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Midstream firms build to meet Eagle Ford condensate production

HOUSTON — With an $860 million deal announced this week, Buckeye Partners is betting on condensate.

Condensate, a type of light crude oil, has been flowing in increasing quantities from the Eagle Ford Shale in South Texas as technological advances boost production there.

And with more condensate flowing from the region — as well as the possibility that lightly refined condensate may be exempt from a U.S. ban on most crude oil exports — many midstream companies are looking at potential profit in getting the light oil from the South Texas wells to market.

From 2009 to 2012, annual U.S. production of condensate from wells grew by 54 percent, from 178 million barrels to 274 million barrels, according to U.S. Energy Information Administration. By many estimates, the Eagle Ford  region accounts for the majority of that production.

On Tuesday, Houston-based Buckeye Partners L.P. announced it would enter the heated market by paying $860 million for an 80 percent interest in Texas facilities owned by Trafigura AG. The deal includes gathering facilities in the Eagle Ford, as well as processing plants and a marine terminal in Corpus Christi.

Buckeye has been active in markets including Chicago, New York and the Caribbean.

Buckeye and Trafigura will  run the assets  as a joint venture and will contribute at least another $240 million to build new storage and seaborne shipping capacity in the near future, the companies announced.

Trafigura AG is a subsidiary of Netherlands-based commodities trader Trafigura Beheer BV.

Under the new agreement, Trafigura will buy oil and condensate produced in the Eagle Ford before sending it  to other markets using the joint venture’s infrastructure, said spokeswoman Marisol Espinosa.

The deal includes two condensate splitting units Trafigura already is building. Splitters  break condensate into component parts including naphtha, kerosene and diesel. The units will be able to handle a combined 50,000 barrels per day of the light oil when completed in 2015.

In a Wednesday morning conference call with investors, Buckeye Partners executives said the partnership is considering building another splitter.

Other midstream interests also are building splitters to accommodate the increasing amount of condensate flowing from the Eagle Ford.

“The outlook is pretty favorable,” said Lysle Brinker, a research director at analyst firm IHS . “A lot of companies are looking at doing this.”

Kinder Morgan Energy Partners’ $360 million splitter project at its Galena Park terminal on the Houston Ship Channel, also slated for completion in 2015,  will have a daily capacity of 100,000 barrels .

“Midstream is moving into processing,” said John Auers, executive vice president with Turner Mason and Co. “These large midstream companies are investing and the Gulf Coast is the place to be.”

Besides deriving condensate components, running it through a splitter can clear the way for its export.

A law that arose from oil shortages in the 1970s bans most crude oil exports from the United States, but recent regulatory activity has allowed some export of lightly processed condensate with a license.

Trafigura has applied for such  a license, Espinosa said.

If regulators approve, the new Trafigura-Buckeye venture could export condensate through its five ship berths at the Corpus Christi facility terminal.

In a presentation to investors, Buckeye said that the market probably will favor splitting condensate it into its parts before sending it abroad. But Buckeye also stressed that it would remain flexible.



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.”




Small business, big mistake: Classifying employees as independent contractors

When I started my company in 2006, my intent was to have only independent contractors for the first five years, with the goal of minimizing overhead. My plan was to re-evaluate growth, goals, expenses and income in 2011 to determine whether I should start onboarding employees.

However, as with most small businesses, there’s always something that doesn’t go according to plan — at all.

This was one of those things.

At the conclusion of a long-term project with one of my customers, an independent contractor who had been providing onsite support for the project filed for unemployment benefits. What the what? I was left with that perplexed Scooby Doo look on my face.

How can my former independent contractor file for unemployment when our duly signed, attorney-approved agreement clearly states “independent contractor?” When I received a notice from the Department of Labor, Licensing and Regulation, I thought it would be resolved quickly one I sent them the signed agreement.

 Well, it wasn’t. My next notice included a case number for an audit of the work and compensation history not just for that individual, but for my records on every person I had hired in the three years leading up to that.

During the audit, DLLR officials reviewed my payroll information and compared workers to see if those who had been doing similar work were identifying it the same way on their income tax returns. They also wanted to know whether each contractor had an online presence (they asked me for Web site addresses) and whether each individual had been doing work onsite for my company in Maryland.

Of course, I thought I had done my due diligence in the beginning to develop an understanding of what constitutes an employee versus an independent contractor. Ultimately, though, reading through the Internal Revenue Service’s checklist and trying to sort through my state’s guidelines on my own didn’t prove sufficient.

So, if you’re structuring a company like mine and you aren’t sure, call the IRS and talk it through. Explain the type of work an individual will be doing and ask for some guidance.

After going through this, I’ve done consulting work for my clients to help them make better hiring decisions. For instance, I had a customer who was offering their independent contractors full benefits, and another whose contractors were working onsite and had no other customers they were claiming work for on their taxes. I’ve been able to guide them in the right direction and help them avoid potential audits.

So, make sure you are identifying and verifying these details with your contractors:

• Does your contractor do similar work for others and identify that on their tax forms?

• Does the contractor have a Web site?

• Has the contractor provided you with a complete W-9 tax form?

• Are you giving the contractor control to handle tasks with little direction from you?

If you are unsure about any of these items, I suggest you seriously consider making the individual an employee — or at the very least, pick up the phone and seek some guidance.



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.



Looking for the Next Oil Boom? Follow the Tech

Much larger than Eagle Ford and once thought to have reached peak production, new technology has brought us full circle back to the Permian Basin in Texas and New Mexico, where the recent shift to horizontal well drilling has rendered this play the unexpected ground zero.

Determining where the next real oil boom will be depends largely on following the technology, and while the Permian Basin has been slower than others to switch from vertical to horizontal well drilling, horizontal has now outpaced vertical, and investors are lining up to get in on the game.

Until about 12 years ago, virtually all wells in the Permian were vertical. As of last fall, however, horizontal and directional rig counts—meaning, non-vertical drilling rigs—have now begun to exceed vertical, according to RBN Energy.

But what they’re also looking for are developers who are seeing strong economics in both vertical and horizontal wells. It’s all about balance, and this co-mingling of multiple zones — with the ability to complete both horizontal and vertical wells economically — is the best bet for investors.

The Permian Basin now boasts the largest rig count in the U.S. Just this week, the number of rigs exploring for oil and natural gas in the Permian Basin increased to 560, according to the weekly rig count report released July 10 by Houston-based oilfield services company Baker Hughes.

What’s more, according to Bernstein Research, the Permian Basin will top the charts for North American spending growth in 2014, with an amazing 21 percent increase. And 2013 was already a stellar year for the Permian.

Permian production last year increased by 280,000 boe/d to 2.3 million boe/d, comprised of 1.4 million b/d of oil and 5.3 bcfd of gas, according to the U.S. Energy Information Administration.

This technology has changed the way we think about the Permian Basin, once the darling of American oil production that became lost in the shadow of Eagle Ford and Bakken. While Eagle Ford and Bakken were viewed as the “bigger plays” at the start of the unconventional boom in the U.S., due to the fact that new technology debuted here harder and faster, the Permian is back and bigger than ever.

“The Permian Basin is much larger than the Eagle Ford play, and it also contains over 20 potentially productive zones, while Eagle Ford has only one zone,” Parker Hallam, CEO of Crude Energy—a small-cap company, not publicly traded, operating in the Permian, told

Hallam particularly noted the “excellent quality rock” in the Wolfcamp, Fusselman, Cline, Mississippian andStrawn zones.

“The Wolfcamp is one of the better producers in the Permian. It can be up to 1,000 feet thick and is composed of multiple individual zones, several which could be production. Wolfcamp is attracting a lot of attention right now because of the horizontal drilling through the normally tight limestone,” he said.

Hallam also noted that while horizontal drilling is changing the future of the Permian Basin, “vertical completions using new technology like fracking and co-mingling multiple zones are turning out top results and drillers are seeing strong economics in these wells.”

Leading the pack in the Permian are Devon Energy Corp., Concho Resources, Pioneer Natural Resources and Chevron, with Wolfcamp probably the key focus of development activities, and the leading formation in terms of production increases. Devon in particular is being singled out by analysts for its large acreage in the Permian, couple with its transformative turnaround that could render it one of the largest crude oil producers in the U.S.

The only challenge with the Permian—which is on trend to see continual increases in production—is the pipeline takeaway capacity, according to RBN Energy: “The bottom line is that crude oil production in the Permian is growing rapidly, and today there is not enough pipeline takeaway capacity to efficiently handle the volume,” but that should correct itself soon with new pipelines coming online.

Bloomberg quoted Bruce Carswell, West Texas operations manager for Iowa Pacific Holdings, as saying that the forecast through July is that volumes are going to continue to move out of the region by rail.

The Permian Basin Petroleum Index, put out by Amarillo economist Karr Ingham, which examines several industry metrics to measure the health of the oil and gas business in the region, was almost 10 percent higher in May than a year earlier.

Regardless of pipeline capacity, Permian Basin crude is shaping up to be the next big oil boom thanks to new technology. Eagle Ford and Bakken became economical only after being drilled horizontally, so with the final shift to dominate horizontal drilling in the Permian, the game has only just begun.



Coal Plant Carbon Pollution Injects Life in Old Oil Wells

The dream of pollution-free coal plants is getting a boost from growing demand for carbon dioxide used to revive old oilfields.

In one of the first projects to harness the C02 waste of a coal plant for oil drilling, power generatorNRG Energy Inc. (NRG) announced today that it’s beginning construction on a $1 billion retrofit of its East Texas coal plant. NRG will pump carbon dioxide pollution from the plant deep into a nearby oil field that it partially owns. The idea is to loosen trapped crude deposits, making old wells flow like new while burying the harmful greenhouse gas. Cash from the increased oil production will help pay for the project, NRG said in a statement today.

The East Texas plant will be the largest of its kind to supply CO2 for oil exploration from coal-powered utilities. Oil companies have long relied on natural sources of underground carbon to goose output with a technique called carbon flooding. As demand has risen, drillers have snatched up those supplies, causing a shortage of natural carbon and creating a market for recycled CO2 from coal plants.

“The way I look at this project, it is really like a bridge between the power and the oil industries,” said Arun Banskota, president of NRG’s carbon-capture business.

What else is going on?

336,000 Cars

Construction on the project near Houston is scheduled to begin today. When finished in late 2016, the facility will remove carbon equivalent to the exhaust of 336,000 cars annually and spur a 30-fold increase in crude output from the West Ranch oilfield about 80 miles (129 kilometers) away. NRG’s partner in the project is JX Nippon Oil & Energy Corp., Japan’s largest oil refiner and a unit ofJX Holdings Inc.. (5020) The two co-own the oilfield with closely-held Hilcorp Energy Co.

“This is taking a pollutant and turning it into a marketable commodity that’ll unlock billions of barrels of oil,” said Brad Crabtree, vice president of fossil energy at the Great Plains Institute for Sustainable Development, a Minneapolis-based non-profit that studies energy and climate change.

As horizontal drilling and hydraulic fracturing in shale rock catapults North American energy production to the top of the world, some oil prospectors including Texas billionaire Rich Kinder andOccidental Petroleum Corp. (OXY) are focusing on the tried-and-true method of carbon flooding to increase production in older oil fields.

Reservoir Injection

After wells peter out, liquefied C02 is injected into the reservoir to mix with the remaining crude, allowing the oil to flow more easily into wells where it can be pumped out. About half the CO2 remains in the reservoir, and the remainder is reused.

Crude prices averaging more than $90 a barrel for half a decade are spurring investment in carbon flooding and raising demand for the gas needed to refresh the aging fields.

Although U.S. shale formations currently produce eight times more total crude, carbon flood output is forecast to grow 3.6 percent annually during the next 25 years, compared to 1.3-percent for shale. Carbon flooding is Occidental’s most profitable U.S. business, generating a 43 percent after-tax profit margin based on an oil price of $100 a barrel, said Vicki Hollub, the executive vice president who oversees all of the company’s U.S. operations.

There are 160 billion barrels of crude sitting under what were once considered depleted wells. Virtually all of that oil could be tapped with CO2, estimates Chirag Rathi, a principal at consulting firm Frost & Sullivan. That would be a $17 trillion haul at current prices.

Flooding Potential

“Everybody’s always talking about shale but carbon flooding is going to be a growth business for us for some time to come,” said Jeff Simmons, chief of Occidental’s Permian Basin unit in Texas andNew Mexico.

One restraint on the growth of the CO2 business is the lack of raw material: oil producers in the Permian region of west Texas already are using every molecule of carbon-dioxide they can get, said Darrell Ricketson, the vice president in charge of Kinder Morgan Energy Partners LP (KMP)’s Permian Basin CO2 floods.

“There is so much need for CO2 in west Texas,” Ricketson said. “There are millions and millions of barrels of oil waiting to be unlocked. It’s not as widespread as it could be because of the limited availability of CO2.”

Expanding Supplies

Although 80 percent of the carbon used in oilfields today comes from naturally-occurring deposits of the gas, man-made supplies are expected to expand as the technology is improved for capturing CO2 from power plant smokestacks and other industrial sources, according to the U.S. Energy Department.

At the oilfield receiving C02 from NRG, injecting carbon is expected to lift production to 15,000 barrels a day from about 500 now. At current prices, the annual output of the field would have a value of more than $550 million.

“There is a lot of trapped oil that potentially could be recovered with CO2 flooding,” Rathi said, making oilfields “one of the key applications of captured carbon.”



Oklahoma Agrees to Keep Oil Train Shipments Secret

Surging oil production in states like North Dakota has outpaced pipeline capacity, and the energy industry has turned to railroads to transport oil from fields to refineries.

But several high-profile oil-train accidents — including Canada’s explosive Lac-Mégantic 2013 derailment that killed 47, and other accidents in Alberta, Alabama and Virginia — have raised questions about the safety of shipping crude oil on trains.

The federal government has ordered railroads to share more information about some crude oil shipments with state authorities, but Oklahoma officials won’t share that information with regular citizens, The Oklahoman‘s Paul Monies reports:

After an inquiry about the Bakken rail shipment reports, the Oklahoma Department of Environmental Quality said the commission entered into confidentiality agreements with railroads under guidance from the federal Department of Transportation.

Oklahoma is a major oil hub, and train shipments of crude oil traverse the state en route from North-central U.S. oilfields to refineries along Texas’ Gulf Coast. In May, the federal government ordered railroads to share more information with state authorities about crude shipments from North Dakota’s Bakken Shale, which might be more flammable than other types of crude.

Oklahoma’s DEQ said “information relating to terrorism” exempts the information from Oklahoma’s Open Records Act, Monies reports, but other states, including Washington, have made the information public.

In its letter to Washington officials, BNSF Railroad Co. said the information should be shared only on a “need-to-know” basis. The data the railroad provided showed weekly summary information on Bakken oil shipments by county, not detailed train schedules or cargo manifests.

Several other states, including California, New Jersey, Minnesota and Colorado, have chosen to keep the information confidential in accordance with the requests of some railroad companies.





Russian Hackers Targeting Oil and Gas Companies

SAN FRANCISCO — Russian hackers have been systematically targeting hundreds of Western oil and gas companies, as well as energy investment firms, according to private cybersecurity researchers.

The motive behind the attacks appears to be industrial espionage — a natural conclusion given the importance of Russia’s oil and gas industry, the researchers said.

The manner in which the Russian hackers are targeting the companies also gives them the opportunity to seize control of industrial control systems from afar, in much the same way the United States and Israel were able to use the Stuxnet computer worm in 2009 to take control of an Iranian nuclear facility’s computer systems and destroy a fifth of the country’s uranium supply, the researchers said.

The group was named “Energetic Bear” because the vast majority of its victims were oil and gas companies. And CrowdStrike’s researchers believed the hackers were backed by the Russian government given their apparent resources and sophistication and because the attacks occurred during Moscow working hours.

report released Monday by Symantec, a computer security company based in Mountain View, Calif., detailed similar conclusions and added a new element — the Stuxnet-like remote control capability.

In addition to basic hacking techniques, like sending mass emails containing malicious links or attachments, the group infected websites frequented by energy workers and investors in what is known as a “watering hole attack.”

In this attack, instead of targeting a victim’s computer network directly, hackers infect websites their targets visit often — like an online menu for a Chinese restaurant — with malicious software. Without knowing it, workers visiting that site inadvertently download the so-called malware and help the hackers get inside their computer network.

The Russian hackers were careful to cover their tracks, the researchers said. They hid their malware using encryption techniques that made it difficult to identify their tools and where they came from. In some cases, researchers found evidence that the hackers were probing the core of victims’ machines, the part of the computer known as the BIOS, or basic input/output system. Unlike software, which can be patched and updated, once a computer’s hardware gets infected, it typically becomes unusable.

F-Secure, the Finnish security firm, also told its clients last week about the Russian hacking group, which Symantec has named “Dragonfly.”

In the past six months, researchers say the group has become more aggressive and sophisticated.

The Russian hackers have been breaking into the networks of industrial control software, or I.C.S., makers, inserting so-called Trojans into the software used by many oil and energy firms to allow employees to remotely get access to industrial control systems. So when oil and gas companies downloaded the latest version of the software, they inadvertently downloaded the hackers’ malware as well.

At least three industrial control software developers were affected, according to researchers at Symantec, F-Secure and CrowdStrike. The first was a maker of remote access tools for industrial control systems; the second, a European manufacturer of specialized industrial control devices; and the third, a European company that develops systems to manage wind turbines, natural gas plants and other energy infrastructure. They were not named by the security companies because of confidentiality agreements.

Security researchers estimate that more than 250 companies downloaded the infected software updates.

“These infections not only gave the attackers a beachhead in the targeted organizations’ networks, but also gave them the means to mount sabotage operations against infected I.C.S. computers,” Symantec wrote in its report Monday.

There was no evidence the Russian group intended to use its toehold in some networks to inflict damage, like blowing up an oil rig or power facility, said Kevin Haley, the director of security response at Symantec, in an interview. The apparent motive, Mr. Haley said, was to learn more about energy companies’ operations, strategic plans and technology. “But the potential for sabotage is there,” he added.

More recently, Energetic Bear has been targeting companies in the financial sector, said Adam Meyers, CrowdStrike’s head of threat intelligence. In particular, the group has been attacking, with the watering hole technique, some websites frequented by firms that invest in the energy sector.

Once someone visits an infected site, Mr. Meyers said, attackers will infect their system, scan their device to see if it is worth hacking, and then install sophisticated hacking tools. For devices deemed uninteresting, the attackers simply clean up their tools and move along.

“They are very aggressive,” Mr. Meyers said. “And very careful to cover their tracks.”



Texas County close to repairing roads affected by oilfield traffic

If all goes according to plan, seven miles of county road could be replaced in early fall or next spring as part of the Transportation Infrastructure Fund (TIF) project.

Jim Wells County applied for the funds through the Texas Department of Transportation. The county was awarded a little more than $500,000 for the repair of roads affected by oilfield traffic.

On Monday, the Court had a special meeting to clarify specifications for bids for the roadwork.

At an earlier meeting, County Roads 120, 211, 305, 463 and 481 were designated as priority roads for repair. A low-water crossing at County Road 117 is also up for consideration, if there are enough funds.

Betty Collier with GrantWorks said once they get all the paperwork back from the state, the county is ready to begin the bidding process.

The targeted sections of roadway will be completely reconstructed and capped with a double seal coat.

Pct. 4 Commissioner Javier Garcia said it’s necessary to start from scratch, or it would be like putting a band-aid on the road.

Pct. 2 Commissioner Ventura Garcia said he would feel more comfortable with the specifications in the bids if they were done by an engineer.

The Court suggested Joe Sandoval with Maverick Engineering, because of his previous work with county.

Collier said the state does not require engineers for this project, because counties do their own roadwork. She added that commissioners would have to send out correspondence to three engineers with basic qualifications before they could use Sandoval.

Collier said this is to show that there was some sort of process in selecting the engineer.

The roads would all be bid at the same time, and construction could begin as early as August.

Collier said they have not seen the state turnaround on the paperwork, so an exact timeline is hard to pinpoint.

If it gets too late in the year, construction may have to wait until spring for the warmer weather.

Collier added that Jim Wells County is further along in the TIF process than the surrounding counties.




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