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Moab energy company testing fracking method near Dead Horse Point, Canyonlands

By Brian Maffly

A Moab energy company is testing a novel method of fracking at its booming oil field outside Canyonlands and Dead Horse Point State Park.

The experimental extraction method — injecting oil rather than chemical-laden water underground — has shaken environmentalists already worried about the industrialization of a scenic area.

Fidelity Exploration and Production Co.’s wells on Big Flat have been among the nation’s most productive in 2012. But more recently drilled bores haven’t been yielding as much crude lately.

So last week, the company injected fluids in a well near Dead Horse Point in hopes of “stimulating” its outflow, according to Fidelity officials.

The hydrocarbon formation outside Moab, known as Paradox Basin, contains naturally occurring fissures that can be damaged by water, according to company spokesman Tim Rasmussen.

“We needed to find a fluid that would not damage the reservoir while at the same time being environmentally benign,” he said.

With fracking, fluids are pumped under extreme pressure into sandstone formations to force fissures that allow trapped oil and gas to flow into the well bore. The technique is credited with spurring a boom in domestic oil and natural gas production and subsequently declining prices.

But the process is fraught with controversy. Critics say fracking is not adequately regulated as companies inject vast amounts of chemical-laden fluids that could contaminate groundwater.

Fidelity’s engineers settled on a 2,200-barrel mixture of crude from the well itself and food-grade oil — a far smaller volume than is usually used in a water-based fracking operation.

Still, environmentalists say public land managers should study the impact of oil fracking before the company goes any further.

Local activist Bill Love is concerned fracking fluids could escape the well bore and migrate toward the two major rivers that pass through the area’s two national parks and two national recreation areas and provide water for millions.

“BLM has not done a study. The National Park Service needs to have a study,” said Love, who co-founded the Canyon Country Coalition for Pipeline Safety.

Drilling started on Big Flat in the early 1960s, but it wasn’t until Fidelity took over the Cane Creek unit in the late 2000s that wells there became a commercial success — without the help of a single fracking system or even a pump jack in many cases.

Rasmussen said past operators have fracked the Paradox formation, but without success.

Fidelity’s newly fracked well was completed last spring. Monthly production started with 4,144 barrels in April and steeply tapered to 1,165 barrels by September, according to state records.

The well descends 7,500 vertical feet into the oil reservoir then bends 90 degrees and travels laterally in a northeasterly direction for another 5,000 feet through the reservoir.

Fidelity injected the oil only in the toe of that horizontal leg, the half farthest from the vertical bore.

The well will remain shut in while it stabilizes, then it will be “flowed back.”

“Initial flow-back rates will be controlled and monitored,” Rasmussen said. “These rates will be compared to production before the treatment to determine the effectiveness of the experimental design.”

If production improves, Fidelity may try the technique elsewhere on Big Flat.

“We do not believe that the Big Flat wells are good candidates for traditional massive fracture treatments,” Rasmussen said. “The purpose of this stimulation is different and, if successful, could result in better recovery from our existing wells.”

Fracking with water would leave a much larger footprint than what Fidelity is pursuing, the company maintains. It takes at least 1 million gallons of water, often loaded with diesel, methanol, surfactants, gelling agents and other chemicals, to frack a well.

Water is scarce in Grand County and places to dispose of spent fracking water are even scarcer.

Rasmussen said the frack oil can be recovered and sold, therefore the operation won’t deplete local water supplies nor pose a disposal burden.

But local environmentalists remain concerned about the lack of an environmental analysis of the operation and the possibility of fracking fluids fouling groundwater.

Most of the 100-square-mile oil field is on federal land checkerboarded with state sections. The fracked well, known as Cane Creek 32-1, is on state land and could be fracked without Bureau of Land Management approval.

The state Division of Oil, Gas and Mining reviewed Fidelity’s plan and signed off on it, agency spokesman Jim Stringer said.

Wells are fracked daily elsewhere in Utah. But Big Flat is different. It’s located at the doorstep of cherished pristine lands, including Canyonlands’ Island in the Sky, on a plateau 2,000 feet above the Colorado and Green rivers.

Moab activist Love notes two “beautiful” springs are in the area — one in Hell Roaring Canyon and another outside Upheaval Dome.

“They have not taken baseline samples from the springs,” Love said.

Love’s group already is grappling with Fidelity over a network of pipelines the BLM has approved to move copious volumes of natural gas that come up with the oil and are flared at the wellheads.

At least 18 wells are producing oil on Big Flat and Fidelity drills non-stop there. BLM predicts another 50 wells are on the way.

Fidelity’s parent, MDU Resources Group, recently announced plans to sell the company that has been spending heavily on Big Flat. Despite a $150 million investment this year, daily production has inched up just 5 percent to 2,400 barrels, according to its most recent financial disclosure to investors.

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Article Source: Maffly, B. (2014). Moab energy company testing fracking method near Dead Horse Point, Canyonlands. Salt Lake Tribune. Retrieved from

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100 pairs of work socks headed to oil field

Jeff Bahr | Aberdeen News

Hannah LaJoie wasn’t interested in winning a 5K Fun Run/Walk on Saturday morning. She cared a lot more about being honored for her flamboyant socks.

Hannah, 10, sported a colorful look in the “Run Your Socks Off” 5K event, organized by North Highland United Methodist Church.

You can be sure her legs weren’t cold. Hannah was wearing eight pairs of socks, which created a wild rainbow effect. She also had four pair of socks elsewhere on her body.

Why was Hannah wearing the wacky attire?

“Well, because I love wearing crazy socks,” said the Warner student.

Over the summer, the Boys and Girls Club had a crazy socks day and Hannah took that event. She describes herself as “really competitive.”

So Hannah was happy after Saturday’s run when she and her 4-year-old sister, Kenna Wolberg, were honored for their socks. They were the two young people who won sock awards.

More importantly, though, a lot of people in the North Dakota oil fields will be wearing better socks because of the event.

The entry fee for the fun run was a pair of work socks, each of which will be shipped to folks in the Bakken oil basin. “We collected close to 100 pair,” said the Rev. Lou Whitmer, pastor of North Highland.

About 50 people covered the 5K course. The event was a project of the Bakken Oil Rush Ministry, which is organized by United Methodist churches in the Dakotas.

Whitmer knew that several members of the church like to run, so the run seemed like “a fun way to do a mission program,” she said.

Many of the participants dressed for the occasion. Fashion choices ran from argyle to stripes galore. Participants ranged from Michael Hartung, who’s run four marathons, to babies in strollers.

Ten-year-old twins Zachary and Nathan Palmer joined their mother, Lesleann, at the fun run/walk. Lesleann was there because of her best friend, Amber Huff, who invited her. “I knew she wouldn’t turn down a chance to do a run,” Huff said.

Also taking part was Huff’s sister, Miranda Telin, and her parents, Al and Kristie Scherbenske, who go to church at North Highland. They told Telin about the event “and I thought it was a good fundraising effort for people in North Dakota,” she said.

Two of the participants, De Basham and Dar Retzer, recently saw a missionary from the Bakken area speak at First United Methodist. The speaker lives in Williston, where her rent is $2,500 a month.

Hannah and Kenna participated with their grandmother, LeAnn Conn.

The run/walk was just the start of a busy day for the Sarah and Nathan Miller family. Later in the day, their three sons had soccer games. Sarah ran the 5K course Saturday because she likes to run. She was on the cross country team at Edmunds Central, when her name was Sarah Miles. “Run Your Socks Off” was her third 5K, the second one this year.

The 5K was successful enough that North Highland will have another fundraiser next September.

“It was really fun to have the community support along with the people of the church,” Whitmer said. “And it was a beautiful day and lots of energy.”



Texas Proposes Tougher Rules On Fracking Wastewater After Earthquakes Surge

The agency that regulates oil and gas activity in Texas is considering new, tougher regulations governing the practice of injecting leftover water used to frack natural gas wells deep into the ground — a process which is believed to be responsible for an increase in human-caused earthquakes across the state.

The Texas Railroad Commission’s new proposed regulations on wastewater injection wells were heard by members of the Texas House of Representatives’ Subcommittee on Seismic Activity on Monday, following complaints that earthquakes have become more frequent over the last several years. Dr. Craig Pearson, the Railroad Commission’s new seismologist, told the subcommittee that the regulations would help make sure injected wastewater doesn’t migrate onto inactive fault lines and cause man-made quakes.

“Because we’re now dealing with induced seismicity, the worry is not only about water moving up [to our groundwater] but out to dormant faults,” Pearson said, noting that current regulations are only designed to protect from groundwater contamination.

The controversial technique of hydraulic fracturing, otherwise known as “fracking,” uses a great deal more water than conventional drilling. To stimulate natural gas wells, companies inject high-pressure water and chemicals miles-deep into subsurface rock which effectively cracks or “fractures” it, making the gas easier to extract.

The leftover wastewater used to frack the well is disposed of by injecting it deep underground, and scientists increasingly believe that this is causing man-made earthquakes — not only in Texas, but across the country. The large amount of water injected into the ground can change the state of stress on existing fault lines to the point of failure, scientists believe, causing earthquakes.

As it is now, Pearson said most of the earthquakes occurring in Texas are too small to be felt. But some scientists have warned that seismic activity stands to get stronger and more dangerous as fracking increases, and more wastewater propagates along fault lines underground.

If Texas’proposed rules on wastewater disposal wells are approved, companies seeking to operate them would have to include United States Geological Survey records of seismic events that have occurred around proposed well sites in their permit applications. The commission estimated that this would cost companies an additional $300, which the rules describe as “negligible.”

Additionally, the commission would be allowed to suspend or terminate any wastewater disposal operator’s permit if it finds that fluids have been leeching past where they’re supposed to be. It would also be allowed to terminate an operator’s permit if the operator is found to be responsible for earthquakes. The rules would not require that permits be suspended for fluid-leeching violations or earthquakes; instead, they would just give the commission the authority to do so if it wanted to.

The commission would also be allowed to require more frequent monitoring of fluids and pressure from certain companies, and to request additional information from the application to prove that fluids won’t spread across fault lines.

So far, environmentalists have applauded the rules as a good start, but have expressed concerns that they don’t go far enough.

“It’s kinda like when you’re in a 12-step program,” Cyrus Reed with the Sierra Club told Terrence Henry at StateImpact NPR. “You know, the first thing you need to do admit that you have a problem. And I think the Railroad Commission has done that by proposing these rules.”

Indeed, the Railroad Commission has come a long way from January, when commission Chairman Barry Smitherman refused to acknowledge that the quakes were linked to any part of the fracking process. “It’s not linked to fracking,” he told local reporters after a meeting of concerned citizens. “If we find a link then we need to take a hard look at all these injection wells in this area. Reexamine them … Perhaps there something that we’re not aware of underground.”

The Texas commission is taking public comment on the proposed rules until next month.



5 Tax Changes Small Business Owners Need to Prepare For

Though it still may be barbecue and beach season, the end of 2014 will be here before you know it. For consumers, this means holiday shopping and New Year’s resolutions. But for business owners, it also means getting financial ducks in a row in preparation for the upcoming tax season.

There are many new and pending changes for the upcoming tax season, and some of them will be particularly important for small businesses. Based on conversations with tax experts, here are a few upcoming issues you may want to speak with your financial adviser about as you look toward year-end tax planning.

The Affordable Care Act. The ACA should be at the forefront of a business’s tax planning agenda, especially if the business is over or close to the 50-employee threshold, said Timothy Todd, CPA and assistant professor of law at Liberty University School of Law. With the administration beginning to enforce the mandate in 2015, now is the time to plan, Todd said. For some employers, the mandate has been pushed out to 2016, so discuss this with your tax adviser if you’re unsure how you’ll be affected.

Corporate tax rates. Mike Trabold, director of compliance risk atpayroll processing company Paychex, noted that one key issue in upcoming tax-reform proposals is corporate tax rates. Companies that are structured as corporations currently pay a higher tax rate than LLCs, partnerships and other tax-efficient business structures. Trabold said that if tax rates are lowered for corporations,small businesses that are structured a different way wouldn’t get the same tax advantages unless there were a parallel amendment to personal tax rates.

Deduction eliminations and limit reductions.Small business owners will find that some tax credits they once depended on have expired or have been greatly reduced, saidJohn Hewitt, CEO of Liberty Tax Service. Section 179 allows business owners to deduct the entire cost of certain assets, such as equipment and furniture, in the year of purchase rather than over a longer period of time. In the 2013 tax year, the deduction limit was $500,000, but this year, it has dropped significantly to $25,000. Bonus depreciation, whereby businesses could claim a 50-percent deduction for qualified property they placed into service in the tax year, ended in 2013. The work opportunity tax credit, which had given employers a credit of up to $9,600 for hiring veterans and other workers in specific categories, is also gone, as is the energy tax incentive that helped employers go green by giving deductions for eco-friendly business features such as lighting.

Net investment income tax. The 3.8 percent tax on net investment income became effective in 2013, but it may surprise you if you are being affected for the first time in 2014. Todd explained that the tax applies to high-income individuals with investment income. Common scenarios where this new tax may be implicated is if you have rental income, a stock portfolio or other “passive” income.

Tax extenders. The proposed “tax extenders” bill is an effort to renew $85 billion in temporary tax breaks for individuals and businesses. Although Reuters reported that the bill is stalled in the Senate until after the congressional elections in November, any decisions that follow may affect the 2015 tax season, Trabold said. Whether your business has been taking advantage of any of the 50 tax breaks included in the bill or not, it’s important to be prepared either way.

So what can you do now to make things easier when tax preparation season rolls around in a few months? The first thing you’ll want to do is to make sure your records are up-to-date and that your financial documents are organized and easily accessible for tax season, especially for any potential deductions.

“Save everything,” Todd said. “A lot of deductions require extra substantiation, such as meals, entertainment expenses and use of a personal vehicle. There’s been a spate of tax court cases lately that has disallowed business deductions due to lack of record keeping. If your business is audited, this is low-hanging fruit for the IRS to disallow.”

Another smart tax-prep move is to take advantage of technology that will make organization and record-keeping easier for yoursmall business. Jonathan Barsade, CEO of sales tax solutions provider Exactor, advised seeking a tax solution that is comprehensive, low-maintenance and easy to use.

“Modern technologies can automate the entire [tax] process for the small business owner, from the point of calculating the taxes at the time of the transaction, through the final generating and filing of the tax returns,” Barsade told Business News Daily.”There is no reason why a small business owner should spend any more than an hour each month on all of their tax compliance needs. The earlier the business owner proceeds towards automation, the less time they will need to work in tax season, which means more time remaining to focus on your business.”

Most importantly, keep these and other tax issues on your radar by following financial news and checking in regularly with your accountant or tax adviser.

“Tax code changes regularly, and this year is no exception,” Hewitt said. “A tax adviser will help ensure that your [documents] are organized and that your business is taking advantage of any tax savings that may be available. Depending on your situation, you may want to purchase new equipment, defer income or even hire personnel before the end of the year for tax savings purposes. A tax adviser can look at the business and help answer those questions.”

“Things can change very quickly,” Trabold added. “[Certain tax reforms] could be a real benefit to a small business, and you wouldn’t want to lose an opportunity because you didn’t move on it quickly enough. Keep an eye on the changing winds, and be ready to act if necessary.”



Is Foam About To Transform The Oil Recovery Business?

The best way to get oil out of the ground may be to pump in foam.

Scientists pumped foam into an experimental rig that mimicked the flow paths deep underground and found the foam was more effective than more commonly used materials, such as water and gas.

Oil rarely sits in a pool underground waiting to be pumped out to energy-hungry surface dwellers. Often, it lives in formations of rock and sand and hides in small cracks and crevices that have proved devilishly difficult to tap. Drillers pump various substances downhole to loosen and either push or carry oil to the surface.

Sibani Lisa Biswal, associate professor of chemical and biomolecular engineering at Rice University, created the experimental formations—they look something like children’s ant farms—to see how well foam stacks up against other materials in removing as much oil as possible.

The formations are not much bigger than a postage stamp and include wide channels, and large and small cracks. By pushing various fluids, including foam, into test formations, the researchers can visualize the ways by which foam is able to remove oil from hard-to-reach places.

They can also measure the fluid’s pressure gradient to see how it changes as it navigates the landscape.

Paths of less resistance

The findings are strongly in foam’s favor. Foam dislodged all but 25.1 percent of oil from low-permeability regions after four minutes of pushing it through a test rig, versus 53 percent for water and gas and 98.3 percent for water flooding. This demonstrated efficient use of injected fluid with foam to recover oil.

The less-viscous fluids appear to displace oil in high-permeability regions while blowing right by the smaller cracks that retain their treasure. But foam offers mobility control, which means a higher resistance to flow near large pores.

“The foam’s lamellae (the borders between individual bubbles) add extra resistance to the flow,” Biswal says. “Water and gas don’t have that ability, so it’s easy for them to find paths of least resistance and move straight through. Because foam acts like a more viscous fluid, it’s better able to plug high-permeable regions and penetrate into less-permeable regions.”

Foam tends to dry out as it progresses through the model, says graduate student Charles Conn, lead author of the paper that is published in the journal Lab on a Chip. “The bubbles don’t actually break. It’s more that the liquid drains away and leaves them behind.”

Drying has two effects: It slows the progress of the foam even further and allows surfactant from the lamellae to drain into low-permeability zones, where it forces oil out. Foam may also cut the sheer amount of material that may have to be sent downhole.

One of the challenges will always be to get the foam to the underground formation intact. “It’s nice to know that foam can do these things, but if you can’t generate foam in the reservoir, then it’s not going to be useful,” Conn says. “If you lose the foam, it collapses into slugs of gas and liquid. You really want foam that can regenerate as it moves through the pores.”

Biswal says her lab plans to test foam on core samples that more closely mimic the environment underground.

George Hirasaki, professor emeritus of chemical and biomolecular engineering and Kun Ma, a Rice alumnus, are coauthors of the paper.

The Department of Energy, the Abu Dhabi National Oil Co., the Abu Dhabi Oil R&D Sub-Committee, the Abu Dhabi Co. for Onshore Oil Operations, the Zakum Development Co., the Abu Dhabi Marine Operating Co. and the Petroleum Institute of the United Arab Emirates supported the research.




Energy Investing 101: Identifying the Top Independent Oil & Gas Stocks

Three to five years ago, investing in the American shale boom was pretty easy. You could print out a list of energy companies, pin them to a wall, then throw darts blindfolded, and the companies you landed on would likely trounce the S&P 500. Today, though, it’s not as simple, and investors who want to make good decisions in this space will need to do some more digging.

Here’s the nice part: Understanding an oil and gas producer isn’t that difficult. There are, of course, the financial metrics we all know and love as well as stock valuations, but there are some more specific keys you should consider when looking specifically at independent oil & gas producers. Let’s take a deeper dive into this industry to find out how you can make better basic investing decisions in the independent oil & gas space.

Who are we talking about, here?
Unlike integrated oil and gas companies, independents exclusively produce oil and gas, That means no downstream assets like refiners or retail arms. In some ways, it makes them much easier to understand, because you don’t have to sift through multiple business segments to identify the primary driver of profitability for the company. 

The thing is, hundreds of independents are publicly listed on major U.S. exchanges. They can vary in size from having a market capitalization of only a couple million dollars all the way up to ConcoPhillips (NYSE: COP  ) , which today is valued close to $100 billion. Unlike other groups within the energy space like Big Oil and offshore rigs, there are simply too many companies to list them all, or even pick a dozen or so without missing out on some great investing opportunities. 

Five key points to consider
In all honesty, there is a bunch of noise that can distract you when trying to identify what is important. So many investors today are worried if companies are in the top shale producing regions, but what good does knowing which shale plays are the best if a company has holdings in a poor part of that formation that barely produces anything? At the same time, there are other companies that don’t even operate in shale that can be just as lucrative investments. If you are looking to buy companies on a truly long-term, buy-and-hold strategy, then you need to focus on other keys that are much more important than geography.

To help filter out the noise, here are five key points you should dig into when you are doing your homework. To mention every company would be a little exhausting, so instead — to give you a little leg up on your research — I will supply three leaders and three laggards for each of the five points below that have a market capitalizations of more than $500 million.

1. Production potential: Go beyond just proved reserves
One of the major misconceptions about the term “proved reserves” is that many assume its the amount of oil in a reservoir. Actually, it is the amount of oil & gas in that reservoir that a company estimates can be extracted with a reasonable rate of return based on prices set by the Securities and Exchange Commission. This means the total proved reserves for a particular formation can change as prices vary, or if technology makes it cheaper to access that formation. Here is a great visual explanation of this from the U.S. Energy Information Administration.

Source: U.S. Energy Information Admininstration.

To get a better understanding of how much resource potential a company has, it’s better to look at what is known as the 3P resources. This means proved, probable, and possible resources. This data gives a little more clarity to how much oil and gas a company can extract if prices were to change, or if technology improves. Not every company provides this information, but if they do, it can be found in its 10-K.

Another thing to consider when looking at reserves — and production — is how much of those reserves are in oil, gas, or natural gas liquids. Generally speaking, companies that have higher reserves and production in oil will generally have higher profit margins, because oil has a greater value on the market, but this isn’t always the case.

2. Reserves to production ratio
The total amount of oil and gas that a company can access isn’t that valuable of information if not taken in context, though. That is where the reserves to production ratio comes into play. The reserves to production ratio is the total amount of reserves a company has on its books divided by its total production, which is typically measured in years. 

This is a very crude metric because it assumes two things that are highly unlikely: First, that current proved reserves will remain constant, which also implies that oil and gas prices will remain constant and no new technology will make more oil in place attainable, and second, that production will remain constant over this entire period. Any oil and gas produce worth their salt will look to both increase reserves and production, so the reserve-to-production ratio is only a snapshot of the current situation. If you want to get a little more involved you can do some quick calculations to compare production to 3P reserves or technically recoverable resources as well.

Company Reserve to Production Ratio % of Reserves That Are Oil/Liquids
Antero Resources  35.8 years 1%
PDC Energy   29.6 years 41%
Continental Resources  21.8 years 66%
SM Energy 6.7 years 37%
Kosmos Energy  5.9 years 96%
W&T Offshore 5.6 years 56%

Source: S&P Capital IQ, author’s calculations.

3. Reserve replacement costs
One important factor to note is that not all reserves are created equal. Certain sources of oil are simply more expensive to access than others, and the ability to access these sources as cheaply as possible can be a major determinant of the future profitability of a producer. We can evaluate this by looking at reserve replacement costs, which is defined as the amount spent on exploration, development, and acquisitions (net of divestitures) divided by the total amount of reserve revisions, extensions, new finds, and acquisitions.

According to the most recent annual survey from Ernst & Young, the average reserve replacement cost in the industry was $20.30 per barrel of oil equivalent. As you can see in the table below, these costs can be heavily influenced by whether a company is bringing on reserves of oil or gas.

Company Reserve Replacement Costs % of Reserve Additions That Was Oil/Liquids
Antero Resources $3.84 0%
Cabot Oil & Gas  $4.56 1%
Range Resources  $4.97 24%
Newfield Exploration $34.47 100%
Pioneer Natural Resources $128.19 76%
Encana  $129.28 100%

Source: Ernst & Young.

4. Production costs vs. production mix
Not only does a company need to be able to secure its future on the cheap, but investors like us want to find the great operators that are able to produce oil and gas today at a decent price. This is where production costs come into play. Production costs are very similar to operational expenses on an income statement, but without depletion and amortization expenses, since they are a non-cash expense. Most companies will report their production costs on a per barrel of oil equivalent or per thousand cubic feet of gas equivalent for its total production. 

Here’s the catch when looking at these costs, though: The value for oil is considerably higher than that of natural gas. Looking at a survey of independent oil and gas producers, the production cost per barrel compared to the percentage of production that is oil looks a little something like this:

Source: Ernst & Young, Company 10-Ks and 40-Fs, and S&P Capital IQ, author’s calculations.

Therefore, a company that produces a higher amount of oil can be forgiven for having higher production costs, but not too much. So, when you are looking at production costs, be sure to take it into context with the production mix. The companies in the table below are rated and presented based on their production costs per barrel, and the percentage of their production that was liquids.

Company Produciton Costs Per Barrel Equivalent % Production That Was Oil/Liquids
EQT Corp $2.07 <1%
Rosetta Resources  $8.05 61%
Goodrich Petroleum $5.44 27%
Breitburn Energy Partners  $23.71 55%
ConocoPhillips $24.56 54%
Legacy Reserves $29.67 65%

Source: Ernst & Young, S&P Capital IQ, and Company 10-Ks and 40-Fs, author’s calculations.

5. Operational cash flow coverage of capital expenditures
This last metric is becoming more and more important as the shale boom isn’t the fresh new thing it once was. Many of the companies in this space have grown production by massive amounts in the past couple of years, but very few have generated the operational cash flow to cover their capital expenses and have been forced to raise capital through debt and equity issuances or through asset sales. According to the U.S. Energy Information Administration, capital expenditures at oil and gas producers currently outpaces operational cash flow by about $110 billion, and that number will likely rise if oil prices remain stagnant.

Source: U.S. Energy Information Administration.

Don’t let anyone convince you otherwise — this is an unsustainable path for companies and should make investors worry about the value of their shares. If this trend continues, companies will be forced to continually issue new debt at higher and higher interest rates, issue value-diluting shares, or be forced to sell off assets that would likely be a part of a longer term future.

For an individual investor, this doesn’t have to be the case, because we can pick the companies that are a much more solid footing when it comes to cash generation. This is a very easy thing to look for: Simply look at a company’s cash flow — on an annualized basis to remove any seasonal swings — and divide that by the company’s annual capital expenditures. Any figure greater than 1 is a very good sign, because it is covering all of its expenses with something left over for other needs such as future plans, paying off debt, or even giving a little back to shareholders.

Company Operational Cash Flow Coverage of Capital Expenditures (%)
Kosmos Energy 169.9%
Legacy Reserves 123.7%
Marathon Oil 118.3%
Diamondback Energy 16.6%
Parsley Energy 8.8%
Magnum Hunter Resources  7.2%

Source: S&P Capital IQ, author’s calculations.

What a Fool believes
The oil and gas industry has been a lucrative one for more than a century now, and even though we are making great strides in developing alternative energy, we will likely need oil and gas for decades into the future. Oil and gas producers can be incredibly lucrative investments to play this trend, and having a better understanding of this industry will help you make better stock choices. Looking into these five things won’t guarantee you will find the perfect stock for your portfolio, but it should help you separate some of the wheat from the chaff when it comes to independent oil & gas companies. Because unless we see another boom like we have over the past few years, it will take more than a dartboard to make a good investment. 

Other subjects in the Energy Investing 101 series

Integrated oil & gas, aka Big Oil

Offshore rigs

Oil & gas royalty trusts

Do you know this energy tax “loophole”?
You already know record oil and natural gas production is changing the lives of millions of Americans. But what you probably haven’t heard is that the IRS is encouraging investors to support our growing energy renaissance, offering you a tax loophole to invest in some of America’s greatest energy companies. Take advantage of this profitable opportunity by grabbing your brand-new special report, “The IRS Is Daring You to Make This Investment Now!,” and you’ll learn about the simple strategy to take advantage of a little-known IRS rule.




Refracking brings ‘vintage’ oil and gas wells to life

By Anna Driver and Ernest Scheyder

HOUSTON/WILLISTON NORTH DAKOTA (Reuters) – A fracking boom isn’t enough for U.S. oil and gas producers – they’re now starting the re-fracking boom.

Wells sunk as little as three years ago are being fracked again, the latest innovation in the technology-driven shale oil revolution. Hydraulic fracturing, which has upended global energy markets by lifting U.S. crude oil output to a 25-year high, has been troubled by quick declines in oil and gas output.

The development highlights how producers must constantly invest and tinker, both to raise overall oil recovery rates that can be as low as 5 percent and to limit steep drops in production suffered by wells drilled into tight oil deposits.

Canada’s Encana Corp invested $2 million to refrack two wells in Louisiana’s Haynesville shale formation earlier this year, after seeing its production in the area dip 27 percent from 2012 levels.

    “There were a significant number of wells that we considered unstimulated,” said David Martinez, Encana’s senior manager for Haynesville development.

    Using minuscule plastic balls, known as diverting agents, pumped at high speeds with water into the old wells, most of which are three to five years old, Encana blocked some the older fractures, or cracks.

    “The thought is that the diverting agent will go to the cracks with the least amount of pressure,” bypassing cracks with higher pressure and boosting the pressure of the entire well so output climbs, Martinez said.

    He said the process can’t be as precisely controlled as an initial round of hydraulic fracturing, in which water, chemicals and sand into are blasted into rock to unlock oil and gas.

Fracking has been used on about 1 million wells bored since 2007, and oil and gas companies now fracture as many as 35,000 wells each year, according to FracFocus, the national fracking chemical registry.

    Refracking cost Encana about $1 million per well, compared with about $12 million for wells it drilled in 2012. Encana is no longer drilling new wells in the Haynesville formation, executives said.

    Since it isn’t clear how long the benefits of a refracking last, Encana plans to collect more data when it refracks five more Haynesville wells this quarter, Martinez said.

    If those prove fruitful it may consider expanding the practice to its holdings in the Denver-Julesburg Basin of Colorado and the Eagle Ford formation in Texas.

    Another Haynesville operator, Dallas-based Exco Resources Inc, said it boosted output from a 2010 refracked test well by 1.3 million cubic feet of gas per day. It didn’t say how much gas it was producing before the refracking. Average initial production from new wells Exco drilled in the second quarter was 12.9 million cubic feet per day.

Some of Exco’s Haynesville wells after four years were producing about a fifth of what they did in their first year, with output declining 69 percent that first year alone, according to the company.

Exco believes the technology can be applied to 400 of its so-called “vintage” wells that were drilled several years ago using what is now outdated technology.

    The company is planning a refracking campaign for 2015, Hal Hickey, Exco’s president, told investors on a July 30 conference call.

    “We’ve been at the forefront” in the Haynesville, he said.

    Marathon Oil Corp is now targeting some of its older wells in the Bakken field in North Dakota and using the latest technology, including re-fracturing, to increase crude output.

Marathon owns or has a stake in about 2,300 wells in the Bakken, though it won’t say how many wells are in production.

    When horizontal drilling was just starting to take off in the Bakken in 2007 and 2008, “(well) completion technology was quite different than it is today,” said Lance Robertson, Marathon Oil’s vice president of North American production operations.

    For example, some early Bakken wells were readied for production by using a single frack stage, or a single section that creates multiple fissures in rock, and about half a million pounds of sand. Now companies use an average of 30 to 35 frack stages and as much as 6 million pounds of sand per well, Robertson said.

    “We go back in and use the best available technology,” Robertson said in an interview.

    Marathon’s refracked wells have so far exceeded the company’s expectations, delivering returns that are large enough to merit additional investment, the company said.

    About 100 of Marathon’s Bakken wells are good candidates to be fracked for a second time, executives said.

So far, refracking has not prompted companies to book higher reserves, said Allen Gilmer, chief executive of DrillingInfo, a well analytics company.

Marshall Watson, a petroleum engineering professor at Texas Tech University, cautions that refracking needs to be better understood before it becomes commonplace.

    “Refracks can work in isolated cases,” Watson said. “Sometimes they do, and sometimes they don’t.”

Yet as refracking gets fresh attention, concern lingers about disposal of frack wastewater, particularly in areas that suffer from drought.

In Colorado, home of the Denver-Julesburg Basin, where almost 2,900 wells have been developed since 2011, water demand for hydraulic fracturing is forecast to double to 6 billion gallons by 2015, more than twice the annual use of the city of Boulder, according to Ceres, a nonprofit group that tracks environmental records of publicly traded companies.

“It sort of shows how much we don’t know about fracking and why it fails sometimes,” said Andrew Logan, the director of the oil and gas program at Ceres. “This has the potential to severely stress water supplies beyond even currently strained levels.”

    The oil industry, however, says the effects of fracking are known and don’t pose a danger.

    “Hydraulic fracturing is a safe, proven technology that has been used for over 60 years to increase production of oil and natural gas – changing America’s energy trajectory from scarcity to abundance,” said Zachary Cikanek, a spokesman for the American Petroleum Institute in Washington.

For now, the energy industry is hoping this initial bump in the number of wells refracked presages a fresh boom whereby unconventional wells are given a jump start every few years to keep oil and gas – and profits – flowing.



oil worker

Now Arriving at Pittsburgh International: Fracking

PITTSBURGH — Where 600 flights used to take off and land every day here at Pittsburgh International Airport, there are now about 300. Partway down Terminal B, the moving sidewalk that used to lead to a dozen gates now stops abruptly at a plain gray wall.

Pittsburgh’s airport is struggling financially and mired in debt, with sharply lower traffic ever since US Airways began phasing it out as a bustling hub in 2004. Long gone are the days when British Airways flew 747s to London, and TWA flew to Frankfurt.

For salvation, airport officials are looking down — about 6,000 feet. The quiet runways, it turns out, are sitting on enough natural gas to run the whole state of Pennsylvania for a year and a half, and this month, Consol Energy will drill its first well here to tap the gas, which county officials say will bring them nearly half a billion dollars over the next 20 years.

The well is outside the airport fence but, with horizontal drilling, will extract the rich deposits that lie under the terminals and runways.

“It’s like finding money,” said Rich Fitzgerald, the county executive of Allegheny County, which owns the airport. “Suddenly you’ve got this valuable asset that nobody knew was there.”

The discovery could not have come at a better time for the airport, which devotes 42 percent of its annual budget to pay off its large debt, much of it incurred to build out the gates it no longer uses. The airport has 75 gates; 62 are still available, but many of those are actually vacant, marked with the airport logo and not an airline’s.

After the drilling, which uses hydraulic fracturing, or fracking, begins in earnest and the natural gas royalties kick in, the airport will receive about $20 million a year, a hefty portion of an operating budget currently below $91 million.

Pittsburgh is not the only airport with oil or gas exploration on its grounds. Dallas-Fort Worth has done it for years, and there were oil and gas wells at Denver International even before the airport was there.

But no other airport relies on oil and gas revenue the way Pittsburgh will. Dallas-Fort Worth, by comparison, earns $8 million from the 100 wells on its property, a fraction of its annual revenue of $6 billion. And Denver International brought in $6.2 million in 2012, about 1 percent of its revenue, from its 76 wells.

Mr. Fitzgerald and others have recognized for a while that their chunk of southwestern Pennsylvania lies atop the vast Marcellus Shale, a fracker’s paradise that is among the most productive in the world. But it wasn’t until the last few years that airport officials got serious about extracting the gas.

The airport offers conditions just about ideal for fracking. For example, the airport sits above four separate layers of shale, each containing natural gas and related liquids. All of it can be reached by a single set of drilling pads, delivering their gas to the same pipelines, using a single set of roads.

With a single well, drillers can bore down a few thousand feet, turn sideways and drill lateral wells up to two miles long. In other areas of Pennsylvania, that can mean having to secure permission from hundreds of property owners. The airport, though, is 9,000 acres with a single landlord.

Kent George, head of the airport authority from 1998 to 2007, said that when US Airways, then known as USAir, told county officials that it wanted to build a hub in the 1980s, the reply was, “We’ll do whatever you need.” Mr. George said that the local government acted “without taking a look at what the long-term exposure was,” and soon, “the airport was fat, dumb and happy with 600 flights a day.”

But then came consolidation, leaving the surviving airlines with too many hubs. A wave of bankruptcies followed, allowing airlines like US Airways to break their long-term leases. The result was a decline in landing fees, gate rentals and passenger spending.

“A million passengers here, a million passengers there, and before you know it, we had dropped considerably,” said Jay Kruisselbrink, vice president of Airmall, which manages the airport’s retail space. The terminal was built for 30 million passengers a year. The peak was just under 21 million, in 1997. Last year, there were eight million.

In response, the airport, like others, has sought to increase revenue from sources that have nothing to do with aviation.

Just about anything will be considered, as other airports have found. “It could be warehouse development,” said Bob Hazel, a former vice president for US Airways and now a consultant. “It could be grazing.”

Mr. Kruisselbrink said the new strategy was showing promise; typical retail sales per departing passenger at an airport are $5 to $7, he said, but Pittsburgh’s were about $14.

And the retailers themselves are trying new things. Bar Symon, opened by the celebrity chef Michael Symon, put electric outlets at almost every seat so patrons can recharge their laptops and smartphones.

“Will it give us another two or three beer sales?” Mr. Kruisselbrink said. “Probably.”

There are also plans to develop the airport-owned land outside its boundaries, with tenants paying rent to the airport. Already, Dick’s Sporting Goods has a headquarters there as well as a hangar.

But the real action is about a mile south of Pittsburgh International’s parking lots, where bulldozers created a pancake-flat gravel pad of about eight acres nestled in the wooded rolling hills.

This month, a drilling rig will poke six holes more than a mile down and a second rig will drill horizontal offshoots that will extend 8,000 feet or more. Work proceeds normally as airliners soar past, although everyone looks up when an Air Force C-5 cargo plane roars overhead at low altitude.

Mark Stebbins, the district operations superintendent for Consol Energy, described it as a modest-size project for his company. All of the work, which faced minimum opposition, was approved by the airport and the Federal Aviation Administration, he said as he unfolded a map on the hood of his pickup.

“Not that we don’t know where we’re at,” he said. “We have a very comprehensive plan.”



A California Oil Field Yields Another Prized Commodity

BAKERSFIELD, Calif. — The 115-year-old Kern River oil field unfolds into the horizon, thousands of bobbing pumpjacks seemingly occupying every corner of a desert landscape here in California’s Central Valley. A contributor to the state’s original oil boom, it is still going strong as the nation’s fifth-largest oil field, yielding 70,000 barrels a day.

But the Kern River field also produces 10 times more of something that, at least during California’s continuing drought, has become more valuable to many locals and has experienced the kind of price spike more familiar to oil: water. The field’s owner, Chevron, sells millions of gallons every day to a local water district that distributes it to farmers growing almonds, pistachios, citrus fruits and other crops.

It is one of the more unusual sources of water, one whose importance has increased in a year when the drought has forced farmers to fallow fields and bulldoze almond orchards. The water is pumped out of the same underground rock that contains oil; after the two are separated, the water flows through an eight-mile pipeline to Bakersfield’s Cawelo Water District, which this year will rely on Chevron’s water for half of its supply, up from an average of a quarter. The district sells it exclusively to farmers for irrigation and reduces its salinity by blending it with water from other sources.

“These are the years that it really shines, because that water is constant no matter what the hydrology is,” said David R. Ansolabehere, the district’s general manager. “In wet years, it almost becomes a problem because we don’t have so much use for it. But in dry years, boy, it really does come in handy.”

Criticized for its use of water, especially in the process known as fracking, the oil industry is focusing on efforts to conserve and recycle water — or, in this case, to increase the available supply for irrigation. As drought has gripped California and Texas, the nation’s No. 3 and No. 1 oil-producing states, respectively, the industry has taken tentative steps to minimize its freshwater consumption. Some companies are recycling water produced in fracking, or hydraulic fracturing, while others have been fracking with brackish water and even without water.

Critics dismiss the water conservation measures as political ploys. They point out that Chevron and the Western States Petroleum Association, a trade group, are among the biggest lobbyists in Sacramento, and that they recently helped defeat a bill that would have declared a statewide moratorium on fracking.

What is more, critics say, California must rely on industry figures for the amount and kind of water used in oil production. According to the Western States Petroleum Association, 323 acre-feet of water were used in fracking 830 wells in California in 2013, compared with 2.7 million acre-feet for agriculture here in Kern County, the heart of California’s oil industry. (An acre-foot is the volume of water that would cover an acre up to a foot high.) Figures and details on water use in conventional oil production were not available, according to the association.

“It’s almost impossible to get information,” said Adam Scow, the California campaign director for Food and Water Watch, an advocacy group. “How much water is the oil industry using every year, whether it’s fracking, acidizing, cyclic steaming or other methods?”

Bob Poole, a spokesman for Santa Maria Energy, a small oil producer in Santa Barbara County, said that oil companies must navigate the politics of drought in California. Santa Maria is planning to build an eight-mile pipeline to bring treated wastewater to its oil fields, where it injects steam and gas into rock to push out the oil in a process known as cyclic steaming.

The company chose to use treated wastewater, which is cheaper than freshwater, Mr. Poole said, adding, “We also felt that it was very important politically.”

In Kern County, oil producers and farmers have coexisted peacefully for decades, but that balance has changed in recent years. Advances in drilling technology have led oil companies to move into agricultural areas. In Shafter, just north of here, dozens of new oil fields are next to almond orchards and other crops. The possible eventual exploitation of a huge untapped oil reserve called the Monterey Shale, which lies under Kern County’s prime farmland, could mean the kind of intense fracking carried out in Texas and North Dakota.

The drought is another potentially disruptive element in the relationship between the two industries, commonly known here as “oil and ag.”

A recent study by the University of California, Davis, estimated that the drought could cost the Central Valley’s agricultural industry $1.7 billion, including 14,500 lost jobs.

Richard Howitt, an emeritus professor of agricultural and resource economics who was the lead author of the report, which was done for the State Department of Food and Agriculture, said it was not possible to measure the effect of the oil industry’s water consumption on agriculture. But given the severity of the drought, Mr. Howitt cautioned against increasing fracking.

“If we do have the development of the Monterey Shale, we’ve got to do it on a different basis than they are in North Dakota,” Mr. Howitt said of fracking. “We have to do it with recycled water, and that adds to the cost.”

The Cawelo Water District struck an agreement to buy the Kern River oil field’s excess water two decades ago, and the project was expanded in 2007 with Chevron’s construction of the eight-mile pipeline. Because the oil field’s water is much less salty than the water in other fields, it can be blended with water from other sources to make it suitable for irrigation.

Saltier water produced in other oil fields is currently too expensive to treat. But just as with oil, external conditions — a lingering drought, in the case of water — could change that.

“It’s a hot topic right now,” Abby Auffant, Chevron’s lead land representative for the California division, said of the water project. “The longer the drought is sustained, I’m sure the more interest it will generate.”

About 760,000 barrels of water a day are produced at the Kern River oil field — compared with 70,000 barrels of oil — and half of the water goes to the Cawelo Water District.

In a normal year, Chevron’s water is a little bit cheaper than water bought from the state, which goes for $30 to $60 per acre-foot, said Mr. Ansolabehere, the water district manager. This year, while the price of Chevron’s water is unchanged, water on the open market is being sold for up to $1,300 per acre-foot as water districts receive only a tiny fraction of what they are supposed to get from the state, he added.

Tom Frantz, an almond farmer in Shafter and one of the most vocal opponents of fracking in Kern County, was not convinced of its value.

“Relative to all the water we’re using in Kern County,” Mr. Frantz said of Chevron’s water, “it’s a tiny, tiny fraction.”




Bakken Oil Boom Brings Growing Pains to Small Montana Town

At the edge of a farmer’s wheat field outside the prairie town of Bainville, Montana, Justin and Mandy Tolbert’s 36-foot camper sat in a rented lot. For more than 20 months, the Tolberts lived in the camper with their six children, ages 5 to 12, and Justin’s adult cousin.

At night, a jumble of pillows and cushions on the floor served as sleeping space. In August, when temperatures approached 100°F, the camper cooked. In January, the temperature dipped to -20°F, freezing the pipes and leaving the family without water for days.

“The hardest part [is] winter, when they cannot get outside to play,” Mandy Tolbert said about her children. “It’s not like a house where they can run around.”

The Tolberts are far from poor. Justin makes more than $200,000 a year as an oil pipeline welder in the Bakken oil field. The family owns a two-story home with an in-ground pool in Tulsa, Oklahoma. They drive a $50,000 four-wheel-drive van.

The Tolberts moved here in 2012 as part of a massive migration of workers chasing their fortunes in the Bakken shale, where a revolution in drilling technology led by fracking has pushed United States oil production to a 24-year high.

Like many oil boom families, the Tolberts left home to find a brighter future. They chose to live in rural Montana to avoid the bustle at the center of the oil rush 30 miles away, in Williston, North Dakota.

But the explosive growth that deterred them from Williston is spreading to small Montana border towns such as Bainville, causing severe housing shortages and growing pains.

Although only a small fraction of Bakken wells are in Montana, where oil production peaked in 2006, nearby oil industry development and an influx of workers have maxed out the town’s water system, destroyed roads, and introduced drugs and violent crimes unheard of by generations of farmers and ranchers.

The Lure of Oil Salaries

“If you wish for this oil, be careful what you wish for, because life as you know it is done,” said Ken Norgaard, road department supervisor for Roosevelt County, the vast and sparsely populated county of rolling farmland that includes Bainville.

Map of the Bakken shale formation


County jobs were once coveted for their solid benefits and retirement plan, Norgaard said. Now, he has trouble finding workers. Norgaard advertised a road grader job as far away as Wyoming. In six months, he received two applications.

In the oil field, truck drivers make more than twice what the $17-an-hour county job pays, Norgaard said. The oil industry is also destroying the county’s gravel roads, which were originally built for the earliest cars and small farm equipment. Heavy trucks hauling hundreds of gallons of fracking water have turned the country roads to washboards. When it rains, the gravel washes out and strands school buses.

“I’ve got plenty of equipment; what I need is manpower,” Norgaard said. “I need to get my wages up to where I can compete with the oil patch.”

The K-12 Bainville School faces similar challenges. The influx of oil workers has pushed rent for run-down mobile homes to upwards of $2,500 a month. Teachers, whose salaries start at $33,000, can’t afford housing. At the same time, student enrollment has more than doubled to 165 since 2009.

“We have had to get creative,” said school superintendent Renee Rasmussen, who graduated from the school in 1973, one of a class of ten. In the past few years, Rasmussen said, the school bought 13 homes to house many of its teachers.

Before the oil boom, the school was in danger of closing. Now classes are filled beyond capacity, and girls line up to use one of three bathroom stalls in the elementary school’s bathroom.

“How can we allow the growth to happen, welcome people here, and at the same time remain who we are?”—Renee Rasmussen, school superintendent

One January afternoon, Rasmussen faced a more immediate crisis—finding a way to get the kids home from school. Rasmussen has struggled to hire school bus drivers, even after increasing wages to $24 an hour. She has recruited the school lunch cook and the janitor to drive buses. But on that day, an out-of-town basketball game left Rasmussen scrambling to find an additional driver.

Despite the problems, Rasmussen thinks development has improved the school and Bainville. But she worries that the small town flavor of Bainville, where oil millionaires dress like poor farmers and sometimes forget to cash their oil checks, may be changing.

“The big crisis is this,” Rasmussen said. “How can we allow the growth to happen, welcome people here, and at the same time remain who we are?”

Municipal Budgets Strained

Bainville’s growing pains are likely to get much worse. In May, the United States Geological Survey doubled its 2008 estimate of oil resources in the Bakken and the Three Forks formation, which lies below the Bakken.

In early 2013, Procore Group Inc., of Alberta, Canada, built a rail facility in Bainville to unload the sand used in the hydraulic fracturing process, which will be trucked to wells across the Bakken. A sprawling “man camp” that can house 350 oil workers also has been built, which required the town to double the size of its sewer lagoon. The expansion was paid for by Procore.

Bainville mayor Dennis Portra said there are plans for a hotel, a gas station, and additional residential housing. Portra said Bainville’s population has doubled since 2010 to about 450, and will likely double again in the next couple of years.

Portra is a proponent of oil industry growth. The boom has provided jobs for his three adult children. But he was dismayed in 2013, when Montana Governor Steve Bullock vetoed a bill that would have provided $35 million to municipalities struggling with oil and gas industry development.

Montana towns like Bainville, Portra said, are suffering the effects of the boom, while others are getting rich. The majority of the Bakken wells, and tax revenue, are in North Dakota. For oil drilled in Montana, the state takes 50 percent of tax revenue. Counties and schools across the state receive most of the remainder. Towns and cities share only one-tenth of one percent.

“Why should it come back to the local taxpayer to pony up for schools, roads, water, and police when we are sending millions to the general fund?” Portra asked.

Bullock’s deputy chief of staff Kevin O’Brien said the governor supports increasing funding for towns in the Bakken, but he said the governor vetoed the bill to help balance the state’s budget.

“The governor intimately feels their pain,” O’Brien said.

Crime on the Rise

Among the changes in Bainville, none has locals on edge like the increase in crime. In 2012, two Colorado men looking for work in the oil field allegedly killed a popular math teacher in nearby Sidney, Montana, and buried her body along a highway outside Williston. Soon after, Roosevelt County bought a new file cabinet to store the rush of concealed-weapon applications.

On a recent evening, as Roosevelt County Sheriff’s Deputy Avis Ball patrolled near Bainville, she pointed out a simple cross next to the highway. It’s the spot where in 2012 she found Brian Doyle, a 49-year-old oil worker from Florida, dead and partially buried in the snow. Doyle was run over and abandoned by his friend, who was later convicted of negligent homicide.

“He’d been laying there for a week in the snow,” said Ball, who patrols the eastern edge of the county alone, often an hour from the nearest backup deputy at the far end of the county.

Earlier this year, Ball said, four men beat a man nearly to death in Williston, put him in the trunk of a car, and dropped him off in a field in Roosevelt County. “When I started, I was taking dog calls,” said Ball, who joined the department in 2011. “Since then it has taken off.”

The FBI has warned that Mexican drug cartels are trafficking drugs to the area, targeting the large paychecks of the mostly young men who work in the Bakken. Felony drug arrests in Roosevelt County rose from 4 to 28 from 2008 to 2012, according to Sheriff Freedom Crawford. Crawford said methamphetamine is the biggest drug problem the county faces, followed by illegal painkillers. But a bigger problem, he said, is the increase in alcohol-fueled fistfights. From 2008 to 2012, assault arrests nearly doubled, to 173.

“Historically, we knew who our troublemakers are,” Crawford said. “Now after the oil field hit, we can’t keep up with it. We don’t know who these people are.”

The spike has taxed the county’s tiny 100-year-old jail, which Crawford said has held as many as 40 people, more than double the number it held before the boom. Jail overcrowding led to American Civil Liberties Union scrutiny that pressured Crawford to limit capacity to 17. On a recent afternoon, only one inmate was local, the others from as far away as Florida. Crawford said the county is planning a new 40-bed jail that can be expanded to 60 beds if the oil boom continues.

“If we have no place to live, we are backed into a corner.”—Avis Ball, sheriff’s deputy

But Crawford faces more immediate concerns. In April, Ball’s landlord sold the home where she lived with her four children. She had to be out by the end of May, but Ball, who is a single mother, couldn’t find a home she could afford. Instead, she moved into a motel room, which she hopes is temporary. Her children are living with friends until Ball finds another home.

But Ball doubts she can find a home to rent on her sheriff’s deputy salary, which she said is less than $22 an hour.

“I’m not ready to leave my job here,” Ball said. “I have not met my goals. But if we have no place to live, we are backed into a corner.”

A Changing Way of Life

Many of the changes that frustrate locals don’t make the crime statistics sheet. On an early morning at the Welcome Stop, a two-pump gas station and convenience store in Bainville, a group of locals sat drinking coffee at a round table and talked about hunters trespassing on their land, drunken men wandering the streets at night, and petty theft.

“You used to drive your pickup to town, leave your keys inside and your rifle in the back window. You can’t do that anymore,” said Dan Lambert, a town sewer worker.

“We were very naive. We were not expecting things that happen in other places to happen here.”—Shellie Pacovsky, emergency response technician

Shellie Pacovsky, the town’s senior emergency response technician, said a woman who asked to park her camper on Pacovsky’s property later opened an adult massage parlor with signs and online advertisements. When the woman refused to leave, Pacovsky pushed her car off the property with her John Deere tractor.

“We were very naive,” Pacovsky said. “We were not expecting things that happen in other places to happen here.”

If the boom has stretched the patience of many locals, it has been a boon to the now-millionaire farmers and ranchers who own land where oil has been struck, and to Bainville’s newest residents, who work the wells.

In August, Tony and Tanya Tippett were in danger of losing their house in Georgia over back taxes when Tony’s brother called from this area with stories of hard work and hefty paychecks.

Although Tony’s brother was living in a sleeping bag near a truck stop in Williston, Tony and Tanya decided to join him. Tony now makes $2,000 a week after taxes working for an oil well servicing company. Tanya works behind the counter at the Welcome Stop.

Like many families here, the Tippetts live in a camper. They share it with Tony’s brother and a bulldog, paying $800 a month to park in a campground. Tony said he plans to stay in Bainville for five years, “depending on how much we can stomach the cold.”

Tony commutes to Williston, but he said he would never move his family there. Like the locals, Tony likes the small town atmosphere of Bainville, even if the influx of workers means he is forced to live in a camper. “It’s rougher over there,” he said of Williston.

As for the Tolberts, they are not sure they will ever move back to Tulsa. As long as the work holds out, they plan to stay in Bainville. After making it through a winter of frozen pipes and six kids in a camper, the Tolberts moved into a house in April and bought three sheep for their children.

Justin Tolbert renovated the 1,000-square-foot house, which is owned by a local school bus driver and used to be a small office building, in exchange for several months of rent.

Mandy Tolbert says her children miss sleeping together in one room, but they sometimes visit the old camper, which didn’t sit vacant long. Justin’s friend from Tulsa, who is also a welder, recently moved in with his wife and four children. Like the Tolberts, they plan to stay, if the oil work lasts.




Halliburton Fracking Spill Mystery: What Chemicals Polluted an Ohio Waterway?

On the morning of June 28, a fire broke out at a Halliburton fracking site in Monroe County, Ohio. As flames engulfed the area, trucks began exploding and thousands of gallons of toxic chemicals spilled into a tributary of the Ohio River, which supplies drinking water for millions of residents. More than 70,000 fish died. Nevertheless, it took five days for the Environmental Protection Agency and its Ohio counterpart to get a full list of the chemicals polluting the waterway. “We knew there was something toxic in the water,” says an environmental official who was on the scene. “But we had no way of assessing whether it was a threat to human health or how best to protect the public.”

This episode highlights a glaring gap in fracking safety standards. In Ohio, as in most other states, fracking companies are allowed to withhold some information about the chemical stew they pump into the ground to break up rocks and release trapped natural gas. The oil and gas industry and its allies at the American Legislative exchange Council (ALEC), a pro-business outfit that has played a major role in shaping fracking regulation, argue that the formulas are trade secrets that merit protection. But environmental groups say the lack of transparency makes it difficult to track fracking-related drinking water contamination and can hobble the government response to emergencies, such as the Halliburton spill in Ohio.

Officials from the EPA, the Ohio EPA, and the Ohio Department of Natural Resources (ODNR) arrived on the scene shortly after the fire erupted. Working with an outside firm hired by Statoil, the site’s owner, they immediately began testing water for contaminates. They found a number of toxic chemicals, including ethylene glycol, which can damage kidneys, and phthalates, which are linked to a raft of grave health problems. Soon dead fish began surfacing downstream from the spill. Nathan Johnson, a staff attorney for the non-profit Ohio Environmental Council, describes the scene as “a miles-long trail of death and destruction” with tens of thousands of fish floating belly up.

Statoil and the federal and state officials set up a “unified command” center and began scouring a list of chemicals Halliburton had provided them for a compound that might be triggering the die off. But the company had not disclosed those ingredients that it considered trade secrets.

“We knew there was something toxic in the water. But we had no way of assessing whether it was a threat to human health or how best to protect the public.”

Halliburton was under no obligation to reveal the full roster of chemicals. Under a 2012 Ohio law—which includes key provisions from ALEC’s model bill on fracking fluid disclosure—gas drillers are legally required to reveal some of the chemicals they use, but only 60 days after a fracking job is finished. And they don’t have to disclose proprietary ingredients, except in emergencies.

Even in these cases, only emergency responders and the chief of the ODNR’s oil and gas division, which is known to be cozy with industry, are entitled to the information. And they are barred from sharing it, even with environmental agencies and public health officials. Environmental groups argue this makes it impossible to adequately test for contamination or take other necessary steps to protect public health. “Ohio is playing a dangerous game of hide and seek with first responders and community safety,” says Teresa Mills of the Virginia-based Center for Health, Environment, and Justice.

Within two days of the spill, Halliburton disclosed the proprietary chemicals to firefighters and the oil and gas division chief, but it didn’t give this information to the EPA and its Ohio counterpart until five days after the accident, by which time the chemicals had likely reached or flowed past towns that draw drinking water from the Ohio River. The company says that it turned over the information as soon as it was requested. “We don’t know why USEPA and Ohio EPA didn’t have the information prior to July 3,” Halliburton spokeswoman Susie McMichael tells Mother Jones. “If they had asked us earlier, we would have provided the information, consistent with our standard practice.” The Ohio EPA, on the other hand, maintains that ODNR, emergency workers, and federal and state EPA officials had a representative ask Statoil and Halliburton for a complete list of chemicals just after the spill. Several days later, environmental regulators pressed for the information again and learned that it had already been shared with only ODNR, which according to the EPA report was not deeply involved in the emergency response.

Other key players, including local water authorities, the private company hired to monitor water contamination, and area residents, did not get a full rundown of chemicals, even after the EPA and the Ohio EPA finally received the information.

Ohio state officials maintain that the river water is safe to drink because the fracking chemicals have been so heavily diluted. But environmentalists are skeptical. “Tons of chemicals and brine entered the waterway and killed off thousands fish,” says Johnson of the Ohio Environmental Council. “There’s no way the drinking water utility or anyone else could monitor those chemical and determine whether the levels were safe without knowing what they were. Even today, I don’t think the public can be sure that the water is safe to drink.”




Texas city could become first in state to ban fracking

DENTON, Texas – A North Texas city could become the first in the state to ban hydraulic fracturing if city leaders approve a grassroots petition to outlaw the drilling method.

The Denton Record-Chronicle reports ( ) Denton city staff expect Tuesday evening’s public hearing on the measure to draw a huge crowd to city hall.

A Colorado-based group has been circulating a competing petition in support of hydraulic fracturing, or fracking.

The head of the agency that regulates the oil and gas industry in Texas wrote Denton city officials Thursday asking them to withhold their support for the petition. Outgoing Railroad Commission Chairman Barry Smitherman likened it to a “ban on drilling” that could injure the state’s economy.

Even if the council rejects the ban, Denton residents could vote on it in November.



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