The standoff at Standing Rock was looking like turning to Wounded Knee 3 over the weekend, as a small army of veterans converged on the site to try to defend the "water protectors" protesting against the planned North Dakota Access pipeline.

While Donald Trump's financial ties to the project will no doubt ensure that he will attempt to ensure the success of the project as part of his 4 year plan to increase his wealth at taxpayer expense any way he can, for now the natives and the vets can relax as the Army Corps of Engineers decided to deny the pipeline company a permit for their planned river crossing.

The Army Corps of Engineers will not grant the permit for the Dakota Access pipeline to drill under the Missouri river, the army announced on Sunday, handing a major victory to the Standing Rock Sioux Tribe after a months-long campaign against the pipeline. Assistant secretary for civil works Jo-Ellen Darcy announced the decision on Sunday, with the army saying it was based on “a need to explore alternate routes” for the crossing.

The announcement came just one day before the corps’ deadline for thousands of Native American and environmental activists – who call themselves water protectors – to leave the sprawling encampment on the banks of the river. For months, they have protested over their fears that the pipeline would contaminate their water source and destroy sacred sites, and over the weekend hundreds of military veterans arrived at the camps in a show of support for the movement.

Art Berman has a post at Forbes looking rather skeptically at breathless reports about a "massive oil find" in the Permian basin in Texas (like this one - A $900 Billion Oil Treasure Lies Beneath West Texas Desert) - Permian Giant Oil Field Would Lose $500 Billion At Today's Prices. Tim Worstall isn't very impressed either - The Midland Basin Wolfcamp Shale Is Not Worth $900 Billion - That's Not How Resource Economics Works.

Read the source–the U.S. Geological Survey. The USGS did an assessment of the undiscovered, technically recoverable resources of the Wolfcamp shale in the Permian basin. “Undiscovered” means what it says–it has not been discovered. It’s an estimate, an educated guess. ”Technically recoverable resources” means the oil that could be produced if cost didn’t matter.

Where Did $900 Billion Come From?

Where did the $900 billion value come from? Multiply 20 billion barrels times $45 per barrel and you get $900 billion. In other words, if the oil magically leaped out of the ground without the cost of drilling and completing wells; if there were no operating costs to produce it; if there were no taxes and no royalties.

I'm always a little dubious about Ambrose Evans-Pritchard but over the years he has done a great job of covering the topic of oil production and energy geopolitics (albeit with his own political slant).

One of his recent columns in the UK Daily Telegraph has a look at comments from the IEA's Neil Atkinson on the state of the US shale oil industry and then does a roundup of global changes in oil supply and demand - Opec has failed to stop US shale revolution admits energy watchdog.

One key participant in the US shale oil boom was Chesapeake's Aubury McClendon, who recently perished in a car accident shortly after being indicted for various financial crimes.

Elsewhere in the oil patch, Amy Myers Jaffe of the Houston Chronicle's "FuelFix" site has an article on oil geopolitics and efforts to curb supply increases by various OPEC and non-OPEC countries - Commentary: In geopolitical conflict and oil Round 1 all parties score point. One interesting snippet was the claim that US shale oil producers have managed to cut break-even costs by 30-40% over the past year and have increased reserves.

Art Berman has an article in Forbes on the ending of the crude oil export ban in the US - The Crude Oil Export Ban--What, Me Worry About Peak Oil?. It's quite amazing just how much oil the US still imports after 10 years of the shale oil boom.

Congress ended the U.S. crude oil export ban last week. There is apparently no longer a strategic reason to conserve oil because shale production has made American great again. At least, that’s narrative that reality-averse politicians and their bases prefer.

The 1975 Energy Policy and Conservation Act (EPCA) that banned crude oil export was the closest thing to an energy policy that the United States has ever had. The law was passed after the price of oil increased in one month (January 1974) from $21 to $51 per barrel (2015 dollars) because of the Arab Oil Embargo.

The EPCA not only banned the export of crude oil but also established the Strategic Petroleum Reserve. Both measures were intended to keep more oil at home in order to make the U.S. less dependent on imported oil. A 55 mile-per-hour national speed limit was established to force conservation, and the International Energy Agency (IEA) was founded to better monitor and predict global oil supply and demand trends.

Above all, the export ban acknowledged that declining domestic supply and increased imports had made the country vulnerable to economic disruption. Its repeal last week suggests that there is no longer any risk associated with dependence on foreign oil.

TomDispatch has an article on life in the Bakken - Adrift in Oil Country.

I hadn’t driven nearly 2,000 miles from Brooklyn to work as a cocktail waitress in a strip club. (That only happened after I ran out of money.) I had set off with the intention of reporting on the domestic oil boom that was reshaping North Dakota’s prairie towns as well as the balance of both global power and the earth’s atmosphere.

This spring, production in North Dakota surged past one million barrels of oil a day. The source of this liquid gold, as it is locally known, is the Bakken Shale: a layered, energy-rich rock formation that stretches across western North Dakota, the corner of Montana, and into Canada. It had been considered inaccessible until breakthroughs in drilling and hydraulic fracturing made the extraction of oil from it economically feasible. In 2008, the United States Geological Survey (USGS) announced that the Bakken Shale contained 25 times more recoverable oil than previously thought, sparking the biggest oil rush in state history.

Now, six years later, the region displays all the classic contemporary markers of hell: toxic flames that burn around the clock; ink-black smoke billowing from 18-wheelers; intermittent explosions caused by lightning striking the super-conductive wastewater tanks that hydraulic fracturing makes a necessity; a massive Walmart; an abundance of meth, crack, and liquor; freezing winters; rents higher than Manhattan; and far, far too many men. To oil companies, however, the field is hallowed ground, one of the few in history to break the million-barrel-a-day benchmark, earning it “a place in the small pantheon of truly elite oil fields,” as one Reuters market analyst wrote.

Bloomberg has a look at the tendency to over-hype shale oil reserves - We're Sitting on 10 Billion Barrels of Oil! OK, Two.

Lee Tillman, chief executive officer of Marathon Oil Corp., told investors last month that the company was potentially sitting on the equivalent of 4.3 billion barrels in its U.S. shale acreage. That number was 5.5 times higher than the proved reserves Marathon reported to federal regulators.

Such discrepancies are rife in the U.S. shale industry. Drillers use bigger forecasts to sell the hydraulic fracturing boom to investors and to persuade lawmakers to lift the 39-year-old ban on crude exports. Sixty-two of 73 U.S. shale drillers reported one estimate in mandatory filings with the Securities and Exchange Commission while citing higher potential figures to the public, according to data compiled by Bloomberg. Pioneer Natural Resources (PXD) Co.’s estimate was 13 times higher. Goodrich Petroleum Corp.’s was 19 times. For Rice Energy Inc., it was almost 27-fold.

“They’re running a great risk of litigation when they don’t end up producing anything like that,” said John Lee, a University of Houston petroleum engineering professor who helped write the SEC rules and has taught reserves evaluation to a generation of engineers. “If I were an ambulance-chasing lawyer, I’d get into this.”

Tom Whipple is somehow still managing to beat the peak oil drum at The Falls Church News Press. His latest article ponders when the peak oil crisis so many doomers have been waiting for will finally occur - The Peak Oil Crisis: When?.

For those following the world oil production situation, it has been clear for some time that the only factor keeping global crude output from moving lower is the continuing increase in U.S. shale oil production mostly from Texas and North Dakota. Needless to say once the fabled “peak” comes, oil and gasoline prices are certain to move higher triggering a series of economic events – most of which will not be good for the global economy.

Thus the key question is just how many more months or years will production of U.S. shale oil (more accurately call light tight oil) continue to grow. Many have answers to this question ranging from the “next year or so” on out the middle or end of the next decade. Some forecasts as to time remaining until the “peak” arrives are politically tinged. No politician, business manager, or even investor wants to hear that serious economic problems affecting their lives may be only a few years away. Fortunately for these folks, there are many forecasters available to spin stories about how “technology” will enable US shale oil production to continue on into the dim future of the 2020’s – which most of us really can’t comprehend or plan for.

Usually missing from optimistic estimates for future U.S. shale oil production is any discussion of just how fast production from fracked wells declines. Most fracked wells are adequate or at least economic producers for three years or so, after which their production is so small that they need to be replaced or reworked to keep a meaningful amount of production going. As shale oil production grows larger and larger, more and more wells will have to be drilled and fracked just to keep production level. At some point there will be a cross over between new wells coming on stream and old wells going out of production so output will start to slip. The EIA recently noted that for North Dakota to increase its oil production by 20,000 barrels a day (b/d) next month, it must bring 94,000 b/d of new production online. At Texas’s Eagle Ford basin, it will take 152,000 b/d of new production next month to increase net production by 31,000 b/d.

There is no doubt that the shale oil drilling industry has made many significant technological advances in recent years. Multiple wells are now being drilled from a single drilling pad – foregoing the need to move drilling rigs and setting up all the expensive infrastructure needed to frack shale wells. For a while shale oil drillers were drilling and fracking longer wells which reduced the cost per barrel. Now we hear that drillers are increasing production per well by pumping more fracking materials down each well and some are saying this will be enough to offset any decline in prices. Currently US shale oil production is about 3 million b/d and in June output increased by about 100,000 b/d. About half of US shale oil production comes from North Dakota where winter conditions are so harsh that production has been falling during the winter months.

The two major forecasting agencies, Washington’s EIA and Paris’ IEA, are both more pessimistic than is generally known for they both foresee US shale oil production leveling off as soon as 2016. The reason for this is that drillers will simply run out of new places to drill and frack new wells. While new techniques of extracting more oil from a well are possible, there is need to look closely at the costs of these techniques vs. the potential payoff.

The shale oil situation in Texas is somewhat different than in North Dakota for there you have much better weather and two separate shale oil deposits. The recent growth in Texas’s shale oil production has been much smoother than in storm-prone North Dakota and has been increasing at about 44,000 b/d each month. So far as can be seen from the outside of the industry, production in both states will continue to grow for at least another year or two – but then we will be at 2016.

Bloomberg has a look at the borrowing boom underpinning the US shale oil boom - Drillers Piling Up More Debt Than Oil Hunting Fortunes in Shale.

A decade into a shale boom that has made fracking a household word and Wilson a rich man, drillers are propping up the dream of U.S. energy independence with a mountain of debt. As oil production hits a 28-year high, investors and politicians are buying into the vision of a domestic energy renaissance.

Companies are paying a steep price for the gains. Like Halcon, most are spending money faster than they make it, an average of $1.17 for every dollar earned in the 12 months ended on June 30. Only seven of the U.S.-listed firms in Bloomberg Intelligence’s E&P index made more money in that time than it cost them to keep drilling. These companies are plugging cash shortfalls with junk-rated debt. They owed $190.2 billion at the end of June, up from $140.2 billion at the end of 2011.

Bloomberg has an article on peak oil trader Andy Hall - Trader Who Scored $100 Million Payday Bets Shale Is Dud.

Andrew John Hall -- known as the God of Crude Oil Trading to some of his peers -- has built his success on a simple creed: Everyone who disagrees with him is wrong.

For most of the past 30 years, that has been a killer strategy. Like a poker player on an endless hot streak, Hall has made billions for the companies for which he’s traded by placing one aggressive bet after another. He was one of the few traders who anticipated both the run-up in and the eventual crash of oil prices in 2008.

Hall was so good that he bagged a $98 million payday in 2008, when he ran Citigroup Inc.’s Phibro LLC trading unit, and was up for about $100 million more in 2009. ...

His wager that oil prices would rise and rise has run headlong into an unanticipated energy revolution -- the frenetic push in the U.S. and elsewhere to wring crude out of shale. Shale drilling has boosted U.S. oil output to the highest level in 27 years; it helped the U.S. supply 84 percent of its energy demand last year. Oil prices, far from taking the upward trajectory Hall predicted, have been essentially unchanged since 2011. ...

“At one point, Phibro traders were the rulers of the world,” says Carl Larry, a former trader who publishes a newsletter on oil markets. “The best always learn how to adapt. Maybe it’s taking him longer to do that now. Or maybe his time has come.”

Hall, based on comments in his letters to investors, is unfazed by the losses and secure in his view that the price of oil is destined to rise. In those letters, he regularly mocks those who are convinced that a shale boom will mean long-term cheap, abundant energy. “When you believe something, facts become inconvenient obstacles,” Hall wrote in April, taking issue with an analyst who predicted a shale renaissance could result in $75-a-barrel oil over the next five years.

Hall is going all in on a bet that the shale-oil boom will play out far sooner than many analysts expect, resulting in a steady increase in prices to as much as $150 a barrel in five years or less.

Investing ever-larger sums of his own money, he’s buying contracts for so-called long-dated oil, to be delivered as far out as 2019, according to interviews with two dozen current and former employees and advisers who are familiar with Hall’s trading but aren’t authorized to speak on the record. To attract buyers, the sellers of these long-dated contracts -- typically shale companies that have financed the boom with mounds of debt -- need to offer them at a discount to existing prices.

The FT has a pair of pieces on the shale oil industry - one in-depth article comparing the optimistic and skeptic views of the shale oil boom / bubble and another letter to the editor declaring the shale boom the oil industry's "retirement party" - US shale: What lies beneath and Shale: last act at retirement party.

The skeptic view features long-time peak oil proponent Dave Hughes and Bill Powers.

The letter to the editor notes "The crippling problems of shale oil production remain, which are a depletion rate 10 times worse than a conventional well, to produce oil at a 10th of the rate, via wells that cost vastly more to drill than a conventional (land-based) well. Better perhaps than an offshore well, but with a desperate race to drill thousands of wells each year, every year to maintain present production levels."

One unpleasant side effect of the shale oil boom in North Dakota and the massive rise in using rail to move the oil across the US has been the alarming increase in disasters involving oil filled trains (the Lac-Mégantic disaster being the worst example). The Guardian has a report on the latest incident - North Dakota oil train crash sparks fireball.

A BNSF train carrying crude oil in North Dakota has collided with another train, setting off a series of explosions that left at least 10 cars ablaze, the latest in a string of incidents that have raised alarms over growing oil-by-rail traffic.

Local residents heard five powerful explosions just a mile outside of the small town of Casselton after a westbound train carrying soybeans derailed and an eastbound 104-car train hauling crude oil ran into it just after 2pm local time on Monday, officials said. There were no reports of any injuries. ...

Trains carried nearly 700,000 barrels a day of North Dakota oil to market in October, a 67% jump from a year earlier, according to the state Pipeline Authority.

This summer a runaway oil train carrying Bakken crude derailed and exploded in the centre of the Quebec town of Lac-Megantic, killing 47 people. The incident fuelled a drive for tougher standards for such shipments, including potentially costly retrofits to improve the safety of tank cars that regulators have cited as prone to puncture.

In early November two dozen cars on another 90-car oil train derailed in rural Alabama, erupting into flames that took several days to fully extinguish.

There has been a flurry of articles on Devon Energy's acquisition of a large amount of acreage in the Eagle Ford shale play. Shale Energy Insider has an example - Devon Energy to acquires assets in Eagle Ford for US 6bn. More at Reuters - Devon strikes Texas oil deal, plans to sell assets and Proactive investors - Oil Column: Eagle Ford shale to account for 15% of BHP Billiton’s cash flows.

Devon Energy has reached an agreement to acquire GeoSouthern Energy’s assets in the Eagle Ford oil play for $6 billion. The acquired assets include current production of 53,000 barrels of oil equivalent (BOE) per day and 82,000 net acres with at least 1,200 undrilled locations. The risked recoverable resource is estimated at 400 million barrels of oil equivalent, the majority of which is proved reserves.

The BS had an interesting snippet as it considered the implications of the deal for BHP, noting a massive increase in the recovery rate predicted for oil in the shale formation. Whether or not this is actually feasible I'm unsure - BHP US shale outlook improves.

The potential jump comes from much-improved expectations for how much oil the company can expect to get from its Texas holdings. BHP's partner in the Eagle Ford holdings, Devon Energy, has revealed that it expects recovery rates of 20 per cent of the oil in the shale, up from previous forecasts of only 7 per cent.

Those recovery rates not only bode well for cash output, but also in offsetting BHP's production costs. The figures were released as part of Devon Energy's $US6 billion ($A6.53 billion) purchase of BHP's 50 per cent partner GeoSouthern.

National Geographic has an article on the water demands of North Dakota's shale oil wells - North Dakota's Salty Fracked Wells Drink More Water to Keep Oil Flowing.

It's well known that water has been key to the shale oil and gas rush in the United States. But in one center of the hydraulic fracturing boom—North Dakota—authorities are finding that the initial blast of water to frack the wells is only the beginning.

The wells being drilled into the prairie to tap into the Bakken shale need "maintenance water"—lots of it—to keep the oil flowing.

So while the water first pumped down the hole to crack rock formations and release the underground oil and natural gas typically totals 2 million gallons (7.5 million liters) per well, each of North Dakota's wells is daily drinking down an average of more than 600 gallons (2,300 liters) in maintenance water, according to recent calculations by North Dakota's Department of Mineral Resources (DMR). Without water, salt buildup forms and restricts the flow of oil.

Climate Central has a look at the shale oil boom, quoting Dave Hughes and Arthur Berman - Fracking Boom Leading to Fracking Bust.

Scientists studying oil and gas well production data are beginning to question how long the boom will last, however, suggesting that a shale oil and gas bust may come sooner than expected, even as the industry insists that the boom has been and will continue to be a success.

British Columbia-based geoscientist David Hughes, whose research was presented at the Geological Society of America meeting this week in Denver, says the story hidden in oil well production numbers is that oil and gas production from fracking could peak in some places as soon as 2016.

Soon after the Jake well was drilled, the amount of oil it produced declined sharply. In just a few months in 2009, the well produced 48,373 barrels of oil, Colorado Oil and Gas Conservation Commission data show. By 2012, the Jake well’s annual production totaled 22,300 barrels. So far in 2013, the gusher has eeked out only about 6,000 barrels.

It’s the same picture in oil wells throughout the Niobrara shale, where oil production declines more than 65 percent in a new well’s first year of production, Hughes said.

In the Bakken shale of North Dakota, an oil play slated to tie into the controversial Keystone XL Pipeline, production declines 44 percent in the first year across the entire oil field. Production in the Eagle Ford shale south of San Antonio, Texas, declines 34 percent in the first year, according to Hughes’ data. Production in the Haynesville oil field in Texas and Louisiana peaked after just 5 years, he said.

And as Hughes noted, the more production drops off in individual oil wells, the more wells companies have to drill and frack to make up the difference.

Bloomberg has a (2 week old) article on the fading shale oil boom in the US - Shale Grab in U.S. Stalls as Falling Values Repel Buyers.

Oil companies are hitting the brakes on a U.S. shale land grab that produced an abundance of cheap natural gas -- and troubles for the industry. The spending slowdown by international companies including BHP Billiton Ltd. (BHP) and Royal Dutch Shell Plc (RDSA) comes amid a series of write-downs of oil and gas shale assets, caused by plunging prices and disappointing wells. The companies are turning instead to developing current projects, unable to justify buying more property while fields bought during the 2009-2012 flurry remain below their purchase price, according to analysts.

Resilience has an article on oil and gas production in Argentina (which indirectly explains why the Chileans are so interested in large scale solar power now), including a look at the reputedly large potential for shale oil production in Patagonia - Argentina: energy boom or energy cliff?.

At the end of the 20th century, Argentina started exporting gas to Chile, a mirage of the gas possibilities in this country. Both Argentina and Chile believed that the supply was going to be increasing forever. I visited Chile invited by Compañía de Petróleos de Chile (COPEC) in 2011. I also had the opportunity to meet with top officials of the energy sector and academic experts in energy. They all believed that Argentienan supplies would last for decades. I could not understand why very professional people had such a belief, when data on reserves and possible flows of their neighbour country was probably available to them.

In fact, they embarked in an ambitious plan to develop pipelines across the Andes to supply Chile from the Argentinean network and ordered a number of gas fired power plants, trying to avoid or minimize, for instance, the heavy smog of Santiago, and for other economic reasons. However, and without previous warning, Argentina reduced shipments to less than half. The obvious reason, as seen in the figures above, was the depletion pattern of the Argentinean gas and the need to prioritize their own domestic consumption. This left overnight the Chileans with big recently erected infrastructures idle and difficult problems to attend their growing internal energy demand, especially in electricity production for the extractive industries that they had expected to satisfy with the gas fired power plants.

They had to move fast to build a regasification plant in Quintero and now another in Mejillones. They did it in a record time, but certainly at a cost they had not imagined. This coincided with the sharp increase of fuel consumption that had started at the end of the past century. They needed to sign urgent contracts with LNG tankers and suppliers (i.e. Qatar), something that created for them what they called the perfect storm. Chile was in 2011 paying one of the most expensive electricity tariffs in the continent, partly due to this important bad planning.

CleanTechnica has a look at the headwinds facing the shale oil industry - The Fracking Chickens Are Coming Home To Roost. Grist has a similar artice - Fracking frenzy slows as oil and gas assets plummet in price.

This won’t be the first time we’ve heard whispers of impending doom for the natural gas fracking industry, but since this one is coming from Bloomberg it’s probably worth a listen, so here’s the deal. Yesterday, Bloomberg reported that the boom in gas field purchasing from 2009 to 2012 has turned into a whopper of a bust, leaving oil and gas companies with a belly load of depressed assets and “disappointing” wells to go with falling gas prices.

Ambrose Evans Pritchard has his own farewell to The Oil Drum at The Daily Telegraph, remaining skeptical that we've got an endless supply of oil just waiting to flow out of the ground - Commodity supercycle in rude health despite shale.

The Oil Drum is closing down after eight years, giving up the long struggle to alert us all to "peak oil" and the dangers of an energy crunch. Readers have been drifting away. The theme has gone out of fashion, eclipsed by shale and fracking in the US. ...

But though fracking is a Godsend, let us not lose our heads. The US Energy Department expects shale oil to add 3.1m bpd to America's oil output by 2020, a remarkable feat but far less than the 5.4m estimates of a much-cited study by Leonardo Maugeri at Harvard.

The depletion rate on rigs at the Bakken field in North Dakota - the biggest US shale field - is precipitous. Output falls 30pc within two years, and a third is leaking into the air. Shale bears say average declines are nearer 70pc in the first year, and dismiss the whole craze as a bubble.

That is going too far. The technology is improving every week. The decline rate may flatten over time. Yet claims of a 100-year bonanza in the US are wishful thinking. "The upper limit of supply is likely closer to 23 years using present day rates of consumption," said the Eos report.

Kevin Norrish from Barclays said US drillers have already tapped the "best plays" for shale, with newer Utica ventures in the north east of the US and Canada coming up short. The biggest productivity leaps may already have happened. "We expect a steep slowdown in the rate of tight oil production growth from the middle of this decade onward," he said.

Barclays is defiantly holding to a Brent crude forecast of $184 in 2020, betting that spare capacity in global output will prove thinner than supposed, and that oil shocks will come back to haunt us.

We should think of shale as one-generation play for the US, enough to ensure American superpower primacy into the middle of the century. Whether the rest of the world can follow suit in any meaningful time-frame is an open question. Boston Consulting Group said there were 110,000 shale wells in the US and Canada by the end of last year, and just 200 in all other countries combined. Argentina, Poland and Ukraine may try to get going after 2015 but they have almost no service infrastructure, and all score badly on "ease of doing business". Australia may do better from 2017 onwards.

China has the world's biggest reserves on paper. It is itching to start but much of its shale is in the north-west desert where there is no water, and frackers have yet to find a viable extraction process without water. Not one of the 19 drilling awards issued by the Communist authorities in January went to companies with oil and gas experience. They were mostly power utilities or coal miners.

Even if China seizes the prize, it will first have to build a vast network of pipelines. That will take a great deal of energy, long before shale supply reaches the market. ...

We all love a fresh narrative but consensus has swung too fast from the 2008 oil panic to the energy complacency of 2013, and done so on slender evidence. As matters stand, peak cheap oil remains an incontrovertible fact. To Oil Drum, a fond farewell.

The Guardian has an article on the unfortunate intersection of the Texas drought and shale oil boom - A Texan tragedy: ample oil, no water.

Beverly McGuire saw the warning signs before the town well went dry: sand in the toilet bowl, the sputter of air in the tap, a pump working overtime to no effect. But it still did not prepare her for the night last month when she turned on the tap and discovered the tiny town where she had made her home for 35 years was out of water.

"The day that we ran out of water I turned on my faucet and nothing was there and at that moment I knew the whole of Barnhart was down the tubes," she said, blinking back tears. "I went: 'dear God help us. That was the first thought that came to mind."

Across the south-west, residents of small communities like Barnhart are confronting the reality that something as basic as running water, as unthinking as turning on a tap, can no longer be taken for granted.

Three years of drought, decades of overuse and now the oil industry's outsize demands on water for fracking are running down reservoirs and underground aquifers. And climate change is making things worse.

In Texas alone, about 30 communities could run out of water by the end of the year, according to the Texas Commission on Environmental Quality.

Nearly 15 million people are living under some form of water rationing, barred from freely sprinkling their lawns or refilling their swimming pools. In Barnhart's case, the well appears to have run dry because the water was being extracted for shale gas fracking.

The town — a gas station, a community hall and a taco truck – sits in the midst of the great Texan oil rush, on the eastern edge of the Permian basin.

A few years ago, it seemed like a place on the way out. Now McGuire said she can see nine oil wells from her back porch, and there are dozens of RVs parked outside town, full of oil workers.

But soon after the first frack trucks pulled up two years ago, the well on McGuire's property ran dry.

No-one in Barnhart paid much attention at the time, and McGuire hooked up to the town's central water supply. "Everyone just said: 'too bad'. Well now it's all going dry," McGuire said.

FuelFix has a post on Shell's recent profit decline and asset writedowns, driven by poor performance from their North American shale oil assets - Peak oil researcher says shale profits proving ephemeral. The post points to an article by Art Berman, continuing his long line of analysis questioning the longevity and financial basis of the shale oil boom - Shale boom profits bypass big oil. Even the Wall Street Journal was prompted to ask "So why has Shell just wiped $2 billion off the value of some shale assets supposedly rich in the hydrocarbon liquids that everyone craves?". They couldn't come up with an answer.

A prominent proponent of peak oil theory — the idea that global petroleum production will peak and then begin dropping off permanently — says that recent Big Oil profit drops show that profits from shale are more elusive than commonly expected.

Many of the oil industry’s big players wrote down the value of their shale assets for second quarter — a move that indicates the continuing challenge of making many of the shale plays financially viable, according to Art Berman, a petroleum geologist and director of the Association for the Study of Peak Oil. Berman, a Houston-area geologist, has been questioning the economics of shale gas for years, particularly in terms of the potential reserves.

Last week, Shell reported a 20 percent profit drop for second quarter, which it partially attributed to write-offs of some of its shale positions rich in natural gas liquids and oil, according to Simon Henry, Shell’s chief financial officer, at the second quarter earnings call.

“Recent revelations and write-downs of shale assets in North America by Shell, ExxonMobil and Chevron support our research that big companies cannot make money on low rate-low volume shale wells,” wrote Art Berman in an article on Petroleum Truth Report. Berman said that when ExxonMobil purchased XTO Energy in 2010, it began the acceptance of shale reserves as a potential income driver, and optimistic estimates were made about the potential production of many of these wells. But falling oil and gas production helped push earnings down 57 percent for the second quarter.

Berman predicts that the companies will begin to move out of the shale plays because of the difficulty in making them profitable. “I believe that we are seeing the slow liquidation of these organizations but they cannot let the investment public know that this is what is occurring,” Berman wrote. “Hence the cornucopian rhetoric about the shale revolution and North American becoming the next Saudi Arabia –pure poppycock, of course.”