Noah Addis / for NBC News

Dairy farmer Carol French holds a jar of water taken in July 2012 from the tap in her home in Sheshequin Township, Pa. French says her water first turned cloudy in March 2011, not long after natural gas companies began conducting hydraulic fracturing, or fracking, nearby.

BRADFORD COUNTY, Pa. — Carol French still has the canning jar full of cloudy and gelatinous water that came out of her well right before her daughter got sick and some of her 40 milk cows developed a rash. She agrees that this jar, by itself, proves nothing about the environmental impact of "fracking," the drilling technology largely responsible for America's boom in oil and gas production. You can't determine the environmental effects of drilling and fracking from one person's Mason jar full of water.

"I can't say it's definitely from the drilling, but there's strong circumstantial evidence," French said, referring to nearby natural gas drilling using fracking.

Making that direct connection often isn't possible even with 1,100 jars. That's how many examples are on a "list of the harmed," people who have offered personal stories of harm from fracking, as tallied by the advocacy group Pennsylvania Alliance for Clean Water and Air. 

Beyond such anecdotes, many facts about fracking's impact on the environment remain hotly contested. Consequences like water contamination have been established, but often it is not clear if they were directly caused by fracking or the result of sloppy drilling practices.

Meanwhile, the scientific studies that do exist suggest there are inconvenient truths for both sides of the fracking debate to confront.

The biggest hurdle for the pro-industry side: The rapid expansion of fracking over the last five years has resulted in confirmed cases of drinking water contamination, a house explosion, and air pollution.

But for those who oppose fracking, there is this: Burning the natural gas produced by fracking may be much better for the environment and public health, over the long run, than burning coal.

As detailed in the first three installments of Power Shift, an NBC News/CNBC special report, the United States is experiencing an energy boom created by new drilling technologies that have unlocked vast domestic oil and natural gas reserves. Proponents of fracking praise its economic benefits, while many foreign policy experts say this developing energy independence may give the U.S. new leverage in world affairs.

Many experts say that concern about the environmental consequences of fracking and other new drilling technologies may be the biggest obstacle to the continued growth of this newfound domestic energy supply. 

The  future of the industry may depend on whether more cases of environmental damage are documented, and whether they are regarded as unlikely accidents or the inevitable consequence of this expanding search for energy resources. That could, in turn, lead to stricter regulation that could slow or halt new drilling.

NBC News

Interactive map: Where the U.S. produces its energy. Click to enlarge

For now, your view of the energy boom may depend on whether drilling and fracking are happening in your back yard, as they have been in Carol French's back yard in northeast Pennsylvania since 2008. Bradford County is the busiest fracking county in the state. Just across the border, in New York, Gov. Andrew Cuomo is considering whether or not to allow fracking, which he says would take place only under "toughest-in-the-nation" environmental regulations. Much of the countryside in both states sits above the Marcellus Shale, the gas-rich band of rock that stretches to Ohio and West Virginia.

Water issues are in dispute 
To get the natural gas out of crevices deep underground, companies must pump in vast quantities of water and sand, under enough pressure to fracture rock and release the gas trapped inside. Also in the slurry that comes back up as waste water: toxic chemicals, including some that cause cancer, damage the nervous system, disrupt hormones and mutate genes. And those are just the ones we know about. Oil and gas companies in some states haven’t been compelled to say what’s in their brew, so some don’t.

The companies say the health risks are minimal. As of August 2011, oil and gas companies still said there had never been a documented case of drinking water contaminated by fracking. (The industry claim may still technically be true, using the industry definition of "fracking" to refer only to the process that happens after the drill hole is dug, not the drilling activities necessary before the fracking can occur.)

Reuters

How fracking works. Click to enlarge.

The first blemish on the industry's clean record came in a New York Times article documenting such a case from the 1980s. (Demonstration projects for hydraulic fracking began decades earlier in the U.S., though it didn't become common until the early 2000s.) Then came the most-publicized case of well-water contamination near fracking operations, in Dimock Township, Pa., just east of Bradford County; the federal Environmental Protection Agency said in 2012 that preliminary results found the water was safe to drink, though it did contain chemicals as well as explosive methane. Those results have been debated. The nonprofit investigative news organization Pro Publica has reported numerous confirmed health and safety problems related to drilling and fracking, including a house explosion near Cleveland, Ohio, after gas leaked into the home's water well.

Fracking is now regulated almost entirely by the states, though the EPA is slowly moving toward federal regulation. In the meantime, government has only lightly tapped the brakes to tighten regulation of the industry.

Drinking water contamination has been the biggest public relations problem for the industry. But the contaminants can come from several sources: from the hydraulic fracturing process itself, from the waste water, from the pits where drilling chemicals are stored, or from transporting chemicals and wastewater. The industry says that examples of contamination are very rare. Lisa Jackson, who was then then the EPA administrator, echoed the industry position that problems aren't systemic to fracking. "If you get a bad operator in there, somebody who’s not responsible, who’s not seeing how important it is to get this right, they can contaminate an aquifer," she said in a June 2011 talk. Environmentalists argue that pollution is an unavoidable part of the drilling process, not the result of shoddy practices.

It’s theoretically possible, though unproven, that some of the tainted water and dangerous gases might travel through deep underground crevices to unexpected places, such as the aquifers used for private wells and community water supplies. A July 2012 study by researchers at Duke University and California State Polytechnic University at Pomona found that salty water from deep underground could make its way into drinking water near the surface.

At the surface, there have also been outright accidents, leaking oil and toxins. Well casings have cracked, and sometimes pumping in more concrete for a "squeeze job" to stop the escaping water and chemicals won't stop the damage.

In Bradford County, the pleasant pond at the vacation home of Truman and Bonnie Burnett is a murky swamp, ringed by dead trees, after tens of thousands of gallons of drilling fluid spilled in 2009 from the property of their neighbor, who had signed a gas lease. His wife won't come back to their vacation home anymore, Truman Burnett says, so he has nailed a framed photo of her on a tree.

An industry lobbying group in North Dakota, where fracking is common, said the industry is doing what it can, but some mistakes are inevitable.

"You're going to have spills when you have more activity," Ron Ness, president of the North Dakota Petroleum Council, told a reporter with the investigative journalism organization Pro Publica, which documented more than 1,000 accidental oil spills in North Dakota in 2011.

Related story

Sorting through the claims, counterclaims about environmental impact of 'fracking,' 

Advice for a neighbor
"Our water changed on March 15, 2011," said Carol French, the dairy farmer, a few months after the drilling began in December 2010. What remains unclear is whether health issues experienced by her daughter and some of her cows afterward were caused by the turbid tapwater.

"My daughter was 24 at the time," French said. "She had a high fever for three days. I thought she had the flu. She had stabbing pains in her abdomen, and diarrhea. ... When I took her to the emergency room they checked her urine and blood to only find that the white blood cell count was high in her urine not in her blood. They then did a MRI to find that she had 'free floating fluid' in her abdomen, and her spleen, liver, and right ovary were enlarged. They didn't know what was wrong with her."

Then her daughter went to stay with a friend while looking for work. "Nine days later, all symptoms were gone and she was acting like herself," her mother said.

When she came back to visit, the symptoms returned. "When I would visit my daughter, my rashes would disappear, but return within five days after returning to my home. Our cattle seem to have breeding problems, but I can't say it's strictly due to my water changing without tests being done."

Now she has bad water a few times a month. When the tap water gets cloudy, she drives around to the nine gas well pads within a mile of her farm, writing down which ones have trucks and men working. She agrees that alone is a fruitless way of identifying a cause.

Slideshow: Drilling down and out in Texas

Jim Seida / NBC News

Watch a drilling crew at work near the small town of Garden City as they drill an oil well that eventually will extend more than a mile deep and a mile sideways in the Permian Basin.

Launch slideshow

She hasn't tested her water yet; nor has the state Department of Environmental Protection. They've been squabbling over the rules of how to test and whether the state will act if the results implicate the fracking operations. It's going to cost her $3,200 to get a lab to test for all the acids, detergents and poisons that companies say they use for fracking – or hydraulic fracturing – to break up underground shale and remove oil and natural gas.

Meanwhile, she tests her water for coliform and E. coli bacteria, meeting USDA and FDA standards for a dairy operation, and she ships the milk off to America's food supply.

No studies have found fracking chemicals have entered the food chain. Two Cornell University researchers have reported health impacts on cattle near drilling operations, but industry backers called the study "deeply  flawed."   

French started out as a supporter of fracking. She signed her own gas lease to allow fracking on the farm near Ulster, pocketing $13,600 starting back in 2006, but no company drilled on her land. Now she questions the economic benefits of fracking and worries about the environmental consequences.

"The standards of yesteryear," she said, "do not meet the industrial activities surrounding us. Like my milk inspector told me, 'You cannot find something you are not looking for.'"

A lot of her neighbors in the county, however, have put serious money in their pockets.

Among them is Robert "Bob" Wilmot, a former pipefitter who was able to rebuild a bed and breakfast he runs with his wife ("the best cook in the county," he says) in the small Bradford County town of Rome. He got $5 an acre for a gas lease on his 250-plus acres, then $75,000 more to let the gas company turn his hay field into a pond, and another $25,000 to allow a pipeline. Everyone in the county has heard stories of people making hundreds of thousands, even millions for one of the big compressor stations that send the gas down the pipeline. When the gas rush began here, churches put up signs such as "Thank God the gas companies are here."

Wilmot says he has confidence in the gas companies, and if anything he believes the state regulators are too tough.

But Wilmot does have a few reservations. Asked what advice would he offer to the people ten miles up the road in New York, which is considering fracking, he replied. 

"I'd go ahead. I wouldn't be in favor of putting fracking over by the Finger Lakes. That's a beautiful area. You can't replace them lakes."

Bill Dedman is an investigative reporter for NBC News; he reported from Pennsylvania. Karen Weintraub is a freelance health and science reporter in Boston.

More from Power Shift, an NBC News/CNBC special report:

Part 1: Energy boom dawning in America

Part 2: Oil, gas sector fuels US economy

Part 3: How the energy boom could shake up the global order

Without fanfare, China passed the United States in December to become the world's leading importer of oil – the first time in nearly 40 years that the U.S. didn’t own that dubious distinction. That same month, North Dakota, Ohio and Pennsylvania together produced 1.5 million barrels of oil a day -- more than Iran exported.

As those data points demonstrate, a dramatic shift is occurring in how energy is being produced and consumed around the world – one that could lead to far-reaching changes in the geopolitical order.

U.S. policy makers, intelligence analysts and other experts are beginning to grapple with the ramifications of such a change, which could bring with it both great benefits for the U.S. and potentially dangerous consequences, including the risk of upheaval in countries and regions heavily dependent on oil exports. 

But many experts say the U.S. would be the big winner, in position to reshape its foreign policy and boost its global influence. 

"People already are looking at the U.S. differently, seeing the U.S. as much more competitive in the world,” said energy analyst and author Dan Yergin, saying that he first noticed the change in the world view of the U.S. at the World Economic Forum in January in Davos, Switzerland.

Slideshow: Drilling down and out in Texas

Jim Seida / NBC News

Watch a drilling crew at work near the small town of Garden City, Texas, as they drill an oil well that eventually will extend more than a mile deep and a mile sideways in the Permian Basin.

Launch slideshow

As detailed in the first two installments of Power Shift, an NBC News/CNBC special report, the United States is reaping the benefits of an energy boom created by new drilling technologies that have unlocked vast domestic oil and natural gas reserves. Coupled with decreasing demand due to energy efficiency and continued cultivation of alternative energy sources, an increasing number of experts believe the U.S. could achieve energy independence by the end of the decade – realizing a dream born during the gas crisis of 1973.

But who would be the global winners and losers in such a scenario?

Most U.S. policy makers and experts agree that the U.S. and its allies – particularly its North American neighbors -- would be the biggest beneficiaries.

Boom helps Iran sanctions stick
In fact, they say, the West already has realized one major benefit: the success of international sanctions against Iran over its nuclear program.

Carlos Pascual, the State Department’s coordinator for international energy affairs, noted last month at the CERAWEEK energy conference in Houston that increased U.S. oil production, coupled with a boost in exports from Iraq and Libya, has kept oil prices stable despite the loss, because of sanctions, of up to 1.5 million barrels a day in Iranian exports.

“What this has taught us, and helped underscore, is that within the world we live in today, hard security issues and energy policy issues have become fundamentally intertwined,” he said.

NBC News

Interactive map: Where the US produces its energy. Click to enlarge.

Yergin, who also is a CNBC energy consultant and author of the energy-focused nonfiction best-sellers "The Quest" and "The Prize," put it this way: "People talk of the future impact. The increase in U.S oil production has already had an impact: Sanctions wouldn't have been effective without U.S. oil production. …  We've added (within the last year) almost as much as Iran was exporting before sanctions.”

Hossein Moussavian, a former Iranian ambassador to Germany and nuclear negotiator who's now a fellow at the Woodrow Wilson School at Princeton University, said "the radicals" in Tehran failed to foresee the changing energy picture, believing that sanctions wouldn't be imposed and that, if they were, they wouldn't work because oil prices would surge.

"The Iranian mistake was to believe …  the threats of referring Iran to the United Nations Security Council, imposing sanctions, was just a bluff," he said.

In the longer term, observers say that the Organization of Petroleum Exporting Countries (OPEC) and many of its member nations are likely to be the biggest losers if the U.S. continues to cut oil imports, likely decreasing oil prices in the process.

"A dramatic expansion of U.S. production could … push global spare capacity to exceed 8 million barrels per day, at which point OPEC could lose price control and crude oil prices would drop, possibly sharply," the U.S. intelligence community's internal think tank, the National Intelligence Council, said in its “Global Trends 2030” report in December. "Such a drop would take a heavy toll on many energy producers who are increasingly dependent on relatively high energy prices to balance their budgets."

With some analysts predicting that oil prices could drop as low as $70 to $90 a barrel – down from the current price of nearly $110 per barrel of Brent crude oil – a “scramble” among OPEC members for market share could ensue, said Edward Morse, an energy analyst with Citigroup and co-author of a recent report on titled “Energy 2020: Independence Day.”

An International Monetary Fund analysis indicates that many major oil-producing states need more than that lowest price level to meet their budgets and would be forced to increase output or reduce spending, which could trigger unrest. Among them, according to the report: Iran, Libya and Russia, at $117 a barrel; Iraq, $112; Yemen, $237; and the UAE, $84.

Iraq, which has had production from its rich oil fields curtailed by war or sanctions for half of the 53 years of OPEC’s existence, poses another challenge to the organization.

Now that it’s finally free of such interference, its production is increasing by between 500,000 and 900,000 barrels a year, making it the second fastest growing oil-producing country in the world after the U.S. 

“And, by God, no one’s going to impose any quota limitations on them,” said Morse, referring to Iraq’s OPEC partners. “So part of the challenge to OPEC is internal as well as external.”

Can Saudis maintain market-maker role?
Analysts say OPEC heavyweight Saudi Arabia, which controls vast reserves of oil and needs $71 a barrel to meet its budget, according to the IMF, will do everything it can to remain the market-maker. But in that role, it will face new challenges, they say.

“Over time, it should become increasingly challenging for Saudi Arabia to ‘overproduce’ and bring down prices to punish wayward OPEC members; without this disciplinary mechanism, it is unclear whether OPEC can remain cohesive,” according to the Citigroup report.

For its part, OPEC professes to be not unduly alarmed by the U.S. oil and natural gas boom. It highlights the "considerable uncertainties" surrounding wells drilled using hydraulic fracturing, or “fracking,” and associated technologies.

Yergin said he believes that the Saudis will be able to withstand the turbulence, and that they will provide a buffer for the organization’s lesser producers.

“It's too quick to write the obit for OPEC,” he said. “… The Saudis will figure it out. They are re-orientated to Asian markets, turning left instead of right.”

But some members of the oil cartel -- particularly Nigeria and Angola -- already are feeling the impact of the U.S. production surge, according to the Citigroup report. U.S. imports from the two countries dropped to 700,000 barrels a day at the end of 2012, down from 1.6 million barrels in 2007. That’s because U.S. production of light, sweet crude -- the kind of oil the West African nations produce -- has burgeoned in recent years. Citigroup forecasts that by the end of 2013, the market for Nigerian oil at Gulf Coast refineries could entirely dry up.

Longer term, say by 2020, cheaper heavy oil from Canada, freed from the so-called oil sands by new recovery technologies, could push similar oil from Venezuela out of the U.S. Gulf Coast market,  (assuming the Obama administration approves construction of the Keystone XL pipeline to carry it), according to forecasts.

Mexico also is expected to increase production, offering the U.S. access to another convenient and friendly provider.

"The Eagle Ford formation in Texas extends into Mexico and if you look at the Gulf, you'll see thousands of black dots marking oil platforms on the U.S. side but nothing on the Mexican side,” said Yergin. “That's changing. There is a political consensus among the three major parties on energy. You will see less immigration from Mexico. Mexico could become more of a BRIC (the term used for fast-developing economies like Brazil, Russia, India and China) than Brazil."

Besides guaranteeing a stable domestic energy supply, those energy resources add tools to the U.S. diplomatic toolbox, said David L. Phillips, director of the Peace-building and Human Rights Program at Columbia University.

"Why permit ourselves to be held hostage to regimes hostile to our national interests and who give safe harbor to those who would do us harm?" he asked. "… The glaring example is Venezuela. (Hugo) Chavez was so strongly anti-American and he was providing energy to our enemies. They should pay the price for non-cooperation."

Current and former diplomats note that the U.S. also could use its increased natural gas production to weaken rival Russia’s near monopoly on natural gas exports to Europe, via its state-controlled energy giant Gazprom. Already, declining prices fueled by the U.S. boom have benefited the European market.

"What has emerged is a competitive market that allowed the utilities of Western Europe to renegotiate their contract with Gazprom, affecting both prices and financing terms," said the State Department’s Pascual.

Adding to the pressure, the U.S. firm Cheniere Energy last month signed a 20-year deal to export enough liquefied natural gas to the British utility Centrica PLC to heat 1.8 million homes starting in 2018 – the first pact of its kind.

Growth slowing in China, India
As for China and India, both of which are expected to import increasing amounts of energy for years to come, analysts see indications that economic growth is slowing in both countries.

“In a pattern similar to the abrupt slowdown in demand growth seen in the Asian Tigers in the 1990s, Chinese demand growth has slowed to a more tepid 3 (percent) to 5 percent rate as compared to the double-digit growth seen in the early 2000s,” said a Citigroup report by analyst Seth Kleinman released last week.

That slowdown is in part due to the diminishing competitive edge that China enjoys over the U.S., Yergin said.

“Chinese wages are going up 20 percent a year. U.S. energy efficiency and increased production helps the U.S. in the mix on the global competitive landscape, he said, noting that Dow Chemical recently announced it will invest $4 billion in U.S. petrochemical production. “…That doesn’t happen without the U.S. advantage in energy.”

Citigroup's Morse and other analysts said the slowing Chinese economy and energy insecurity could prompt China to more militarization in the Far East -- a dangerous development in a region already beset by nationalist disputes and where the U.S. is expected to focus increasing attention. But none suggests that the Chinese are likely to challenge the United States as a global power, saying Beijing has neither the military assets nor the desire. Its strategy remains regional and attuned to "short-range engagements," Morse wrote.

The impact of the rebalancing of global energy production could be more severe in other nations.

Trevor Houser, a former energy analyst in the Obama administration State Department, worries about the prospect of failed states.

"If you look at the consequences of more U.S. production and reduced sales from OPEC, some would see that as a benefit," said Houser, now a partner with New York-based Rhodium Group, a global market analysis firm. "But starving those economies of oil revenue will surely have disruptive effects. It is not necessarily a good development for U.S. foreign policy and geopolitical stability in general."

AP file/Hassan Ammar

A U.S. F-18 fighter jet, left, lands on the aircraft carrier USS Abraham Lincoln as a U.S. destroyer sails alongside during exercises in the Persian Gulf in 2012.

Houser also said that U.S. energy independence could lead to isolationist policies, but will not insulate Americans from global price disruptions.

"The price Americans pay at the pump will still be determined by events in the global oil market, yet falling U.S. oil imports (are) going to reduce political support for safeguarding those global markets, and no one is willing or able to step up to the plate to replace us,” he said. “... The U.S. economy will still be vulnerable if someone blows up a Saudi port."

More from Power Shift, an NBC News/CNBC special report:

Part 1: Energy boom dawning in America

Part 2:  Oil, gas sector fuels US economy

That issue – specifically, “Do we leave the Middle East once our energy needs are secure?” – came up at the World Economic Forum in Davos, Switzerland, in January, said Yergin, recalling that “an oil minister came up to me and said, ‘Please don’t leave us.’”

Pascual, the State Department official, argues that such fears are overblown.

"These changes in no way change the U.S. commitment to global security, to peace and stability in the Middle East and to security in the transit lanes,” he said, referring to oil shipping routes. “Some people have asked is the United States going to become disinterested. The answer is no. It is absolutely in our self-interest to stay engaged.”

Richard Engel is NBC News' chief foreign correspondent; Robert Windrem is a senior investigative producer. 

Coming next Monday: Digging into the environmental consequences of 'fracking' 

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An Open Channel post last week from the Food & Environment Reporting Network drew the attention of Steve Everley, a spokesman for Energy In Depth, a research and public education program of the Independent Petroleum Association of America. Here is his rebuttal to the article, which appeared in a longer form in The Nation.

A recent article in The Nation magazine, in collaboration with the Food & Environment Reporting Network (FERN), made a series of declarations and assertions about the impacts of hydraulic fracturing, specifically with respect to agriculture and America’s food supplies. It was a frightening tale, but the facts that were left out were just as notable (if not more so) than what was selectively chosen to be included.

The central thesis of the article is that shale development, including hydraulic fracturing, is contaminating the food we eat. As the author states early on, “there’s growing evidence that these two impulses, toward energy and food independence, may be at odds with each other.”

From there, the story advances as one would imagine. Using the fatally flawed Bamberger-Oswald “study” on hydraulic fracturing as the focal point, the author weaves a carefully constructed narrative that does everything from repeating common (and debunked) activist talking points to claiming America’s cows are being poisoned to death by oil and natural gas development.

Of course, the story would have been much different had the author included (instead of deliberately omitting) scientific assessments that weren’t tailor-made for an anti-natural gas crowd.

How do we know they were deliberately omitted? Well, to her credit, Elizabeth Royte (the author of the piece) reached out to Energy In Depth several weeks ago about this article. She acknowledged having read EID’s work on the subject, and then asked me some pointed (but fair) questions about potential impacts on livestock and crops from hydraulic fracturing. I sent her a detailed response, including links to studies (more on that below) that demonstrate little if any negative impact on health as a result of nearby shale development. I also emphasized that concerns about public health should always be taken seriously, and the industry naturally does exactly that. But I also cautioned that simply blaming impacts on the most convenient thing (i.e. hydraulic fracturing) without scientific evidence does not solve problems, nor does it encourage the proper kind of public dialogue to address concerns.

Unfortunately, Ms. Royte did not see fit to print any of that, choosing only to include a brief mention of the lack of scientific pedigree in the Bamberger-Oswald paper – which was promptly bracketed by ascribing fault to the natural gas industry for a supposed lack of disclosure.

So, what else didn’t make it into the report?

First of all, the flaws in the Bamberger-Oswald study have been publicly documented. Dr. Ian Rae, for example, a Co-Chair of the Chemicals Technical Options Committee for the U.N. Environment Programme, called the study “an advocacy piece” written by individuals who “cannot be regarded as experts” in the subject about which they were writing. “It certainly does not qualify as a scientific paper,” Rae added. Rae also critiqued the journal that published the study – New Solutions: A Journal of Environmental and Occupational Health – by saying “the refereeing process evidently was not very stringent.”

Spencer Platt / Getty Images file

Cabot Oil and Gas workers examine a natural gas valve at a hydraulic fracturing site in South Montrose, Penn.

I shared all of this information with Ms. Royte, but Dr. Rae’s commentary on the Bamberger-Oswald paper was omitted entirely from the story.

Secondly, although the article purports to be part of an “investigative reporting” effort, there was clearly a lack of interest in discussing anything that deviated from the Bamberger-Oswald paper’s conclusions. Here are just a few items relating to health impacts from development that I shared with the author, who nonetheless did not see fit to print:

• Denton County, Texas: An analysis by two public health experts found that, “even as natural gas development expanded significantly in the area over the past several years, key indicators of health improved across every major category during those times.” Denton County is situated atop the massive Barnett Shale, one of the largest natural gas fields in the United States.

• Fort Worth, Texas: An air quality study conducted for the City of Fort Worth – the largest and most comprehensive of its kind to date – determined there were “no significant health risks” from shale development in the area. Fort Worth, located in Tarrant County, also sits atop the Barnett Shale.

• Pennsylvania: The Pennsylvania Department of Environmental Protection, in two separate reports of air monitoring in Pennsylvania – one each for the northeastern and southwestern portions of the state – “did not identify concentrations of any compound that would likely trigger air-related health issues associated with Marcellus Shale drilling activities.”

There are, of course, many more examples, including hard data from the Bureau of Labor Statistics that undermine the suggestion that hydraulic fracturing is a grave threat to occupational or community health. Most of us also know about the AP investigation earlier this year, which found that activists’ claims about hydraulic fracturing causing cancer and other health problems had little or no basis in fact, much less scientific evidence.

So again, why were these examples omitted from the report? It’s really anyone’s guess. The one common denominator, however, is that none of them conforms to the notion that hydraulic fracturing is somehow a “tornado on the horizon” – as Sandra Steingraber, the lead-in voice to the Bamberger-Oswald paper, once put it. In fact, a sober review of these materials – and a proper weighting of the credibility of those who released the information – might even lead people to realize that claims about impending doom are hyperbolic and, in many cases, flat out untrue.

Read the original piece: Livestock falling ill in fracking regions

Here’s the bottom line: Landowners, farmers, and any other individuals can and should ask questions about the impacts of natural gas development. Those who ask questions should demand answers based on facts, and communities weighing the costs and benefits should, by definition, seek input on both sides and make decisions based on a careful review of that information.

The problem with Ms. Royte’s report, though, is that it did not seek to be a part of that good faith dialogue. By relying on anecdotes and a single, fundamentally flawed research paper – and refusing to even discuss findings that contradict the singular message that those sources conveyed – the story that was presented to readers was not only one-sided, but actually harmful to the broader public discussion about developing oil and natural gas from shale.

Despite that, the story has been reprinted in news outlets and other media as if it carefully weighed competing viewpoints and came to a frightening conclusion. But the truly scary part is that the author, in more than 4,000 words, flat out refused to include even a few sentences about the scientific findings that fell outside what was apparently a pre-determined conclusion.

Maybe the next investigative report will examine the reasoning behind such a glaring omission, though we won’t be holding our breath.

Click here to read Food & Environment Reporting Network's Elizabeth Royte response.

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Jacki Schilke

This cow on Jacki Schilke's ranch in northeast North Dakota lost most of its tail, one of many ailments that afflicted her cattle after hydrofracturing, or fracking, began in the nearby Bakken Shale.

In the midst of the domestic energy boom, livestock on farms near oil- and gas-drilling operations nationwide have been quietly falling sick and dying. While scientists have yet to isolate cause and effect, many suspect chemicals used in drilling and hydrofracking (or “fracking”) operations are poisoning animals through the air, water or soil.

Earlier this year, Michelle Bamberger, an Ithaca, N.Y., veterinarian, and Robert Oswald, a professor of molecular medicine at Cornell’s College of Veterinary Medicine, published the first and only peer-reviewed report to suggest a link between fracking and illness in food animals.

The authors compiled 24 case studies of farmers in six shale-gas states whose livestock experienced neurological, reproductive and acute gastrointestinal problems after being exposed — either accidentally or incidentally — to fracking chemicals in the water or air. The article, published in “New Solutions: A Journal of Environmental and Occupational Health,” describes how scores of animals died over the course of several years. Fracking industry proponents challenged the study, since the authors neither identified the farmers nor ran controlled experiments to determine how specific fracking compounds might affect livestock.

The death toll is insignificant when measured against the nation’s livestock population (some 97 million beef cattle go to market each year), but environmental advocates believe these animals constitute an early warning.

Exposed livestock “are making their way into the food system, and it’s very worrisome to us,” Bamberger said. “They live in areas that have tested positive for air, water and soil contamination. Some of these chemicals could appear in milk and meat products made from these animals.”

In Louisiana, 17 cows died after an hour’s exposure to spilled fracking fluid, which is injected miles underground to crack open and release pockets of natural gas. The most likely cause of death: respiratory failure.

In New Mexico, hair testing of sick cattle that grazed near well pads found petroleum residues in 54 of 56 animals.

In northern central Pennsylvania, 140 cattle were exposed to fracking wastewater when an impoundment was breached. Approximately 70 cows died, and the remainder produced only 11 calves, of which three survived.

In western Pennsylvania, an overflowing wastewater pit sent fracking chemicals into a pond and a pasture where pregnant cows grazed: Half their calves were born dead. Dairy operators in shale-gas areas of Colorado, Pennsylvania, West Virginia, and Texas have also reported the death of goats exposed to fracking chemicals.

Drilling and fracking a single well requires up to 7 million gallons of water, plus an additional 400,000 gallons of additives, including lubricants, biocides, scale- and rust-inhibitors, solvents, foaming and defoaming agents, emulsifiers and de-emulsifiers, stabilizers and breakers. At almost every stage of developing and operating an oil or gas well, chemicals and compounds can be introduced into the environment.

Cows lose weight, die
After drilling began just over the property line of Jacki Schilke’s ranch in the northwestern corner of North Dakota in 2009, in the heart of the state’s booming Bakken Shale, cattle began limping, with swollen legs and infections. Cows quit producing milk for their calves, they lost from 60 to 80 pounds in a week and their tails mysteriously dropped off. Eventually, five animals died, according to Schilke.

Ambient air testing by a certified environmental consultant detected elevated levels of benzene, methane, chloroform, butane, propane, toluene and xylene -- and well testing revealed high levels of sulfates, chromium, chloride and strontium. Schilke says she moved her herd upwind and upstream from the nearest drill pad.

Although her steers currently look healthy, she said, “I won’t sell them because I don’t know if they’re OK.”

Nor does anyone else. Energy companies are exempt from key provisions of environmental laws, which makes it difficult for scientists and citizens to learn precisely what is in drilling and fracking fluids or airborne emissions. And without information on the interactions between these chemicals and pre-existing environmental chemicals, veterinarians can’t hope to pinpoint an animal’s cause of death.

The risks to food safety may be even more difficult to parse, since different plants and animals take up different chemicals through different pathways.

“There are a variety of organic compounds, metals and radioactive material (released in the fracking process) that are of human health concern when livestock meat or milk is ingested,” said Motoko Mukai, a veterinary toxicologist at Cornell’s College of Veterinary Medicine. These “compounds accumulate in the fat and are excreted into milk. Some compounds are persistent and do not get metabolized easily.”

Jacki Schilke

An oil-drilling rig is visible from Jacki Schilke's ranch in North Dakota.

Veterinarians don’t know how long chemicals may remain in animals, farmers aren’t required to prove their livestock are free of contamination before middlemen purchase them and the Food Safety Inspection Service of the U.S. Department of Agriculture isn’t looking for these compounds in carcasses at slaughterhouses. 

Documenting the scope of the problem is difficult: Scientists lack funding to study the matter, and rural vets remain silent for fear of retaliation. Farmers who receive royalty checks from energy companies are reluctant to complain, and those who have settled with gas companies following a spill or other accident are forbidden to disclose information to investigators. Some food producers would rather not know what’s going on, say ranchers and veterinarians.

“It takes a long time to build up a herd’s reputation,” said rancher Dennis Bauste of Trenton Lake, N.D. “I’m gonna sell my calves and I don’t want them to be labeled as tainted. Besides, I wouldn’t know what to test for. Until there’s a big wipeout, a major problem, we’re not gonna hear much about this.”

Fracking proponents criticize Bamberger and Oswald’s paper as a political, not a scientific, document. “They used anonymous sources, so no one can verify what they said,” said Steve Everley, of the industry lobby group Energy In Depth. The authors didn’t provide a scientific assessment of impacts -- testing what specific chemicals might do to cows that ingest them, for example -- so treating their findings as scientific, he continues, “is laughable at best, and dangerous for public debate at worst.” Bamberger and Oswald acknowledge this lack of scientific assessment and blame it on the dearth of funding for fracking research and on the industry’s use of nondisclosure agreements.

The National Cattlemen’s Beef Association, the main lobbying group for ranchers, takes no position on fracking, but some ranchers are beginning to speak out. “These are industry-supporting conservatives, not radicals,” said Amy Mall, a senior policy analyst with the environmental group, Natural Resources Defense Council. “They are the experts in their animals’ health, and they are very concerned.”

Last March, Christopher Portier, director of the National Center for Environmental Health at the U.S. Centers for Disease Control and Prevention, called for studies of oil and gas production’s impact on food plants and animals. None is currently planned by the federal government.

As local food booms, consumers wary
But consumers intensely interested in where and how their food is grown aren’t waiting for hard data to tell them their meat or milk is safe. For them, the perception of pollution is just as bad as the real thing.

“My beef sells itself. My farm is pristine. But a restaurant doesn’t want to visit and see a drill pad on the horizon,” said Ken Jaffe, who raises grass-fed cattle in upstate New York.

Only recently has the local foods movement, in regions across the country, reached a critical mass. But the movement’s lofty ideals could turn out to be, in shale gas areas, a double-edged sword.

Should the moratorium on hydrofracking in New York State be lifted, the 16,200-member Park Slope Food Co-op, in Brooklyn, will no longer buy food from farms anywhere near drilling operations -- a $4 million loss for upstate producers. The livelihood of organic goat farmer Steven Cleghorn, who’s surrounded by active wells in Pennsylvania, is already in jeopardy.

“People at the farmers market are starting to ask exactly where this food comes from,” he said.

This report was produced by the Food & Environment Reporting Network, an independent investigative journalism non-profit focusing on food, agriculture, and environmental health. A longer version of this story appears on TheNation.com. 

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Ranjana Bhandari and her husband, Kaushik De, stand near a Chesapeake Energy gas well in Arlington, Texas, on Sept. 16, 2012.

Ranjana Bhandari and her husband knew the natural gas beneath their ranch-style home in Arlington, Texas, could be worth a lot - especially when they got offer after offer from Chesapeake Energy Corp.

Chesapeake wanted to drill there, and the offers could have netted the couple thousands of dollars in a bonus and royalties. But Bhandari says they ultimately declined the deals because they oppose fracking in residential areas. Fracking, slang for hydraulic fracturing, is a controversial method used to extract gas and oil.

Their repeated refusals didn't stop Chesapeake, the second-largest natural gas producer in the United States. This June, after petitioning a Texas state agency for an exception to a 93-year-old statute, the company effectively secured the ability to drain the gas from beneath the Bhandari property anyway -- without having to pay the couple a penny.

In fact, since January 2005, the Texas agency has rejected just five of Chesapeake's 1,628 requests for such exceptions, a Reuters review of agency data shows. Chesapeake has sought the most exceptions during that time -- almost twice the number sought by a subsidiary of giant rival Exxon Mobil, Reuters found.

Chesapeake says it only seeks exceptions to the Texas statute -- called Rule 37 -- as a last-ditch effort, and often because it cannot locate the land owner. The law, company spokesman Michael Kehs said, "protects the rights of the majority of mineral owners."

Not so, say many local residents.

"The principle of it is insane," said Calvin Tillman, a former mayor of Dish, Texas, a small town north of Fort Worth where drilling has been heavy. "Not only can they take your property, but they don't have to pay you for it."

Chesapeake's use of the Texas law is among the latest examples of how the company executes what it calls a "land grab" -- an aggressive leasing strategy intended to lock up prospective drilling sites and lock out competitors.

Chesapeake has become the principal player in the largest land boom in America since the California Gold Rush of the late 1840s and ‘50s, amassing drilling rights on more land than almost any U.S. energy company. After years of leasing tracts from New York to Wyoming, the company now controls the right to drill for oil and gas on about 15 million acres -- roughly the size of West Virginia.

More than its rivals, Chesapeake has made land-leasing central to its business model. An analysis by investment research firm Morningstar Inc. shows that the company has spent $31.2 billion to acquire drilling rights on unproven U.S. land in the last 15 years. Exxon -- a company whose revenue was 35 times larger than Chesapeake's last year -- spent $27 billion during the same period.

Chesapeake's rationale is clearly spelled out in company filings with the U.S. Securities and Exchange Commission.

"We believed that the winner of these land grabs would enjoy competitive advantages for decades to come as other companies would be locked out of the best new unconventional resource plays in the U.S.," the company wrote in its 2012 filing.

It has been less forthcoming about the tactics used in implementing that strategy, however.

Reuters reviewed hundreds of internal Chesapeake emails and thousands of pages of documents, including in-house data that show how Chesapeake evaluates its land acquisitions.

Reporters also examined dozens of lawsuits by land owners in seven states, and interviewed contractors proffering deals for the company.

What emerged were approaches to leasing property that land brokers, land owners and lawyers say push ethical and legal limits. Chesapeake has unilaterally altered or backed out of leases. And in Texas and at least three other states, it has exploited little-known laws to force owners to hand over drilling rights and sometimes forfeit profits.

Some of the company's own contractors have considered the tactics dubious.

"In my entire career, I have never been put in the position that (Chesapeake) has recently handed us," contractor David McGuire wrote to Chesapeake CEO Aubrey McClendon on Aug. 10, 2010. He had just been ordered by the company to reject hundreds of signed leases in Michigan -- through means that McGuire said were "beyond anything I could ever have imagined."

He told McClendon that he regretted ever being part of Chesapeake's land grab. "I simply wish our deal would never have taken place," he wrote in the email.

Some of the methods that Chesapeake has used aren't unique to the company. Nor is the outcome necessarily one-sided. Many land owners have gotten rich on deals with Chesapeake.

"Chesapeake has been successful in our leasing because we strive to fairly compensate the more than one million Chesapeake mineral owners," said spokesman Kehs. "Chesapeake has paid nearly $12 billion in lease bonus payments and nearly $10 billion in royalty payments since 2005."

Critical juncture
How Chesapeake went about its land grab has become increasingly important in the past year, as the company weathers a governance crisis and liquidity crunch.

In April, Reuters reported that McClendon, 53, had arranged more than $1.5 billion in financing by pledging his share of the company's wells as collateral for personal loans. Most of the borrowing came from a firm that also is an investor in Chesapeake, a potential conflict of interest. The report prompted Chesapeake's board of directors to strip McClendon of his chairmanship and hire an independent chairman. Disgruntled shareholders replaced four of its nine directors.

In June, Reuters documented Chesapeake's efforts to team with Canadian rival Encana Corp. to avoid driving up land prices in Michigan. The U.S. Justice Department is investigating whether the companies violated antitrust laws.

Now, as Chesapeake fights to regain its footing, it is looking to execute the last stage in its land strategy: filling out its vast holdings, and then developing or selling them. Where Chesapeake doesn't intend to drill, it intends to sell, according to company presentations.

Much hinges on this next chapter. This year, the company aims to sell $14 billion worth of assets to close a cash-flow deficit.

The real estate strategy has been honed by McClendon, who started his career as a land man, the term for brokers who acquire mineral rights for energy companies.

On April 28, 2010 -- amid one of the biggest land grabs in Michigan history -- McClendon received a flattering email that harkened to his beginnings. It came from contractor McGuire, manager at O.I.L. Niagaran, a local firm that Chesapeake hired to help handle its leasing efforts in northern Michigan.

"To the most successful Landman in the world," McGuire's email began.

McClendon adored the compliment. "That is the nicest title anyone has ever given me," he replied. "I really appreciate that, thanks David!"

McGuire had been hired to serve as Chesapeake's principal outside land man in Michigan, where the company sought acreage in the Collingwood shale formation, then one of the most promising new oil and gas plays in the United States.

After Chesapeake identifies acreage that might hold significant gas or oil, it deploys armies of land men -- some Chesapeake employees, others contractors such as McGuire and his employees. They knock on the doors of land owners to solicit leases. Few regulations govern what they can say or what language can be included in leases.

Chesapeake has, until recently, employed more than 4,000 land men. Often, they are ordered not to disclose that Chesapeake is their client, according to internal emails and interviews with land owners and land men.

"It is critical that we do everything in our power to keep our client's name secret!!!!" wrote Joe McFerron in a Nov. 10, 2010, email to his staff. McFerron was a contractor with RedSky Land, an Oklahoma brokerage hired by Chesapeake in North Dakota and Michigan. McFerron did not respond to requests for comment.

Broker McGuire pursued his task energetically and in secret: Within three months, O.I.L. Niagaran and other subcontractors for Chesapeake had leased about 450,000 acres in Michigan. Chesapeake spent some $400 million there through McGuire and other brokers.

But internal Chesapeake emails show that by August -- a few months after he had called McClendon the world's best land man -- McGuire was troubled by the experience.

At the direction of McClendon and other Chesapeake executives, McGuire was ordered to reject or put on hold hundreds of leases after a Chesapeake test well performed poorly and a major Chesapeake competitor stopped new leasing.

A backlash ensued, and McGuire's company bore the brunt. O.I.L. Niagaran became a defendant in about 150 breach-of-contract lawsuits filed since late 2010 in Michigan state courts.

McGuire referred questions to an attorney, who declined to comment.

Faux deals?
Extricating itself from land leases has sometimes proved as important to Chesapeake as obtaining them.

In lawsuits in Texas, Pennsylvania and North Dakota, land owners allege Chesapeake has treated signed leases as mere placeholders for deals that it may later choose not to honor.

Two state court judges in Michigan ruled early this year that Chesapeake had the right to reject leases at any time before title to the minerals was finalized.

But in the last three months, judges in Louisiana and Texas have awarded nearly $120 million to two land owners -- Peak Energy and Preston Exploration -- after finding Chesapeake breached contracts by walking away from signed deals. Scores of similar cases in Michigan and Texas have been settled this year.

In late 2008, as the financial crisis sent natural gas prices tumbling, Chesapeake began to reevaluate deals it had cut.

One group of land owners caught in these retreats was the Witt family. They own a 33-acre tract above the Haynesville formation of rich gas fields in Harrison County, Texas.

In August 2008, the Witts were approached by land men working for Chesapeake. The offer: to lease mineral rights for the Witts' land for $14,000 per acre, according to an amended complaint filed in May 2012. Instead of checks, Chesapeake issued bank drafts, which can be cashed after an owner's property title is reviewed -- typically 30 to 90 days after a lease is signed.

When the Witts went to cash the Chesapeake bank draft, they were told by bank officials that the payment would not be honored. A hand-written note on one of the Witts' bank drafts rescinded by Chesapeake reads, "Cancelled for renegotiating price (per) acre," according to an exhibit submitted in the family's lawsuit.

The Witts alleged that McClendon told Chesapeake employees "to reduce the already agreed upon bonuses down to no more than $5,000 per acre" and to "take lawsuits" if necessary.

The family claimed they were "cold-drafted," a term used to describe an "unethical practice in the leasing industry" in which the land owner is provided a bank draft "in consideration for a valid, enforceable lease," even though the company's intent is "not to honor the payment obligation."

The practice allegedly enables Chesapeake to lock up property, block rivals, prevent owners from shopping for better offers, and then later decide if it wants to keep the acreage.

"It is unethical by anyone's standards in the energy industry if the intention was not to pay the draft at the time it was issued," said Richard Bate, an oil and gas attorney in Denver. "It is the essence of the land grab because it boxes out the competition without the intention to pay."

In response to the suit, Chesapeake said it "was simply under no contractual obligation to pay lease bonuses" to the Witts, according to court records. The company said the leases were "not signed by Chesapeake," though copies show they were taken in the name of a Chesapeake subsidiary, Chesapeake Exploration.

Terry Rhoads, an attorney for the Witt family, said their lawsuit was settled on Aug. 17. Terms were t disclosed.

No refusing
Some landowners oppose fracking, and New York, Vermont and Maryland have all refused to grant fracking licenses. The technique's effects on groundwater are still under review by the U.S. Environmental Protection Agency.

But Chesapeake and other energy companies, which view fracking as safe, are now using state statutes to access the minerals under unleased land even if owners object to the drilling technique.

If property owners refuse deals, Chesapeake and its land men have made clear their plans to take the oil and gas from beneath the land by using little-known laws in Texas, Ohio and other states. The terminology varies from state to state -- a Rule 37 exception in Texas, mandatory pooling or unitization in Ohio. But the result is often the same: getting state regulators to enable the company to drill, sometimes against the owner's will.

The economic argument for granting access to unleased land is logical. Difficulty in stitching together large plots leaves holes in drilling units that can make development less profitable. Large, contiguous plots enable drillers to pump more oil and gas. Allowing companies to access remaining land means that property owners who want to sell their mineral rights aren't shortchanged by a few holdouts.

"Under Ohio law, it's not legal for one or a few landowners to keep the vast majority of landowners from exercising their rights to develop their minerals and get the benefits," said Heidi Hetzel Evans, a spokeswoman with the state's Department of Natural Resources, which rules on such requests.

Chesapeake has based some of its petitions on just such a premise: that it is protecting the rights of people who want to drill, rather than succumbing to the will of holdout landowners.

That marks a turnabout in Texas. When the state passed the Rule 37 statute in 1919, it was meant to prevent excessive drilling of oil wells and to protect the mineral rights of small landowners, say legal experts. The rule prohibits companies from drilling too close to unleased properties.

Today, Rule 37 exceptions "seem to be a new creative use of the statute in a way that was not intended when it was designed," said Matthew Festa, an associate professor of law at South Texas College of Law. "It's possible that this amounts to the transfer of private property from one private entity to another private entity."

Since Jan. 1, 2005, three of the largest oil and gas drillers in Texas have applied for 3,595 exceptions to Rule 37, according to a Reuters review of Texas Railroad Commission data. Chesapeake has been the most active. It has applied for 1,628 exceptions, compared with 1,073 for rival EOG Resources and 894 for XTO Energy, a unit of Exxon Mobil.

Chesapeake and its rivals almost always win. Energy companies only have to notify land owners that they intend to apply for a Rule 37 exception. If the owner doesn't protest, commission guidelines require the petition be granted.

Texas Railroad Commission spokeswoman Ramona Nye said the agency believes there is no evidence that fracking is unsafe. And evaluating the fairness of Rule 37 exceptions is not part of the commission's mandate, she said.

"We are charged by the Legislature to make sure hydrocarbons don't stay underground and go to waste," she said. "It becomes a balancing act. Do we allow two or three landowners to prevent a majority from developing those minerals?"

Energy companies and their executives are the dominant contributors to the election campaigns of railroad commission members and candidates, according to a Reuters review of Texas Ethics Commission data. For example, Chesapeake was among the largest donors last year to the campaign of the commission's chairman, Barry Smitherman, who is seeking reelection this year. The company contributed $25,000.

‘Whatever we want’
In Texas, Arlington resident Bhandari is resigned to losing future income from the gas beneath the couple's land. "We decided not to sign because we didn't think it was safe," Bhandari said. But "the railroad commission doesn't seem to care about whose property is taken."

They aren't the only owners facing a similar scenario.

Ohio's Utica shale formation is a cornerstone of Chesapeake's plan to drill for more oil, which is fetching a premium at a time of rock-bottom natural gas prices. The company has already leased more than 1 million acres of land in the state. It wants more.

One result: Dozens of Ohio land owners interviewed by Reuters say Chesapeake land men are raising the prospect that their land will be "force pooled" -- a term for using state law to mandate that unleased property be included in drilling units.

That contention is supported by a tape recording of land man Nate Laps, who worked for Chesapeake in Ohio through subcontractor Kenyon Energy. The recording was made by David Kennedy, a landowner in Stark County, Ohio. Kennedy later signed a lease with Chesapeake, receiving a bonus of $9,900 for his 11-acre property. He said he feels that Laps gave him a "fair shake."

The recording indicates that not all landowners are as fortunate.

In a portion of the recorded conversation, Kennedy asked Chesapeake land man Laps: "Mandatory pooling -- what is that?"

Laps responded: "We don't like to talk about this because we won't want to come across as it's our way or no way. … But since you mentioned it -- if properties don't want to sign, if we have 90 percent secured of the well that we need, we have the power to put these people in the lease without their permission."

Kennedy: "Do you still have to pay 'em?"

Laps: "All you do is pay them the royalties. … We can do whatever we want."

Laps did not respond to emails and phone calls seeking comment. But state records in Ohio show Chesapeake is doing precisely what Laps said, and with the blessing of regulators.

Unlike Rule 37 in Texas, Ohio statutes allow that landowners could receive royalties. Hetzel Evans said the DNR receives "a few dozen or more" forced-pooling applications per year. The DNR has approved most of them, she said, but only when a driller shows "there's no other option."

Asked about the comments by Laps to landowner Kennedy, she said: "It does concern us if we're being portrayed as allowing an operator to just come in and do what they will. A comment like that makes it sound like we don't have a framework in place."

State Rep. Mark Okey, a Democrat who represents nearby communities, has unsuccessfully sponsored legislation to govern the conduct of land men. He said his constituents have singled out Chesapeake's brokers as the most forceful. Their land men have even sought to lease his property, he said.

"They believe in intimidation tactics. They threaten you. They will yell at you. … It's all about getting you to sign," Okey said. "You don't sign? We'll go around you. You don't sign? You'll not get anything out of your mineral rights. You don't sign? Then you're going to pay the price because we're going to take those minerals from you."

Chesapeake declined to comment.

David and Catherine Conrad live just outside the town of Hartville, Ohio, near Akron. They said they refused to sign a lease with Chesapeake last year because they, too, oppose fracking. But a Chesapeake well will soon snake beneath the Conrad home.

Chesapeake requested in November that the couple's land -- and the land of 48 other property owners -- be included in an area where Chesapeake plans to drill six wells. Chesapeake's application was reported by the Columbus Dispatch.

On July 10, officials with the DNR approved Chesapeake's request. "I don't think the state should be able to take a landowner's rights to generate a profit for a private company," Conrad said.

In its petition, Chesapeake told regulators its proposed drilling unit could produce 4.5 million barrels of oil and 3.5 billion cubic feet of natural gas -- if the plots of the 49 landowners who didn't lease their property to Chesapeake were included.

If not, Chesapeake said, the unit would be 75 percent less productive and would miss out on an additional $71 million in revenue, according to its application. That math carried the day.

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The times they are a-changing.

Who would have thought that Hollywood environmentalists would find themselves aligned with Persian Gulf oil barons?

But the strange politics of energy have managed to bring the greens into line with the OPEC-member United Arab Emirates on the issue of fracking.

"Promised Land" is a new film starring and written by Matt Damon and John Krasinski, based on a story by San Francisco-based writer Dave Eggers. In the film, Damon and actress Frances McDormand play a team that shows a rural town hard hit by economic decline, offering to pay big money for drilling rights.

Krasinski plays a local activist who leads the town into rebellion against the drillers, arguing that their plans would damage the local environment. To anyone who is familiar with the debates about fracking in, say, upstate New York, this will be a familiar story.

The more interesting twist here isn’t in the move — it’s in the movie’s creation. The film was produced “in association with” Image Media Abu Dhabi, a subsidiary of Abu Dhabi Media, as first reported by the Heritage Foundation. Abu Dhabi Media — which has never had a role in a major American film before — is wholly owned by the government of the United Arab Emirates, a small but extremely wealthy federation of absolute monarchies along the southern coast of the Persian Gulf.

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The UAE has the world’s seventh largest oil reserves, according to the CIA Factbook. It is ranked ahead of Russia and just behind Kuwait in proven oil reserves. It is the fourth largest exporter of oil in the world. And, of course, it is a member of OPEC.

Very obviously, the UAE has an interest in slowing down the expansion of hydraulic fracking that has created an energy boom in the United States. A popular film — there’s even talk of it being an Oscar candidate — might give a boost to the opponents of fracking.

 Although that’s not necessarily what will happen. There’s already a Facebook group formed by residents of the area in Pennsylvania where much of the movie was filmed who claim they were deceived about the filmmakers intentions.

 “They filmed this movie in our backyard. They told us it would be fair to drilling. It’s not. We’re p*ssed,” the group complains.

 No doubt news of the UAE’s involvement in the film will make backlash even more likely.

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Abrahm Lustgarten / ProPublica

This class 2 brine disposal well in western Louisiana, near the Texas border, is among the 680,000 waste and injection wells across the U.S.

Over the past several decades, U.S. industries have injected more than 30 trillion gallons of toxic liquid deep into the earth, using broad expanses of the nation's geology as an invisible dumping ground.

No company would be allowed to pour such dangerous chemicals into the rivers or onto the soil. But until recently, scientists and environmental officials have assumed that deep layers of rock beneath the earth would safely entomb the waste for millenia. 

There are growing signs they were mistaken.

Records from disparate corners of the United States show that wells drilled to bury this waste deep beneath the ground have repeatedly leaked, sending dangerous chemicals and waste gurgling to the surface or, on occasion, seeping into shallow aquifers that store a significant portion of the nation's drinking water.

In 2010, contaminants from such a well bubbled up in a west Los Angeles dog park. Within the past three years, similar fountains of oil and gas drilling waste have appeared in Oklahoma and Louisiana. In South Florida, 20 of the nation's most stringently regulated disposal wells failed in the early 1990s, releasing partly treated sewage into aquifers that may one day be needed to supply Miami's drinking water.

There are more than 680,000 underground waste and injection wells nationwide, more than 150,000 of which shoot industrial fluids thousands of feet below the surface. Scientists and federal regulators acknowledge they do not know how many of the sites are leaking.

Federal officials and many geologists insist that the risks posed by all this dumping are minimal. Accidents are uncommon, they say, and groundwater reserves — from which most Americans get their drinking water — remain safe and far exceed any plausible threat posed by injecting toxic chemicals into the ground.

But in interviews, several key experts acknowledged that the idea that injection is safe rests on science that has not kept pace with reality, and on oversight that doesn't always work.

"In 10 to 100 years we are going to find out that most of our groundwater is polluted," said Mario Salazar, an engineer who worked for 25 years as a technical expert with the EPA's underground injection program in Washington. "A lot of people are going to get sick, and a lot of people may die."

The boom in oil and natural gas drilling is deepening the uncertainties, geologists acknowledge. Drilling produces copious amounts of waste, burdening regulators and demanding hundreds of additional disposal wells. Those wells — more holes punched in the ground — are changing the earth's geology, adding man-made fractures that allow water and waste to flow more freely.

"There is no certainty at all in any of this, and whoever tells you the opposite is not telling you the truth,' said Stefan Finsterle, a leading hydrogeologist at Lawrence Berkeley National Laboratory who specializes in understanding the properties of rock layers and modeling how fluid flows through them. "You have changed the system with pressure and temperature and fracturing, so you don't know how it will behave."

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A ProPublica review of well records, case histories and government summaries of more than 220,000 well inspections found that structural failures inside injection wells are routine. From late 2007 to late 2010, one well integrity violation was issued for every six deep injection wells examined — more than 17,000 violations nationally. More than 7,000 wells showed signs that their walls were leaking. Records also show wells are frequently operated in violation of safety regulations and under conditions that greatly increase the risk of fluid leakage and the threat of water contamination.

Structurally, a disposal well is the same as an oil or gas well. Tubes of concrete and steel extend anywhere from a few hundred feet to two miles into the earth. At the bottom, the well opens into a natural rock formation. There is no container. Waste simply seeps out, filling tiny spaces left between the grains in the rock like the gaps between stacked marbles.

Many scientists and regulators say the alternatives to the injection process — burning waste, treating wastewater, recycling, or disposing of waste on the surface — are far more expensive or bring additional environmental risks.

Subterranean waste disposal, they point out, is a cornerstone of the nation's economy, relied on by the pharmaceutical, agricultural and chemical industries. It's also critical to a future less dependent on foreign oil: Hydraulic fracturing, "clean coal" technologies, nuclear fuel production, and carbon storage (the keystone of the strategy to address climate change) all count on pushing waste into rock formations below the earth's surface.

The U.S. Environmental Protection Agency, which has primary regulatory authority over the nation's injection wells, would not discuss specific well failures identified by ProPublica or make staffers available for interviews. The agency also declined to answer many questions in writing, though it sent responses to several. Its director for the Drinking Water Protection Division, Ann Codrington, sent a statement to ProPublica defending the injection program's effectiveness.

"Underground injection has been and continues to be a viable technique for subsurface storage and disposal of fluids when properly done," the statement said. "EPA recognizes that more can be done to enhance drinking water safeguards and, along with states and tribes, will work to improve the efficiency of the underground injection control program."

Still, some experts see the well failures and leaks discovered so far as signs of broader problems, raising concerns about how much pollution may be leaking out undetected. By the time the damage is discovered, they say, it could be irreversible.

"Are we heading down a path we might regret in the future?" said Anthony Ingraffea, a Cornell University engineering professor who has been an outspoken critic of claims that wells don't leak. "Yes."

***

In September 2003, Ed Cowley got a call to check out a pool of briny water in a bucolic farm field outside Chico, Texas. Nearby, he said, a stand of trees had begun to wither, their leaves turning crispy brown and falling to the ground.

Chico, a town of about 1,000 people 50 miles northwest of Fort Worth, lies in the heart of Texas' Barnett Shale. Gas wells dot the landscape like mailboxes in suburbia. A short distance away from the murky pond, an oil services company had begun pumping millions of gallons of drilling waste into an injection well.

Regulators refer to such waste as salt water or brine, but it often includes less benign contaminants, including fracking chemicals, benzene and other substances known to cause cancer.

The well had been authorized by the Railroad Commission of Texas, which once regulated railways but now oversees 260,000 oil and gas wells and 52,000 injection wells. (Another agency, the Texas Commission on Environmental Quality, regulates injection wells for waste from other industries.)

Before issuing the permit, commission officials studied mathematical models showing that waste could be safely injected into a sandstone layer about one-third of a mile beneath the farm. They specified how much waste could go into the well, under how much pressure, and calculated how far it would dissipate underground. As federal law requires, they also reviewed a quarter-mile radius around the site to make sure waste would not seep back toward the surface through abandoned wells or other holes in the area.

Yet the precautions failed. "Salt water" brine migrated from the injection site and shot back to the surface through three old well holes nearby.

"Have you ever seen an artesian well?" recalled Cowley, Chico's director of public works. "It was just water flowing up out of the ground."

Despite residents' fears that the injected waste could be making its way towards their drinking water, commission officials did not sample soil or water near the leak.

If the injection well waste "had threatened harm to the ground water in the area, an in-depth RRC investigation would have been initiated," Ramona Nye, a spokeswoman for Texas' Railroad Commission, wrote in an email.

The agency disputes Cowley's description of a pool of brine or of dead trees, saying that the waste barely spilled beyond the overflowing wells, though officials could not identify any documents or staffers who contradicted Cowley's recollections. Accounts similar to Cowley's appeared in an article about the leak in the Wise County Messenger, a local newspaper. The agency has destroyed its records about the incident, saying it is required to keep them for only two years.

After the breach, the commission ordered two of the old wells to be plugged with cement and restricted the rate at which waste could be injected into the well. It did not issue any violations against the disposal company, which had followed Texas' rules, regulators said. The commission allowed the well operator to continue injecting thousands of barrels of brine into the well each day. A few months later, brine began spurting out of three more old wells nearby.

"It's kind of like Whac-a-Mole, where one thing pops up and by the time you go to hit it, another thing comes up," Cowley said. "It was frustrating. ... If your water goes, what does that do to the value of your land?"

Deep well injection takes place in 32 states, from Pennsylvania to Michigan to California. Most wells are around the Great Lakes and in areas where oil and gas is produced: along the Appalachian crest and the Gulf Coast, in California and in Texas, which has more wells for hazardous industrial waste and oil and gas waste than any other state.

Federal rules divide wells into six classes based on the material they hold and the industry that produced it. Class 1 wells handle the most hazardous materials, including fertilizers, acids and deadly compounds such as asbestos, PCBs and cyanide. The energy industry has its own category, Class 2, which includes disposal wells and wells in which fluids are injected to force out trapped oil and gas. The most common wells, called Class 5, are a sort of catch-all for everything left over from the other categories, including storm-water runoff from gas stations.

The EPA requires that Class 1 and 2 injection wells be drilled the deepest to assure that the most toxic waste is pushed far below drinking water aquifers. Both types of wells are supposed to be walled with multiple layers of steel tubing and cement and regularly monitored for cracks.

Officials' confidence in this manner of disposal stems not only from safety precautions, but from an understanding of how rock formations trap fluid.

Underground waste, officials say, is contained by layer after layer of impermeable rock. If one layer leaks, the next blocks the waste from spreading before it reaches groundwater. The laws of physics and fluid dynamics should ensure that the waste can't spread far and is diluted as it goes.

The layering "is a very strong phenomenon and it's on our side," said Susan Hovorka, a senior research scientist at the University of Texas at Austin's Bureau of Economic Geology.

According to risk analyses cited in EPA documents, a significant well leak that leads to water contamination is highly unlikely — on the order of one in a million.

Once waste is underground, though, there are few ways to track how far it goes, how quickly or where it winds up. There is plenty of theory, but little data to prove the system works.

"I do think the risks are low, but it has never been adequately demonstrated," said John Apps, a leading geoscientist who advises the Department of Energy for Lawrence Berkeley National Labs. "Every statement is based on a collection of experts that offer you their opinions. Then you do a scientific analysis of their opinions and get some probability out of it. This is a wonderful way to go when you don't have any evidence one way or another... But it really doesn't mean anything scientifically."

The hard data that does exist comes from well inspections conducted by federal and state regulators, who can issue citations to operators for injecting illegally, for not maintaining wells, or for operating wells at unsafe pressures. This information is the EPA's primary means of tracking the system's health on a national scale.

ProPublica's series on injection wells

Yet, in response to questions from ProPublica, the EPA acknowledged it has done very little with the data it collects. The agency could not provide ProPublica with a tally of how frequently wells fail or of how often disposal regulations are violated. It has not counted the number of cases of waste migration or contamination in more than 20 years. The agency often accepts reports from state injection regulators that are partly blank, contain conflicting figures or are missing key details, ProPublica found.

In 2007, the EPA launched a national data system to centralize reports on injection wells. As of September 2011 — the last time the EPA issued a public update — less than half of the state and local regulatory agencies overseeing injection were contributing to the database. It contained complete information from only a handful of states, accounting for a small fraction of the deep wells in the country.

The EPA did not respond to questions seeking more detail about how it handles its data, or about how the agency judges whether its oversight is working.

In a 2008 interview with ProPublica, one EPA scientist acknowledged shortcomings in the way the agency oversees the injection program.

"It's assumed that the monitoring rules and requirements are in place and are protective — that's assumed," said Gregory Oberley, an EPA groundwater specialist who studies injection and water issues in the Rocky Mountain region. "You're not going to know what's going on until someone's well is contaminated and they are complaining about it."

***

ProPublica's analysis of case histories and EPA data from October 2007 to October 2010 showed that when an injection well fails, it is most often because of holes or cracks in the well structure itself.

Operators are required to do so-called "mechanical integrity" tests at regular intervals, yearly for Class 1 wells and at least once every five years for Class 2 wells. In 2010, the tests led to more than 7,500 violations nationally, with more than 2,300 wells failing. In Texas, one violation was issued for every three Class 2 wells examined in 2010.

Such breakdowns can have serious consequences. Damage to the cement or steel casing can allow fluids to seep into the earth, where they could migrate into water supplies.

Regulators say redundant layers of protection usually prevent waste from getting that far, but EPA data shows that in the three years analyzed by ProPublica, more than 7,500 well test failures involved what federal water protection regulations describe as "fluid migration" and "significant leaks."

In September 2009, workers for Unit Petroleum Company discovered oil and gas waste in a roadside ditch in southern Louisiana. After tracing the fluid to a crack in the casing of a nearby injection well, operators tested the rest of the well. Only then did they find another hole — 600 feet down, and just a few hundred feet away from an aquifer that is a source of drinking water for that part of the state.

Most well failures are patched within six months of being discovered, EPA data shows, but with as much as five years passing between integrity tests, it can take a while for leaks to be discovered. And not every well can be repaired. Kansas shut down at least 47 injection wells in 2010, filling them with cement and burying them, because their mechanical integrity could not be restored. Louisiana shut down 82. Wyoming shut down 144.

Another way wells can leak is if waste is injected with such force that it accidentally shatters the rock meant to contain it. A report published by scientists at the Department of Energy's Pacific Northwest National Laboratory and the University of Texas said that high pressure is "the driving force" that can help connect deep geologic layers with shallower ones, allowing fluid to seep through the earth.

Most injection well permits strictly limit the maximum pressure allowed, but well operators — rushing to dispose of more waste in less time — sometimes break the rules, state regulatory inspections show. According to data provided by states to the EPA, deep well operators have been caught exceeding injection pressure limits more than 1,100 times since 2008. 

Excessive pressure factored into a 1989 well failure that yielded new clues about the risks of injection.

While drilling a disposal well in southern Ohio, workers for the Aristech Chemical Corp. (since bought by Sunoco, and sold again, in 2011, to Haverhill Chemicals) were overwhelmed by the smell of phenol, a deadly chemical the company had injected into two Class 1 wells nearby. Somehow, perhaps over decades, the pollution had risen 1,400 feet through solid rock and was progressing toward surface aquifers.

Ohio environmental officials – aided by the EPA – investigated for some 15 years. They concluded that the wells were mechanically sound, but Aristech had injected waste into them faster and under higher pressure than the geologic formation could bear.

Though scientists maintain that the Aristech leak was a rarity, they acknowledge that such problems are more likely in places where industrial activity has changed the underground environment.

There are upwards of 2 million abandoned and plugged oil and gas wells in the U.S., more than 100,000 of which may not appear in regulators’ records. Sometimes they are just broken off tubes of steel, buried or sticking out of the ground. Many are supposed to be sealed shut with cement, but studies show that cement breaks down over time, allowing seepage up the well structure.  

Also, if injected waste reaches the bottom of old wells, it can quickly be driven back towards aquifers, as it was in Chico.

“The United States looks like a pin cushion,” said Bruce Kobelski, a geologist who has been with the agency’s underground injection program since 1986. Kobelski spoke to ProPublica in May, 2011, before the EPA declined additional interview requests for this story. “Unfortunately there are cases where someone missed a well or a well wasn’t indicated. It could have been a well from the turn of the [20th] century.”

Clefts left after the earth is cracked open to frack for oil and gas also can connect abandoned wells and waste injection zones. How far these man-made fissures go is still the subject of research and debate, but in some cases they have reached as much as a half-mile, even intersecting fractures from neighboring wells.

When injection wells intersect with fracked wells and abandoned wells, the combined effect is that many of the natural protections assumed to be provided by deep underground geology no longer exist.

“It’s a natural system and if you go in and start punching holes through it and changing pressure systems around, it’s no longer natural,” said Nathan Wiser, an underground injection expert working for the EPA in its Rocky Mountain region, in a 2010 interview. “It’s difficult to know how it would behave in those circumstances.”

EPA data provides a window into some injection well problems, but not all. There is no way to know how many wells have undetected leaks or to measure the amount of waste escaping from them.

In at least some cases, records obtained by ProPublica show, well failures may have contaminated sources of drinking water. Between 2008 and 2011, state regulators reported 150 instances of what the EPA calls "cases of alleged contamination," in which waste from injection wells purportedly reached aquifers. In 25 instances, the waste came from Class 2 wells. The EPA did not respond to requests for the results of investigations into those incidents or to clarify the standard for reporting a case.

The data probably understates the true extent of such incidents, however.

Leaking wells can simply go undetected. One Texas study looking for the cause of high salinity in soil found that at least 29 brine injection wells in its study area were likely sending a plume of salt water up into the ground unnoticed. Even when a problem is reported, as in Chico, regulators don’t always do the expensive and time-consuming work necessary to investigate its cause.

“The absence of episodes of pollution can mean that there are none, or that no one is looking,” said Salazar, the EPA’s former injection expert. “I would tend to believe it is the latter.”

***

The practice of injecting waste underground arose as a solution to an environmental crisis.

In the first half of the 20th century, toxic waste collected in cesspools, or was dumped in rivers or poured onto fields. As the consequences of unbridled pollution became unacceptable, the country turned to an out-of-sight alternative. Drawing on techniques developed by the oil and gas industry, companies started pumping waste back into wells drilled for resources. Toxic waste became all but invisible. Air and water began to get cleaner. 

Then a host of unanticipated problems began to arise.

In April, 1967 pesticide waste injected by a chemical plant at Denver’s Rocky Mountain Arsenal destabilized a seismic fault, causing a magnitude 5.0 earthquake -- strong enough to shatter windows and close schools -- and jolting scientists with newfound risks of injection, according to the U.S. Geological Survey.

A year later, a corroded hazardous waste well for pulping liquor at the Hammermill Paper Co., in Erie, Pa., ruptured. Five miles away, according to an EPA report, “a noxious black liquid seeped from an abandoned gas well” in Presque Isle State Park.

In 1975 in Beaumont, Texas, dioxin and a highly acidic herbicide injected underground by the Velsicol Chemical Corp. burned a hole through its well casing, sending as much as five million gallons of the waste into a nearby drinking water aquifer.

Then in August 1984 in Oak Ridge, Tenn., radioactive waste was turned up by water monitoring near a deep injection well at a government nuclear facility. 

Regulators raced to catch up. In 1974, the Safe Drinking Water Act was passed, establishing a framework for regulating injection. Then, in 1980, the EPA set up the tiered classes of wells and began to establish basic construction standards and inspection schedules. The EPA licensed some state agencies to monitor wells within their borders and handled oversight jointly with others, but all had to meet the baseline requirements of the federal Underground Injection Control program.

Even with stricter regulations in place, 17 states – including Alabama, North Carolina, South Carolina and Wisconsin -- banned Class 1 hazardous deep well injection.

“We just felt like based on the knowledge that we had at that time that it was not something that was really in the best interest of the environment or the state,” said James Warr, who headed Alabama’s Department of Environmental Management at the time.

Injection accidents kept cropping up.

A 1987 General Accountability Office review put the total number of cases in which waste had migrated from Class 1 hazardous waste wells into underground aquifers at 10 -- including the Texas and Pennsylvania sites. Two of those aquifers were considered potential drinking water sources.

In 1989, the GAO reported 23 more cases in seven states where oil and gas injection wells had failed and polluted aquifers. New regulations had done little to prevent the problems, the report said, largely because most of the wells involved had been grandfathered in and had not had to comply with key aspects of the rules.

Noting four more suspected cases, the report also suggested there could be more well failures, and more widespread pollution, beyond the cases identified. “The full extent to which injected brines have contaminated underground sources of drinking water is unknown,” it stated.

The GAO concluded that most of the contaminated aquifers could not be reclaimed because fixing the damage was “too costly” or “technically infeasible.”

Faced with such findings, the federal government drafted more rules aimed at strengthening the injection program. The government outlawed certain types of wells above or near drinking water aquifers, mandating that most industrial waste be injected deeper.

The agency also began to hold companies that disposed of hazardous industrial waste to far stiffer standards. To get permits to dispose of hazardous waster after 1988, companies had to prove – using complex models and geological studies -- that the stuff they injected wouldn’t migrate anywhere near water supplies for 10,000 years. They were already required to test for fault zones and to conduct reviews to ensure there were no conduits for leakage, such as abandoned wells, within a quarter-mile radius. Later, that became a two-mile minimum radius for some wells. 

The added regulations would have prevented the vast majority of the accidents that occurred before the late 1980s, EPA officials contend. 

“The requirements weren’t as rigorous, the testing wasn’t as rigorous and in some cases the shallow aquifers were contaminated,” Kobelski said. “The program is not the same as it was when we first started.”

Today’s injection program, however, faces a new set of problems.

As federal regulators toughened rules for injecting hazardous waste, oil and gas companies argued that the new standards could drive them out of business. State oil and gas regulators pushed back against the regulations, too, saying that enforcing the rules for Class 2 wells – which handle the vast majority of injected waste by volume -- would be expensive and difficult.

Ultimately, the energy industry won a critical change in the federal government’s legal definition of waste: Since 1988, all material resulting from the oil and gas drilling process is considered non-hazardous, regardless of its content or toxicity.

“It took a lot of talking to sell the EPA on that and there are still a lot of people that don’t like it,” said Bill Bryson, a geologist and former head of the Kansas Corporation Commission’s Conservation Division, who lobbied for and helped draft the federal rules. “But it seemed the best way to protect the environment and to stop everybody from just having to test everything all the time.”

The new approach removed many of the constraints on the oil and gas industry. They were no longer required to conduct seismic tests (a stricture that remained in place for Class 1 wells). Operators were allowed to test their wells less frequently for mechanical integrity and the area they had to check for abandoned wells was kept to a minimum  – one reason drilling waste kept bubbling to the surface near Chico.

Soon after the first Chico incident, Texas expanded the area regulators were required to check for abandoned waste wells (a rule that applied only to certain parts of the state). Doubling the radius they reviewed in Chico to a half mile, they found 13 other injection or oil and gas wells. When they studied the land within a mile – the radius required for review of many Class 1 wells – officials discovered another 35 wells, many dating to the 1950s.

The Railroad Commission concluded that the Chico injection well had overflowed: The target rock zone could no longer handle the volume being pushed into it. Trying to cram in more waste at the same speed could cause further leaks, regulators feared. The commission set new limits on how fast the waste could be injected, but did not forbid further disposal. The well remains in use to this day.  

In late 2008, samples of Chico’s municipal drinking water were found to contain radium, a radioactive derivative of uranium and a common attribute of drilling waste. The water well was a few miles away from the leaking injection well site, but environmental officials said the contaminants discovered in the water well were unrelated, mostly because they didn’t include the level of sodium typical of brine.

Since then, Ed Cowley, the public works director, said commission officials have continued to assure him that brine won’t reach Chico’s drinking water. But since the agency keeps allowing more injection and doesn’t track the cumulative volume of waste going into wells in the area, he’s skeptical that they can keep their promise.

“I was kind of like, ‘You all need to get together and look at the total amount you are trying to fit through the eye of the needle,’” he said.  

***

When sewage flowed from 20 Class 1 wells near Miami into the Upper Floridan aquifer, it challenged some of scientists’ fundamental assumptions about the injection system.

The wells – which had helped fuel the growth of South Florida by eliminating the need for expensive water treatment plants -- had passed rigorous EPA and state evaluation throughout the 1980s and 1990s. Inspections showed they were structurally sound. As Class 1 wells, they were subject to some of the most frequent tests and closest scrutiny.

Yet they failed.

The wells' designers would have calculated what is typically called the "zone of influence" — the space that waste injected into the wells was expected to fill. This was based on estimates of how much fluid would be injected and under what pressure.

In drawings, the zone of influence typically looks like a Hershey’s kiss, an evenly dispersed plume spreading in a predictable circular fashion away from the bottom of the well. Above the zone, most drawings depict uniform formations of rock not unlike a layer cake.

Based on modeling and analysis by some of the most sophisticated engineering consultants in the country, Florida officials, with the EPA's assent, concluded that waste injected into the Miami-area wells would be forever trapped far below the South Florida peninsula.

“All of the modeling indicated that the injectate would be confined in the injection zone,” an EPA spokesperson wrote to ProPublica in a statement.

But as Miami poured nearly half a billion gallons of partly treated sewage into the ground each day from the late 1980s through the mid 1990s, hydrogeologists learned that the earth – and the flow of fluids through it – wasn’t as uniform as the models depicted. Florida’s injection wells, for example, had been drilled into rock that was far more porous and fractured than scientists previously understood.

“Geology is never what you think it is,” said Ronald Reese, a geologist with the United States Geological Survey in Florida who has studied the well failures there. “There are always surprises.”

Other gaps have emerged between theories of how underground injection should work and how it actually does. Rock layers aren’t always neatly stacked as they appear in engineers’ sketches. They often fold and twist over on themselves. Waste injected into such formations is more likely to spread in lopsided, unpredictable ways than in a uniform cone. It is also likely to channel through spaces in the rock as pressure forces it along the weakest lines.  

Petroleum engineers in Texas have found that when they pump fluid into one end of an oil reservoir to push oil out the other, the injected fluid sometimes flows around the reservoir, completely missing the targeted zone.

“People are still surprised at the route that the injectate is taking or the bypassing that can happen,” said Jean-Philippe Nicot, a research scientist at the University of Texas’ Bureau of Economic Geology.

Conventional wisdom says fluids injected underground should spread at a rate of several inches or less each year, and go only as far as they are pushed by the pressure inside the well. In some instances, however, fluids have travelled faster and farther than researchers thought possible.

In a 2000 case that wasn’t caused by injection but brought important lessons about how fluids could move underground, hydrogeologists concluded that bacteria-polluted water migrated horizontally underground for several thousand feet in just 26 hours, contaminating a drinking water well in Walkerton, Ontario, and sickening thousands of residents. The fluids travelled 80 times as fast as the standard software model predicted was possible.

According to the model, vertical movement of underground fluids shouldn't be possible at all, or should happen over what scientists call "geologic time": thousands of years or longer. Yet a 2011 study in Wisconsin found that human viruses had managed to infiltrate deep aquifers, probably moving downward through layers believed to be a permanent seal.

According to a study published in April in the journal Ground Water, it’s not a matter of if fluid will move through rock layers, but when.

Tom Myers, a hydrologist, drew on research showing that natural faults and fractures are more prevalent than commonly understood to create a model that predicts how chemicals might move in the Marcellus Shale, a dense layer of rock that has been called impermeable. The Marcellus Shale, which stretches from New York to Tennessee, is the focus of intense debate because of concerns that chemicals injected in drilling for natural gas will pollute water.

Myers’ new model said that chemicals could leak through natural cracks into aquifers tapped for drinking water in about 100 years, far more quickly than had been thought. In areas where there is hydraulic fracturing or drilling, Myers’ model shows, man-made faults and natural ones could intersect and chemicals could migrate to the surface in as little as “a few years, or less.”

“It’s out of sight, out of mind now. But 50 years from now?” Myers said, referring to injected waste and the rock layers trusted to entrap it. “Simply put, they are not impermeable.”

Myers' work is among the few studies done over the past few decades to compare theories of hydrogeology to what actually happens. But even his research is based on models.

"A lot of the concepts and a lot of the regulations that govern this whole practice of subsurface injection is kind of dated at this point," said one senior EPA hydrologist who was not authorized to speak to ProPublica, and declined to be quoted by name.

"It's a problem," he said. "There needs to be a hard look at this in a new way."

This report, "Injection Wells: The Posion Beneath Us", first appeared on propublica.org.

Oil drilling has sparked a frenzied prosperity in Jeff Keller's formerly quiet corner of western North Dakota in recent years, bringing an infusion of jobs and reviving moribund local businesses.

But Keller, a natural resource manager for the Army Corps of Engineers, has seen a more ominous effect of the boom, too: Oil companies are spilling and dumping drilling waste onto the region's land and into its waterways with increasing regularity. 

Hydraulic fracturing — the controversial process behind the spread of natural gas drilling — is enabling oil companies to reach previously inaccessible reserves in North Dakota, triggering a turnaround not only in the state's fortunes, but also in domestic energy production. North Dakota now ranks second behind only Texas in oil output nationwide.

The downside is waste — lots of it. Companies produce millions of gallons of salty, chemical-infused wastewater, known as brine, as part of drilling and fracking each well. Drillers are supposed to inject this material thousands of feet underground into disposal wells, but some of it isn't making it that far.

According to data obtained by ProPublica, oil companies in North Dakota reported more than 1,000 accidental releases of oil, drilling wastewater or other fluids in 2011, about as many as in the previous two years combined. Many more illicit releases went unreported, state regulators acknowledge, when companies dumped truckloads of toxic fluid along the road or drained waste pits illegally.

State officials say most of the releases are small. But in several cases, spills turned out to be far larger than initially thought, totaling millions of gallons. Releases of brine, which is often laced with carcinogenic chemicals and heavy metals, have wiped out aquatic life in streams and wetlands and sterilized farmland. The effects on land can last for years, or even decades.

Compounding such problems, state regulators have often been unable — or unwilling — to compel energy companies to clean up their mess, our reporting showed.

Under North Dakota regulations, the agencies that oversee drilling and water safety can sanction companies that dump or spill waste, but they seldom do: They have issued fewer than 50 disciplinary actions for all types of drilling violations, including spills, over the past three years.

Keller has filed several complaints with the state during this time span after observing trucks dumping wastewater and spotting evidence of a spill in a field near his home. He was rebuffed or ignored every time, he said.

"There's no enforcement," said Keller, 50, an avid outdoorsman who has spent his career managing Lake Sakakawea, a reservoir created by damming the Missouri River. "None."

State officials say they rely on companies to clean up spills voluntarily, and that in most cases, they do. Mark Bohrer, who oversees spill reports for the Department of Mineral Resources, the agency that regulates drilling, said the number of spills is acceptable given the pace of drilling and that he sees little risk of long-term damage.

Kris Roberts, who responds to spills for the Health Department, which protects state waters, agreed, but acknowledged that the state does not have the manpower to prevent or respond to illegal dumping.

"It's happening often enough that we see it as a significant problem," he said. "What's the solution? Catching them. What's the problem? Catching them."

Ron Ness, president of the North Dakota Petroleum Council, a lobbying group, said the industry is doing what it can to minimize spills and their impacts.

"You're going to have spills when you have more activity," he said. "I would think North Dakotans would say the industry is doing a good job."

In response to rising environmental concerns related to drilling waste, North Dakota's legislature passed a handful of new regulations this year, including a rule that bars storing wastewater in open pits.

Still, advocates for landowners say they have seen little will, at either the state or federal level, to impose limits that could slow the pace of drilling.

The Obama administration is facilitating drilling projects on federal land in western North Dakota by expediting environmental reviews. North Dakota's Gov. Jack Dalrymple has urged energy companies to see his administration as a "faithful and long-term partner."

"North Dakota's political leadership is still in the mold where a lot of our oil and gas policy reflects a strong desire to have another oil boom," said Mark Trechock, who headed the Dakota Resource Council, a landowner group that has pushed for stronger oversight, until his retirement this year. "Well, we got it now."

Reaching 'the Crazy Point'
Keller's office in Williston is as good a spot as any to see the impacts of the oil boom.

The tiny prefab shack — cluttered with mounted fish, piles of antlers and a wolf pelt Keller bought in Alaska — is wedged between a levee that holds back Missouri River floodwaters and a new oil well, topped by a blazing gas flare. Just beyond the oil well sits an intersection where Keller estimates he saw an accident a week during one stretch last year due to increased traffic from drilling.

Keller describes the changes to his hometown in a voice just short of a yell, as if he's competing with nearby engine noise. Local grocery stores can barely keep shelves stocked and the town movie theater is so crowded it seats people in the aisle, he said. The cost of housing has skyrocketed, with some apartments fetching rents similar to those in New York City.

Slideshow: 'Man camps' of the oil patch

Gregory Bull / AP

Click the view images of living conditions in the North Dakota oil fields.

Launch slideshow

"With the way it is now," Keller said, "you're getting to the crazy point."

Oil companies are drilling upwards of 200 wells each month in northwestern North Dakota, an area roughly twice the size of New Jersey.

North Dakota is pumping more than 575,000 barrels of oil a day now, more than double what the state produced two years ago. Expanded drilling in the state has helped overall U.S. oil production grow for the first time in a quarter century, stoking hopes for greater energy independence.

NBC's Rock Center: Thousands of jobs from North Dakota's boom

It has also reinvigorated North Dakota's once-stagnant economy. Unemployment sits at 3 percent. The activity has reversed a population decline that began in the mid-1980s, when the last oil boom went bust.

The growth has come at a cost, however. At a conference on oil field infrastructure in October, one executive noted that McKenzie County, which sits in the heart of the oil patch and had a population of 6,360 people in 2010, required nearly $200 million in road repairs.

The number of spill reports, which generally come from the oil companies themselves, nearly doubled from 2010 to 2011. Energy companies report their spills to the Department of Mineral Resources, which shares them with the Health Department. The two agencies work together to investigate incidents.

In December, a stack of reports a quarter-inch thick piled up on Kris Roberts' desk. He received 34 new cases in the first week of that month alone.

"Is it a big issue?" he said. "Yes, it is."

The Health Department has added three staffers to handle the influx and the Department of Mineral Resources is increasing its workforce by 30 percent, but Roberts acknowledges they can't investigate every report.

Even with the new hires, the Department of Mineral Resources still has fewer field inspectors than agencies in other drilling states. Oklahoma, for example, which has comparable drilling activity, has 58 inspectors to North Dakota's 19.

Of the 1,073 releases reported last year, about 60 percent involved oil and one-third spread brine. In about two-thirds of the cases, material was not contained to the accident site and leaked into the ground or waterways.

But the official data gives only a partial picture, Roberts said, missing an unknown number of unreported incidents.

"One, five, 10, 100? If it didn't get reported, how do you count them?" he said.

He said truckers often dump their wastewater rather than wait in line at injection wells. The Department of Mineral Resources asks companies how much brine their wells produce and how much they dispose of as waste, but its inspectors don't audit those numbers. Short of catching someone in the act, there's no way to stop illegal dumping.

The state also has no real estimate for how much fluid spills out accidentally from tanks, pipes, trucks and other equipment. Companies are supposed to report spill volumes, but officials acknowledge the numbers are often inexact or flat-out wrong. In 40 cases last year, the company responsible didn't know how much had spilled so it simply listed the volume of fluid as zero.

In one case last July, workers for Petro Harvester, a small, Texas-based oil company, noticed a swath of dead vegetation in a field near one of the company's saltwater disposal lines. The company reported the spill the next day, estimating that 12,600 gallons of brine had leaked.

When state and county officials came to assess the damage, however, they found evidence of a much larger accident. The leak, which had gone undetected for days or weeks, had sterilized about 24 acres of land. Officials later estimated the spill to be at least 2 million gallons of brine, Roberts said, which would make it the largest ever in the state.

Yet state records still put the volume at 12,600 gallons and Roberts sees no reason to change it.

"It's almost like rubbing salt in a raw wound," Roberts said, criticizing efforts to tabulate a number as "bean counting." Changing a report would not change reality, nor would it help anyone, he added. "If we try to go back and revisit the past over and over and over again, what's it going to do? Nothing good."

In a written statement, Petro Harvester said tests showed the spill had not contaminated groundwater and that it would continue monitoring the site for signs of damage. State records show the company hired a contractor to cover the land with 40 truckloads of a chemical that leaches salt from the soil.

Nearly a year later, however, even weeds won't grow in the area, said Darwin Peterson, who farms the land. While Petro Harvester has promised to compensate him for lost crops, Peterson said he hasn't heard from the company in months and he doesn't expect the land to be usable for years. "It's pretty devastating," he said.

Little enforcement
The Department of Mineral Resources and the Health Department have the authority to sanction companies that spill or dump fluids, but they rarely do.

The Department of Mineral Resources has issued just 45 enforcement actions over the last three years. Spokeswoman Alison Ritter could not say how many of those were for spills or releases, as opposed to other drilling violations, or how many resulted in fines.

The Health Department has taken just one action against an oil company in the past three years, citing Continental Resources for oil and brine spills that turned two streams into temporary toxic dumps. The department initially fined Continental $328,500, plus about $14,000 for agency costs. Ultimately, however, the state settled and Continental paid just $35,000 in fines.

The agency has not yet penalized Petro Harvester for the July spill, thought it has issued a notice of violation and could impose a fine in the future, Roberts said, one of several spill-related enforcement actions the agency is considering.

Derrick Braaten, a Bismarck lawyer whose firm represents dozens of farmers and landowner groups, said his clients often get little support from regulators when oil companies damage their property.

State officials step in in the largest cases, he said, but let smaller ones slide. Landowners can sue, but most prefer to take whatever drillers offer rather than taking their chances in court.

"The oil company will say, that's worth $400 an acre, so here's $400 for ruining that acre," Braaten said.

Daryl Peterson, a client of Braaten's who is not related to Darwin Peterson, said a series of drilling waste releases stretching back 15 years have rendered several acres unusable of the 2,000 or so he farms. The state has not compelled the companies that caused the damage to repair it, he said. Peterson hasn't wanted to spend the hundreds of thousands of dollars it would take to haul out the dirt and replace it, so the land lies fallow.

"I pay taxes on that land," he said.

At least 15 North Dakota residents, frustrated with state officials' inaction, have taken drilling-related complaints to the U.S. Environmental Protection Agency in the last two years, records show.

Last September, for example, a rancher near Williston told the EPA that Brigham Oil and Gas had plowed through the side of a waste pit [10], sending fluid into the pond his cattle drink from and a nearby creek. When the rancher called Brigham to complain, he said, an employee told him this was "the way they do business."

A spokeswoman for Statoil, which acquired Brigham, said the company stores only fresh water in open pits, not wastewater, and that "we can't remember ever having responded in such a manner" to a report about a spill.

Federal officials can offer little relief.

Congress has largely delegated oversight of oil field spills to the states. EPA spokesman Richard Mylott said the agency investigates complaints about releases on federal lands, but refers complaints involving private property to state regulators.

The EPA handed the complaint about Brigham to an official with North Dakota's Health Department, who said he had already spoken to the company.

"They said this was an isolated occurrence, this is not how they handle frac water and it would not happen again," the official wrote to the EPA. "As far as we are concerned, this complaint is closed." 

Salting the Earth
Six years ago, a four-inch saltwater pipeline ruptured just outside Linda Monson's property line, leaking about a million gallons of salty wastewater.

As it cascaded down a hill and into Charbonneau Creek, which cuts through Monson's pasture, the spill deposited metals and carcinogenic hydrocarbons in the soil. The toxic brew wiped out the creek's fish, turtles and other life, reaching 15 miles downstream.

After suing Zenergy Inc., the oil company that owns the line, Monson reached a settlement that restricts what she can say about the incident.

"When this first happened, it pretty much consumed my life," Monson said. "Now I don't even want to think about it."

The company has paid a $70,000 fine and committed to cleaning the site, but the case shows how difficult the cleanup can be. When brine leaks into the ground, the sodium binds to the soil, displacing other minerals and inhibiting plants' ability to absorb nutrients and water. Short of replacing the soil, the best option is to try to speed the natural flushing of the system, which can take decades.

Zenergy has tried both. According to a Department of Mineral Resources report, the company has spent more than $3 million hauling away dirt and pumping out contaminated groundwater — nearly 31 million gallons as of December 2010, the most recent data available.

But more than a dozen acres of Monson's pasture remain fenced off and out of use. The cattle no longer drink from the creek, which was their main water source. Zenergy dug a well to replace it.

Shallow groundwater in the area remains thousands of times saltier than it should be and continues to leak into the stream and through the ground, contaminating new areas.

There's little understanding of what long-term impacts hundreds of such releases could be having on western North Dakota's land and water, said Micah Reuber.

Until last year, Reuber was the environmental contaminant specialist in North Dakota for the federal Fish and Wildlife Service, which oversees wetlands and waterways.

Reuber quit after growing increasingly frustrated with the inadequate resources devoted to the position. Responding to oil field spills was supposed to be a small part of his job, but it came to consume all of his time.

"It didn't seem like we were keeping pace with it at all," he said. "It got to be demoralizing."

Reuber said no agency, federal or state, has the money or staff to study the effects of drilling waste releases in North Dakota. The closest thing is a small ongoing federal study across the border in Montana, where scientists are investigating how decades of oil production have affected the underground water supply for the city of Poplar.

Joanna Thamke, a groundwater specialist with the U.S. Geological Survey in Montana, started mapping contamination from drilling 20 years ago. She estimated it had spread through about 12 square miles of the aquifer, which is the only source of drinking water in the area. Over the years, brine had leaked through old well bores, buried waste pits and aging tanks and pipes.

In the Poplar study and others, Thamke has found that plumes of contaminated groundwater can take decades to dissipate and sometimes move to new areas.

"What we found is the plumes, after two decades, have not gone away," she said. "They've spread out."

Poplar's water supply is currently safe to drink, but the EPA has said it will become too salty as the contamination spreads. In March, the agency ordered three oil companies to treat the water or to find another source.

North Dakota officials are quick to point out that oversight and regulations are stronger today than they were when drilling began in the area in the 1950s. One significant difference is that waste pits, where oil companies store and dispose of the rock and debris produced during drilling, are now lined with plastic to prevent leaching into the ground.

New rules, effective April 1, require drillers in North Dakota to divert liquid waste to tanks instead of pits. Until now, drillers could store the liquid in pits for up to a year before pumping it out in order to bury the solids on site. The rule would prevent a repeat of the spring of 2011, when record snowmelt and flooding caused dozens of pits to overflow their banks.

But Reuber worries that the industry and regulators are repeating past mistakes. Not long before he left the Fish and Wildlife Service, he found a set of old slides showing waste pits and spills from decades ago.

"They looked almost exactly like photos I had taken," he said. "There's a spill into a creek bottom in the Badlands and it was sitting there with no one cleaning it up and containing it. And yeah, I got a photo like that, too."

Keller has grown so dispirited by the changes brought by the boom that he is considering retiring after 30 years with the Army Corps and moving away from Williston. He runs a side business in scrap metal that would supplement his pension.

Still, determined to protect the area, he keeps alerting regulators whenever he spots evidence that oil companies have dumped or spilled waste.

Last July, when he saw signs of a spill near his home, Keller notified the Health Department and sent pictures showing a trail of dead grass to an acquaintance at the EPA regional office in Denver. The brown swath led from a well site into a creek.

If the spills continued, he warned the EPA in an email, they could "kill off the entire watershed."

EPA officials said they spoke with Keller, but did not follow up on the incident beyond that. The state never responded, Keller said. The site remained untested and was never cleaned up.

"There was no restoration work whatsoever," Keller said.

This report, "North Dakota's Oil Boom Brings Damage Along With Prosperity", first appeared at propublica.org.