed through a series of filters. A sand trap collects the solid materials, which are sent to a landfill. The remaining wastewater is cleaned, treated, and stored for reuse in the next drilling operation. The natural gas is then channeled into a pipeline, captured, and sold. Indeed, a “co-benefit” of the new rules is that, with the help of portable equipment to process gas and condensate (a low-density combination of hydrocarbon liquids that are present as gaseous compounds in natural gas), some 1 million to 1.7 million tons of methane can be recovered each year—gas that was previously wasted.30 The EPA calculates green completions will yield $11 million to $19 million in savings per year.31
The agency has allowed the industry to delay full implementation of the rules until 2015, to ensure a smooth transition. Critics maintain the rules still have worrisome loopholes: existing facilities, for instance, are allowed to release one ton of benzene per year from specified equipment. Nor are industry experts happy with them. In fact, both sides of the fracking debate have threatened to sue the EPA over the new rules.
While the gas rush has benefited many Americans, it has not always made drillers and their investors rich. By 2013, exploration companies had poked so many boreholes into the ground and sucked so much natural gas out of shale that they produced a glut, dropped prices to near record lows, and left the hydrofracking industry with a hangover. “We just killed more meat than we could drag back to the cave and eat,” Texas investment banker Maynard Holt, of Tudor Pickering Holt, who advised on many gas deals, lamented to the New York Times. “Now we have a problem.”32
As noted in chapter 1, shale gas cost $13.68 per million BTU (MBTU) at Henry Hub, the main pricing point for American natural gas, in 2008. But by 2012, gas prices had fallen over 60 percent, to less than $2 per MBTU. By May 2013, prices had perked up, to $4.04 per MBTU, and the EIA expects the price to rise slightly, to $4.10 per MBTU, in 2014.33
Despite this slow recovery, hydrofracking is still not economical for many drillers. Most need the price to rise over $4 to cover costs, and the “sweet spot”—the price at which producers can make money while consumers are not too pinched—is about $5 or $6 per MBTU, analysts say.34
Because of the plunge in prices, the credit ratings and stock price of companies that had expanded rapidly into hydrofracking—such as Chesapeake Energy, Devon Energy, and Southwestern Energy—took a pounding. Many drillers took rigs out of production or shifted them to other regions.
In late 2012, the number of drill rigs exploring for natural gas fell by 30 percent, to 658, according to the energy services company Baker Hughes.35 The steepest declines have been in the Fayetteville Shale in central Arkansas and the Haynesville Shale in Louisiana and Texas.
Some firms have shut down existing wells and halted new investments; others began to shed assets and retrench to pay down debts. By early 2013, Chesapeake’s stock price had sunk, a raft of governance issues had caused the Securities and Exchange Commission to investigate the company, the board was shaken up, and Aubrey McClendon was removed as chairman. In an effort to raise $14 billion quickly, the company took an emergency unsecured bridge loan of $4 billion at 8.5 percent interest.36 And Chesapeake shed valuable assets—such as large oil and gas operations in west Texas to Chevron and Royal Dutch Shell—in great haste.
Smaller companies like Norse Energy Corporation—which leased drilling rights to 130,000 acres in New York State, but was laden by debt and stymied by regulatory delays—have filed for bankruptcy, and are attempting to regroup under Chapter 11 protection.37
But many firms couldn’t stop hydrofracking their wells even if they wanted to. Saddled by complex financial deals and lease arrangements they struck during the boom years, they are contractually obliged to proceed at full speed.
With the help of such Wall Street firms as Goldman Sachs, Barclays, and Jefferies & Company, the 50 biggest oil and gas firms raised some $126 billion between 2006 and 2012 and spent it on acquiring land and equipment, hydrofracking, and building infrastructure. This was double the companies’ capital spending as of 2005, according to Ernst & Young.38
In 2008, before it hit serious financial turbulence, Chesapeake Energy signed up for aggressive “cash and carry” deals to help finance its growth. Plains Exploration paid $1.7 billion for ownership of one-third of Chesapeake’s ownership of drilling rights it controlled in the Haynesville Shale. Plains further committed $1.7 billion to underwrite Chesapeake’s drilling costs, in return for a percentage of profits. But while Chesapeake spent an average of $7,100 an acre on the drilling sites it leased in the Haynesville, Plains paid Chesapeake the equivalent of $30,000 an acre, according to the New York Times. The bankers who orchestrated the deal made some $23 million on it.39
Drilling firms like Chesapeake, Petrohawk, and Exco Resources had also signed “use it or lose it” leases with landowners, which required them to start drilling within three to five years and begin paying royalties to the owner, or forfeit their drilling rights. As gas prices dropped, they were forced to spend a lot more money producing gas than they could sell it for; the economics no longer made sense.
“Quit drilling,” T. Boone Pickens, the Dallas oil and gas billionaire, warned his fellow board members at Exco. In the 1990s, Pickens lost control of his energy company, Mesa, when prices dipped and he couldn’t support the debt load. But Exco had made a $650 million deal with BG Group, an English gas company, when times were good. When gas prices slipped, Exco was contractually bound to keep its 22 rigs hitting production targets in the Haynesville Shale. Pickens was miffed. “We are stupid to drill these wells,” he bluntly told the New York Times.40
A third element that has kept prices from rising involves geology. As mentioned in chapter 1, shale deposits can be “dry”—meaning they produce only natural gas (mostly methane)—or “wet”—meaning they also produce liquid natural gases (LNGs), such as ethane, butane, and propane. LNGs are used to make plastics, to power industrial heaters, or to produce the flames in your home barbecue. LNG prices are linked to the price of crude oil, which—unlike gas—is set globally and is relatively high.41 As natural gas prices dropped, drill rigs have been shifted from dry to wet shales, boosting supplies; but this has also led to a glut of LNGs, and their prices will eventually fall.
In retrospect, it should have been obvious that with so much money flowing into drilling and so many new wells being hydrofracked in such a short amount of time, the natural gas bubble would burst. But, as with the Internet and real-estate bubbles of recent years, the savvy players were publicly predicting that gas supplies will last “for a hundred years” while privately expressing doubts.
In August 2008, Aubrey McClendon, then still CEO of Chesapeake Energy, told analysts that he had tamed the once risky, wildcatting oil and gas business and turned it into a regular, boring “manufacturing business that requires four inputs … land, people, science and, of course, capital.” But as internal documents revealed by a lawsuit show, just two months later McClendon e-mailed his executives: “What was a fair price 90 days ago for a lease is now overpriced by a factor of at least 2x given the dramatic worsening of the natural gas and financial markets.”42
Global behemoths like ExxonMobil and Royal Dutch Shell can afford to play for the long term and have the resources to cut costs and develop efficiencies. Gas prices will eventually rise, but for the near term the industry is suffering the aftermath of its rapid growth spurt.
“What was true yesterday is no longer true today,” notes Andrew Place, of EQT Corp, a gas exploration firm based in Pittsburgh. “Systems are evolving.… Public concerns have pushed the engineers to come up with solutions.”43
Where some see risk, others see opportunity. By now hydrofracking has become a large, well-funded business that is not likely to disappear soon. Given this reality, a growing cadre of entrepreneurs and idealistic academics have been drawn to the industry with the intention of “doing well by doing good” in the shale oil and gas fields.
Graduate students, entrepreneurs, venture capitalists, and energy companies large and small are betting that more efficient hydrofracking technologies—such as new ceramic proppants designed with the help of nanotechnology by a Rice University consortium—and better wastewater management, which has caught the attention of global firms like Schlumberger and small firms like Ecologix, of Alpharetta, Georgia, will be a profitable, expanding business for the foreseeable future. “Hopefully, we’ll mend the dispute between environmentalists and oil companies by answering the wish list of both,” Ecologix CEO Eli Gruber explained to the Wall Street Journal.44
Indeed, as I discuss in chapter 6, one of the most contentious aspects of hydrofracking is contained within its name: the use of millions of gallons of water—at least 70 billion to 140 billion gallons of H2O annually, according to the EPA—to frack 35,000 wells a year.45 This is a serious issue in this day of global warming and population growth. As a Schlumberger representative told a conference recently, if one million new wells are fracked worldwide by 2035, then reducing drillers’ use of fresh water “is no longer just an environmental issue—it has to be an issue of strategic importance.”
Some innovative companies have seen the writing on the wall, and asked: what else can we hydrofrack with?
In hundreds of small gas projects across Canada, and in a few test wells in the United States, drillers have replaced the water in their fluids with liquefied propane in gel form.46 This substitution has a triple benefit: it preserves water supplies, which is increasingly important in drought-prone places like Texas, California, and Alberta; it limits the chance of polluting surface water and groundwater with spilled chemicals; and it removes the chance of setting off earthquakes by injecting wastewater into fault zones.
Using propane gel is essentially the same process as hydrofracking, with an added twist. As with water, the gel is pumped deep underground at tremendous pressure, which creates fissures in shale and releases bubbles of natural gas. Like water, the gel carries sand or man-made proppants to hold the fractures ajar so that gas can escape. But unlike water, the gel is turned into vapor deep underground by heat and pressure, and then flows to the surface with the natural gas, where it is recaptured; sometimes the used gel is reused or resold. Also, unlike water, propane does not wash chemicals or naturally occurring salts and radioactive elements back to the surface.
Gasfrac, a Canadian company, used propane in place of water in over 700 wells in 2012 in the provinces of Alberta, British Columbia, and New Brunswick, and has drilled test wells in several states, including Texas, Colorado, and Pennsylvania.47 Boosters of propane fracking have grand ambitions and imagine the day, as one put it, when “the oil and gas industry could even be a net producer of water rather than a net user.”
But wider use of propane gel is hampered by high cost, limited data about its effectiveness (largely because intensely competitive drilling companies are loathe to share information about innovations), and the industry’s resistance to change.
The remediation (cleaning) of wastewater is another hydrofrack-related business that has seen meteoric growth recently. Ecosphere Technologies, of Stuart, Florida, uses a process called “advanced oxidation.” In the chemical-free treatment, ozone is used to eliminate the chemicals used for bacteria control and scale inhibition, and recycles 10 percent of the water, according to the company.48
Other companies use “tunkey solutions,” which allow drillers to clean water on site and to authenticate the results with tests. WaterTectonics, for instance, is a rapidly growing firm that uses electric currents to bind together contaminants, allowing them to be cleaned from the water. The company, which has a global licensing agreement to clean hydrofracking fluids for Halliburton, tripled its staff and finances between 2009 and 2011, the company said.49 While the drop in gas prices impacted WaterTectonics, “the opportunity in frack water treatment is a very large market that is predicted to grow at an accelerated rate over the next ten years,” said TJ Mothersbaugh, the company’s business development manager.
One of the most promising new ideas for reducing water contamination, or at least lowering the “dread-to-risk ratio” that shadows hydrofracking, is to inject fluids with “tracers” in order to track where they flow deep underground. But the public is wary of the man-made radioactive or chemical tracers currently used (mentioned in chapter 6), and now universities—such as Rice University in Houston—and companies—such as Southwestern Energy—are working to develop new technologies. The new tracers are stable, nontoxic, noninvasive chemicals with a unique “signature” for long-term fluid identification.
The mitigation of hydrofracking pollution is even attracting young, idealistic entrepreneurs. One approach under development by BaseTrace, a new company founded by a group of Duke University graduate students, uses an inert DNA-based tracer. DNA can provide a near-infinite number of sequence variations, so unique tracers can be tailored to individual wells. The BaseTrace product is robust and can withstand high temperatures and pressures, the company says. Just a thimbleful of the tracer can be detected, even when mixed with millions of gallons of fluid. The company hopes to introduce its tracer by late 2013 and is testing ways to identify groundwater pollution over long distances. “We really hope to make a difference by providing answers where previously there were none,” wrote Justine Chow, BaseTrace’s CEO.50
Responding to a perceived decline of government oversight, SkyTruth, a nonprofit environmental monitoring group in West Virginia, created a real-time alert system that uses remote sensing and digital mapping to track pollution events. Founder Jon Amos says that “more and more the burden is going to be on the public to keep an eye on what’s happening in the environment.”51
SkyTruth has released a database created from over 27,000 industry reports on the chemicals used in hydrofracking, and made it freely available to the public. Monitoring the impacts of drilling in the Marcellus play in West Virginia, Pennsylvania, and New York, SkyTruth’s alert system sends an e-mail update when a new event occurs. Alerting property owners that a natural gas well is about to be drilled nearby allows them to test their well water before, during, and after the hydrofracking process. “Our hope,” said Amos, “is that this information will promote discussion.”
In another instance of citizen initiative, Jamie Serra, who works for the Pennsylvania state legislature, created Fracktrack.org, a site that coalesces massive amounts of information about gas development in one site. The notion is to rely on thousands of data points to enhance transparency and understanding, to eliminate bias, and to help citizens understand what’s happening around them.
“After seeing how many people were looking for information that existed but wasn’t made readily available by the government,” Serra said, he decided to “help complete missing and inaccurate data sets that are poorly designed and aren’t mandated.… The numbers are no longer worth arguing over when we have the ability to generate and verify millions of responses in real-time.”52
There are also ways for communities and even individuals to identify gas leaks and map drilling activities. These are not substitutes for effective regulation, but they can be useful supplements. Some concerned citizens have banded together as “methane monitors,” to search out and report gas leaks around hydrofracking sites. They could potentially be compensated for this investigative work with rewards worth thousands of dollars under the Clean Air Act, much like “watershed watchdog” citizen groups help enforce Clean Water Act regulations.53
Josh Fox, the director of GasLand, and other “fracktivists” advocate the use of infrared video cameras to show methane emissions from gas and oil facilities. This can be an empowering tool, though one drawback is that people who don’t properly decipher infrared images confuse standard heat emissions with methane emissions. Some experienced environmentalists, such as Walter Hang, who compiles data maps at his company, Toxic Targeting, warn that well-intentioned but error-prone citizen initiatives can undermine more professional efforts.54
In 2010, Congress requested that the EPA study the extent of hydrofracking’s impact on the environment. In 2011, for the first time, the EPA chose seven natural gas plays on which to conduct case studies.55 Two spots—in the Haynesville Shale, in DeSoto Parish, Louisiana, and in the Marcellus Shale in Washington County, Pennsylvania—were chosen because they had not yet been hydrofracked. The study also includes five places that have been hydrofracked—the Bakken Shale in Kildeer and Dunn counties, North Dakota; the Barnett Shale in Wise and Denton counties, Texas; the Marcellus Shale in Bradford and Susquehanna counties, Pennsylvania; the Marcellus Shale in Washington County, Pennsylvania; and Raton Basin in Las Animas County, Colorado. Results of the study are expected in 2014. “The value of these tests is that they are really the first independent review of what’s happening from start to finish. It is a data set that doesn’t really exist right now,” Briana Mordick, a Natural Resources Defense Council scientist, has said.56
People on both sides of the debate agree that a broad and rigorous measurement of hydrofracking’s impact on groundwater supplies is long overdue. Groundwater lies in deep aquifers far from sight, recharges slowly through precipitation from the surface, and can extend through subterranean chambers for hundreds of miles. (The Ogallala Aquifer, the nation’s largest groundwater source, extends some 174,000 square miles beneath eight states. It has been in the news recently because the proposed Keystone XL pipeline was originally designed to cross over it in Nebraska, raising fears that an oil spill could contaminate the aquifer.) Once polluted, groundwater is notoriously difficult to clean. The crucial aspect to such a study would be a systematic sampling of the site prior to drilling, during drilling, and after drilling. This is accomplished with monitoring wells drilled in and around a hydrofracking site. The EPA is now in the midst of such a study.
To gauge the impact of hydrofracking on water supplies, the EPA is conducting a landmark nationwide study of 24,925 wells that were drilled with the process between September 2009 and October 2010. The agency opens its report with the assertion: “Natural gas plays a key role in our nation’s clean energy future.… However, as the use of hydraulic fracturing has increased, so have concerns about its potential human health and environmental impacts, especially for drinking water.”57 The study includes 18 research projects that will attempt to answer important questions about the use of water in five distinct stages of hydrofracking: from water acquisition to chemical mixing, well injection, flowback, and produced water, to wastewater treatment and waste disposal.
The study includes extensive mapping, a review of published literature, data analysis, scenario planning, computer modeling, laboratory studies, and case studies. It will focus on identifying ways that hydrofracking could contaminate drinking water on the surface and underground, including the role of elevated levels of methane. The study will not address other sensitive questions, such as possible links between hydrofracking and earthquakes or geochemical changes, however. (The Department of Energy and academic institutions are studying these questions.)
In January 2013, Chesapeake Energy agreed to let the EPA test an active drilling site (the EPA has not revealed the location of the test site). Range Resources has also agreed to let the EPA conduct tests at one of its wells in Washington County, Pennsylvania.58 The companies may have calculated that if they can pass government inspection, public sentiment will shift in their favor, and government cooperation will become that much easier to win.
But the stakes are high: both regulators and industry executives say the EPA study will have a significant impact on the way hydrofracking is managed going forward.
A National Research Council report found that by increasing the efficiency of our vehicles, and using new technologies like biofuels and batteries, US cars and trucks could operate 50 percent more efficiently in 20 years.59
As we have seen, the shale gale has already changed the way the United States uses energy. Electric companies are forsaking coal for gas-powered turbines, and petrochemical companies are bringing their overseas facilities back to produce plastics in the United States for the first time in decades. But the holy grail of natural gas is in the gas tank of our cars.
Seventy percent of the oil consumed in America is used for transportation, a sector that emits more than 30 percent of our greenhouse gases.60 Not only is natural gas cheaper than oil, but its emissions have a smaller impact than gasoline and diesel.
While many fleets of commercial trucks and city buses use natural gas, switching over passenger cars to natural gas is a much higher bar. There are four models of gas and dual-fuel cars for sale in the United States, and certified aftermarket conversion kits can be used on 40 models of cars and trucks, at a cost of $12,000 to $18,000.61
One drawback of natural gas cars is they cost thousands of dollars more than gasoline-powered ones—largely because the gas tanks must be bigger and heavier to store the fuel under pressure. (The Honda Civic GX, for instance, costs $5,200 more than a comparable gasoline vehicle.)62 This could change in the future, however. Researches at companies like 3M are developing lighter fuel tanks or tanks that store natural gas at lower pressures.
There are few gas-powered cars available, which keeps costs high, and only 1,500 public fueling stations nationwide (only half of which are publicly accessible), according to the Wall Street Journal. But the economies of scale could build over time, especially once people understand how much money they will save. A comparable amount of natural gas can cost about half as much as gasoline, when it is at $4 a gallon (as of this writing in mid-2013, average gas prices nationwide are $3.78 per gallon, according to AAA).63
And there is the psychological hurdle. Many are afraid that natural gas will cause their cars to explode. This is not likely. For combustion, oxygen would need to mix with the methane in a gas tank and be ignited. CNG tanks are hardened against rupture and designed to vent rather than burst into flames.
In countries that lack gasoline-refining infrastructure—such as Pakistan and Iran—the governments have mandated a switch to natural gas.64 In Russia—the world’s second-largest gas producer after the United States—Gazprom, the state-owned energy monopoly, considers gas “a profitable core business” and is planning to create “a vast natural gas market” for cars, the company said in a statement.65 Gazprom will be the exclusive supplier of natural gas for a new, green race-car series, the Volkswagen Scirocco R-Cup.
Some global energy firms, like Royal Dutch Shell, have turned natural gas into a low-sulfur diesel fuel that can be used in conventional cars and pumped at regular filling stations—though the process is not cheap.
With the right policy incentives in place, however, gas-powered vehicles could “increase the nation’s energy security, decrease the susceptibility of the US economy to recessions caused by oil-price shocks, and reduce greenhouse-gas emissions,” writes Christopher Knittel, a professor of energy and economics at MIT.66
China generates about three-quarters of its electricity with coal-burning plants and produces twice as many greenhouse gases as the United States does every year. As the world’s second-largest economy (after the United States), China increased its coal-fired generating capacity by 50 gigawatts in 2012, roughly equivalent to seven times the annual energy use in New York City. The country’s breakneck growth is unlikely to slow down in the near term, and to keep pace it opens a new coal-powered plant each week. Consequently, the rate of China’s greenhouse gas emissions increases 8 to 10 percent per year; by 2020 it will emit greenhouse gases at four times the rate of the United States.67
Climate scientists, such as those at the nonprofit research group Berkeley Earth, are alarmed by the environmental impact of China’s growth and advocate that the United States help China switch from coal to natural gas.68
As noted, modern gas-fired power plants emit a third to a half of the carbon dioxide produced by coal plants producing the same amount of energy. China has vast shale formations and a budding gas industry. The EIA calculates that China has 1.3 quadrillion cubic feet of technically recoverable gas reserves in 2011, nearly 50 percent more than the United States has.69 Yet China has limited knowledge of hydraulic fracturing, a voracious appetite for power, endemic corruption, and some of the worst pollution in the world. The government has recently begun to auction off drilling rights to shale gas plays in China, and many of the purchasers have little or no experience in energy production. Hydrofracking opponents fear the worst from this combination.
Yet, as most American drillers have shown, hydrofracking can be done in a relatively clean, responsible way. If China can set tough but fair environmental standards and enforce them, it will avoid delivering an unprecedented load of heat-trapping gases to an already overheated climate. Should China switch from coal to natural gas power, it could reduce its emissions by more than 50 percent, Berkeley Earth estimates.70 It would also buy experts around the world time to develop new, cleaner, sustainable energy sources.
As the veteran environmental reporter Andrew Revkin has blogged for the New York Times, “This is how the world works, for better and worse.” Revkin then offers his summary: “Energy needs and economic forces drive innovation, both in using energy more thriftily and finding new sources. Environmental issues arise. Pressure builds for change. Regulations and rules evolve. Industry resists. Lawsuits and environmental campaigns ensue. Innovations occur. And the human enterprise, often in herky-jerky fashion, moves forward.”71