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June 2nd - Old gas field opens up new drilling opportunities
What's old is new again when it comes to the Cotton Valley sands formation in north Louisiana.

An old field that's produced natural gas since the 1940s and '50s, the Cotton Valley formation has opened up new opportunities for drilling for operators in Caddo, DeSoto and even Lincoln parishes looking for more economical ways to extract the resources during the stagnant energy market.

The weekly rig report on April 24 listed 40 land rigs drilling onshore in Louisiana, with 28 of those in northwest Louisiana. And 17 of the 28 are drilling in the Cotton Valley formation.

"Generally speaking, I'm optimistic that drilling will continue in northwest Louisiana and increase as commodity prices improve in the future," independent landman Skip Peel said.

The exploration is not accompanied with the hype of its older and deeper brother, the Haynesville Shale, but the Cotton Valley activity could be described as a "mini boom" because it's the play attracting all of the capital of late, attorney John Kalmbach, with the Shreveport firm of Cook Yancey King & Galloway, said at a recent meeting of royalty owners.

Felix Chavez walks on a Trinidad rig located on U.S. Highway 171 north of Grand Cane that is drilling for natural gas in the Cotton Valley formation. (Photo: Henrietta WIldsmith/The Times)
Changes in drilling techniques and improved efficiencies are credited with drawing companies such as Indigo Minerals and Memorial Resource Development to the Cotton Valley fields. Another factor is the advent of cross-unit lateral (CUL) wells, allowing the driller to reach out 8,000 feet and get into an adjacent section and squeeze even more minerals from the earth.

"It's the wave of the future. We need to be paying attention," Kalmbach said.

DeSoto property owner Gary Brummett was welcoming when Indigo Minerals approached him about putting in four Cotton Valley wells near his home on U.S. Highway 171 north of Grand Cane.

"I was tickled to death to lease them that site. I got a little change from the pipeline and I'll get money for water and money for production," Brummett said.

Better economics

From 2006 to April 2008, companies focused on horizontal drilling were preparing to target the Cotton Valley sands, historically explored with vertical drilling in this corner of Louisiana. But it never really got off the ground because it was interrupted by the Haynesville Shale announcement.

The companies with good Haynesville Shale acreage and the technical ability to drill horizontal wells drove up the costs for leases and field services for companies that wished to develop the Cotton Valley.

The only two companies supported in the public record as interested in the possibility of economic Haynesville Shale production prior to April 2008 are Encana and Chesapeake, Peel said.

"All the other operators in northwest Louisiana were focused on other horizons with most targeting the Cotton Valley group. At a time of high natural gas prices and seemingly unlimited Haynesville Shale acreage, the Cotton Valley faded into the background," he said.

Haynesville Shale operators struggle to make a profit at $2.50 mcf even with the benefit of longer laterals allowed by CUL wells. The Haynesville Shale is dry gas, and there is a glut of domestic dry gas currently and into the foreseeable future.

"In this depressed price environment it is surprising that we have even the modest amount of Haynesville Shale drilling activity that exists currently. The Cotton Valley areas suitable for horizontal drilling and producing natural gas liquids and condensate have better economics. They are more profitable than dry gas," Peel said.

Simplified, horizontal drilling and better hydraulic fracturing is making the Cotton Valley work for those companies that are giving it a go, said Nolan Shaw, geologist with J-W Operating in Addison, Texas, which is concentrating its efforts in the Elm Grove and Caspiana fields in south Caddo and Bossier parishes.

As a general rule, a Cotton Valley well in Caddo and DeSoto has an initial production of about 10 MMcfd, according to Keith Jordan, Indigo Minerals president.

"That's better than last year," Jordan said. "With these new techniques we believe we are making better wells than the old way of doing things."

By comparison, Memorial Development, which is concentrating its attention on the Terryville Field in Lincoln Parish, boasts producing wells of more 20 MMcfd, which is comparable to the early Haynesville Shale wells. Seven of the top 12 producing Cotton Valley wells are in Lincoln Parish, according to the Oil and Gas Financial Journal website.

Not without risks

The well-explored Cotton Valley is about 1,000 to 2,000 feet shallower than the Haynesville and is on the downslope from the Sabine Uplift, getting deeper in Webster, Claiborne and Lincoln parishes and going up again around the Monroe Uplift. It slopes downward again in south Caddo and north DeSoto parishes.

The sand formation is tightly packed but not as much as the pressure cooker Haynesville Shale. It can have liquids in it too, like oil, but not enough to make it an oil-rich play.

Memorial began building up its drilling profile last fall in the Terryville Field. The company and its subsidiary WildHorse Resources are concentrating almost exclusively there.

"They started really bragging about it; calling it the next Marcellous," said Patrick Courreges, Louisiana Department of Natural Resources communications director. "As drilling dropped off the table everywhere else, we actually saw rig counts go up in north Louisiana. It's been a pretty decent build from the low 20s to 30s. It's tipped a little since then but at least it's held steady."

There's a saying that the best place to look for oil and gas is where you found it before, and that's been proven with the Cotton Valley, Courreges said. "It's been interesting to watch."

The Cotton Valley formation is not without its risks.

Its tight grains are hard, not round, causing the sharp shards to tear up bits and take longer to drill. The formation also changes within short distances, requiring more geological study and mapping, Shaw said.

"In the Cotton Valley we're dealing with faults and stratigraphic changes in the sands. Some are river channels, marine bars that have all different depositional environments and all have different environments with the sands. … With the Haynesville Shale you have water contact. With the Cotton Valley you have lot of transition from gas to water," Shaw said.

He added: "We deal with risk every day. Geological risk, risk with mechanical, risk of something going wrong with drilling and completion. If we drill 10 wells, we know all 10 are not good. What we have to factor into the economics is development field type economics, not just one well economics."

The Cotton Valley wells can be more profitable not only because they produce more natural gas through the CUL, but also through the natural gas liquids, or NGLs, such as propane, ethane and butane that comes up with it.

"We can make a little more money because of the uplift in the revenue by the liquids that come with the gas," Jordan said.

On Brummett's property, Indigo built a super pad where the third of four wells is being drilled. Two wells will go south and two north.

The Trinidad rig was skid 21 days ago and the drill bit has already reached down more than two miles. After making a slight curve, the path levels out and will extend another mile and a half, reaching a total depth of plus or minus 18,000 feet. About 35 hydraulic fracturing stages will be used to release the gas.

"We're one of the faster drillers. We can drill two miles down and 1.5 miles sideways in 27 to 30 days, so we've gotten really good at drilling sideways. Some of that is due to technology, the drills used, bits used and the mud we use," Jordan said.

The multi-well pads, longer laterals and more frack stages that release additional gas combined with lower service costs keeps drilling operations around $7.5 million per well, Jordan said.

DNR keeps an eye on the drillers to make sure they don't break the rules by trespassing on another unit, Jordan said. "We can get more recovery of the land, which is better for state and royalty owner."

Brummett has heard complaints from other landowners about the growing use of multi-section drilling. Some are concerned if they are getting their proper royalty payments.

Brummett is not among the naysayers, though.

"These people are spending millions of dollars to drill something out of the ground that I can't get to myself," he said. "If they don't drill it then it's worthless to me. So when I get that nice check once a month I'll go to the bank and feel prosperous."

Even with all of the pluses of drilling in the Cotton Valley, companies such as Indigo are still dropping rigs as a pro-active approach to wait out the drop in natural gas prices. The company is operating two rigs this year, with plans to double that number in 2016.

"We're not making as much money as we did last year, but we believe the prices will trend back up," Jordan said. "But our rate of return is better than last year. With these new techniques we believe we are making better wells."

Unconventional Oil & Gas

Shale plays first come to mind when one considers unconventional resources. These unconventional resource plays may yield natural gas, gas condensates and crude oil. Some of the more noteworthy shale plays in North America include the Bakken, Eagle Ford, Marcellus, Fayetteville, Woodford, Niobrara, Haynesville, Horn River and Utica formations. Tight gas, coalbed methane, oil sands and heavy oil are non-shale unconventional resources.

The Cotton Valley subsurface formation is a tight gas play in northeast Texas and northwest Louisiana just above the Haynesville/Bossier Shale. It is Upper Jurassic and Lower Cretaceous in origin and consists of sandstone, limestone and shale. The depth of the Cotton Valley formation is roughly 7,800 to 10,000 feet. Although it is mainly a natural gas play, some oil has been produced in parts of the Cotton Valley.

Source: Oil & Gas Financial Journal

November 22nd - The 153-Year-Old Oil Well That Hasn't Stopped Pumping Yet
The 153-Year-Old Oil Well That Hasn't Stopped Pumping Yet

By Lynn Doan Nov 21, 2014 11:01 PM CT

About 70 miles north of Pittsburgh, a pothole-pocked dirt road along the side of a warehouse leads to a solitary oil well, undeterred by the recent plunge in crude prices.

McClintock No. 1, the world’s oldest continually producing oil well, is still going after 153 years, quietly churning out about 1/10 of a barrel a day from a small spot in a clearing of trees.

Crude bubbles up from this 625-foot chasm regardless of the swings in oil prices, which have slid 30 percent in the past five months amid a glut in global supply. On its best days, McClintock yielded about 175 barrels. It’s survived through all the industry’s highs and lows, from busts that sent prices below $1 per barrel during the Great Depression to booms that sent them over $140 in 2008.

The well’s output today is sold to a fuel company to make motor oil, but that’s not really why it’s still in operation.

“It’s history,” said Susan Beates, the 54-year-old curator and historian at the Drake Well Museum, an institution that operates the well for the Commonwealth of Pennsylvania. “It’s definitely not economically viable right now. It’s about the status.”

The McClintock well, originally drilled for lamp kerosene, is a remnant of an era long gone. Before automobiles had been invented. Before the U.S. grew dependent on gasoline for transportation. Before domestic oil production rose to almost 9 million barrels a day, only to drop to less than half that and then stage a comeback to reach 9.06 million this month.

Photographer: Lynn Doan/Bloomberg
Susan Beates, curator and historian at the Drake Well Museum, stands next to the first... Read More
Bear Market

In the century and a half that McClintock has run, two certainties have come to light, Beates said. One, nobody knows where oil prices are going and, two, nobody knows where U.S. oil production will peak, she said.

“Oil prices will and have always been up and down,” said Beates, wearing spectacles and a sweater she knit herself. “When we had wells coming online just as the Civil War was starting, what do you think happened to prices then? They plummeted. In 1861, our first exports went to Europe, and prices went up. Then the federal government starts taxing a dollar a barrel to fund the Union war and prices go back down.”

U.S. oil production has proven just as difficult to peg as prices, Beates said. Ten years ago, the Energy Information Administration was estimating that domestic output would slide to 4.1 million barrels a day in 2025. Today, it’s forecasting 8.68 million as drillers use a combination of hydraulic fracturing and horizontal drilling to pull record volumes of crude out of shale formations.

On Oct. 29, Beates was asked to draw on her 16 years of studying the history of oil to come up with an educated guess on where the price of U.S. crude will be the next day. Without missing a beat, she answered, “It will be different.”

West Texas Intermediate oil slid $1.08 a barrel to settle at $81.12 on Oct. 30.

To contact the reporter on this story: Lynn Doan in San Francisco at

To contact the editors responsible for this story: David Marino at Richard Stubbe, Bill Banker

November 12th - LNG Will Offer Protection Against Gas Supply Halts: IEA
LNG Will Offer Protection Against Gas Supply Halts: IEA

By Anna Shiryaevskaya Nov 12, 2014 7:52 AM CT

Rising liquefied natural gas output will help protect against disruptions globally as the conflict between Russia and Ukraine rekindles concerns about security of supply, according to the International Energy Agency.

Natural gas production is expected to rise in almost all regions except Europe by 2040, the IEA said in its World Energy Outlook published today. LNG exports will double, taking market share from interregional pipeline trade and contributing to diversification of supply, according to the Paris-based adviser to 29 developed countries.

“We see a strong wave of LNG coming to the gas markets, it should be very important from a gas security point of view,” Fatih Birol, chief economist at the IEA, said today in a presentation in London. “Energy security is a key issue and will be more important in the next years to come.”

Gas supply to Europe risks being disrupted for a third winter since 2006 amid a conflict between Ukraine and Russia, which meets about a third of the region’s needs for the fuel. Even with a Sept. 5 truce and an Oct. 30 gas deal, fighting continued in eastern Ukraine between government forces and pro-Russian rebels, while NAK Naftogaz Ukrainy is yet to pay Russia’s OAO Gazprom in full to secure winter fuel supplies.

World gas output is expected to rise 56 percent from 2012 levels to 5.378 trillion cubic meters (190 trillion cubic feet) by 2040, with about 31 percent of that coming from so-called unconventional sources such as shale rocks and coal beds. the IEA said. China and the Middle East will lead an increase in demand of more than 50 percent by 2040, the fastest rate among fossil fuels.

Supply Security

“Concerns about the security of future gas supply are allayed in part by a growing cast of international gas suppliers, a near-tripling of global liquefaction sites and a rising share of LNG that can be re-directed in response to the short-term needs of increasingly interconnected regional markets,” the IEA said.

Gas will become the leading fuel in the energy mix of developed nations by about 2030, aided by U.S. regulations limiting emissions from electricity generation, the IEA said.

LNG exports will rise to 599 billion cubic meters, boosting its share in interregional gas trade to 48 percent from 43 percent in 2012, with the rest shipped by pipeline, the report shows. New exporters from North America, Russia and east Africa will emerge, offering more flexibility to the markets, Birol said.

“The global gas industry is rapidly evolving,” Jerome Ferrier, president of the International Gas Union, said in an e-mailed statement. “Our investments in on- and offshore production, LNG and natural gas infrastructure will lead to more security of supply.”

To contact the reporter on this story: Anna Shiryaevskaya in London at

September 29th - Natural Gas Climbs as U.S. Chill May Spur Fuel Demand
Natural Gas Climbs as U.S. Chill May Spur Fuel Demand

By Christine Buurma Sep 29, 2014 9:01 AM CT

Natural gas futures advanced to a one-month high in New York on forecasts for colder-than-normal October weather that would stoke demand for the heating fuel.

Temperatures may be below normal in parts of the central U.S. from Oct. 4 through Oct. 13, according to MDA Weather Services in Gaithersburg, Maryland. Gas stockpiles were 13 percent below the five-year average in the week ended Sept. 19, the biggest deficit for the time of year since 2005.

“It’s getting chillier and historically prices usually start to gravitate higher beginning with the November contract,” said Tom Saal, senior vice president of energy trading at FCStone Latin America LLC in Miami. “The fact that we have a storage deficit is one reason why prices are higher than at this time last year.”

Natural gas for November delivery rose 3 cents, or 0.7 percent, to $4.059 per million British thermal units at 9:34 a.m. on the New York Mercantile Exchange. Volume for all futures traded was 11 percent below the 100-day average. Futures are up 13 percent from a year ago. Gas climbed to $4.084 per million Btu in earlier trading, the highest intraday price since Aug. 29. The October contract expired at $3.984 on Sept. 26.

The low in Chicago on Oct. 9 may be 42 degrees Fahrenheit (6 Celsius), 6 less than normal, according to AccuWeather Inc. in State College, Pennsylvania. Detroit temperatures may drop to 45 degrees, 2 lower than usual.

Gas Stockpiles

About 49 percent of U.S. households use gas for heating, according to the U.S. Energy Information Administration, the energy department’s statistical arm.

Gas stockpiles totaled 2.988 trillion cubic feet as of Sept. 19, compared with 3.374 trillion at the same time last year, EIA data show. Supplies were down 11 percent from a year earlier.

Inventories may climb to 3.477 trillion at the end of October, the lowest start to the peak heating season since 2008, according to the EIA.

U.S. gas demand may rise 1.8 percent this year to 72.6 billion cubic feet a day, led by industrial users, the EIA said Sept. 9 in its monthly Short-Term Energy Outlook report.

To contact the reporter on this story: Christine Buurma in New York at

August 13th - Blackstone Looks to Buy Shell's Interest in Haynesville

Blackstone Looks to Buy Shell's Interest in Haynesville
The Wall Street Journal reported this morning that massive private equity company Blackstone Group LP is in negotiations to buy Shell's Haynesville Shale interests for around $1 billion. Shell, known as SWEPI, LP in the Haynesville, entered the play as Encana's HV partner in 2007, a rare early entrance to a developing shale play for an energy major. By my count, Shell has completed 179 Haynesville wells, all in Louisiana (through mid-June), with their first completion in March 2009, but the company hasn't operated a Haynesville rig since April 2014.

This is the first big Haynesville deal in a while (assuming it gets done), but it follows Shell's corporate mandate to shed domestic shale assets and cut back on other domestic investments. Shell has a long presence in Louisiana, but late last year it cancelled its planned south Louisiana gas-to-liquid plant, which likely would have been fed by Haynesville gas. This created questions as to whether the company's Haynesville would now be orphaned within the company or sold.

Truth is, Shell never seemed too excited about the Haynesville. A shale play is just not a good fit for an energy major that needs to put its capital to work on very, very big projects to show big revenues and profits. As someone emailed me regarding Shell four years ago, "they just spend their time reading the safety manual" instead of completing and producing wells while competitors were striking deals and drilling wells at a breakneck pace. That kind of wild west environment never seemed right for a conservative energy major like Shell. It's no surprise that they are the first of the early Haynesville prospectors out of the play.

Blackstone and its private equity brethren, on the other hand, have been very interested in the "energy space" of late. "Smart money" purchasing "cast off" assets is an indicator to me that Haynesville activity is going to increase soon. A major exiting a maturing play is an ominous sign, but big companies make sweeping decisions when divesting that don't always take into account short-term economics. To me, this is a good buying opportunity for Blackstone and an easy way for Shell to resume focus on "elephant" projects in which it specializes.
Posted by Robert Hutchinson at 11:13 AM
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Labels: Blackstone Group, Deals, Haynesville Shale, Shell

May 1st - New Gulf Coast Steel-Feedstock Plant To Take In 60 MMcf/d Of Excess U.S. Gas
New Gulf Coast Steel-Feedstock Plant To Take In 60 MMcf/d Of Excess U.S. Gas

The gas’ cost to produce the feed to European plants will be about a third as much as that in Europe.

European steel-maker The Voestalpine Group has broken ground for a feedstock plant in Corpus Christi that will leverage low-cost, U.S. natural gas in converting iron ore into “sponge iron” for its plants in Austria.

“We investigated 17 locations in eight countries for this project,” Wolfgang Eder, Voestalpine AG chief executive and head of its steel division, says in a press release. “In the end, Texas was the most promising on all key criteria, such as logistics, energy supply, well-trained employees and political environment.”

The plant, which is to commence production by year-end 2015, is expected to use 22 billion cubic feet of natural gas per year—or about 60 million cubic feet per day. The cost of the gas will be about a third as much as the cost would be in Europe, the company notes: The four-year-average, U.S. (Nymex) price has been about $3.70 per thousand cubic feet; in Europe, about $10.

Current U.S. gas production is some 66 billion cubic feet a day; the plant’s draw would contribute to taking 0.1% off the oversupplied market.

The company adds, “The use of natural gas instead of coke and coal in the reduction process makes a significant contribution to improvement of the CO2 balance and is an important step in achieving the (company’s) very demanding, internal energy and climate goals.”

The $740-million outlay, involving some 1,000 construction jobs, is Voestalpine’s largest U.S. investment. The facility, called a “direct-reduction plant,” is to have 150 full-time employees and produce 2 million tons a year of hot-briquetted iron (HBI) and direct-reduced iron (DRI). About half of this will be used in steel manufacturing in Voestalpine’s plants in Linz and Donawitz, Austria; the balance, sold to partners.

“In contrast to the coke- and coal-based, pure-blast-furnace route, only natural gas is used as a reduction agent in direct reduction, which is more environmentally friendly,” the company reports.

In addition to using lower-carbon-footprint natural gas in its process, the Corpus Christi operation is to use round-trip shipping via large “eco-ships.” Also, a cooling system using seawater eliminates draw from freshwater sources.

“The open and professional collaboration with all the participants on site is exemplary,” Eder says. “This impressively demonstrates the USA’s efforts at rapid and sustainable reindustrialization. The fact that we, as a future-oriented, industrial company, were welcomed with open arms was a factor in selecting this location.”

Globally, Voestalpine has more than 46,000 employees.

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas Investor,, Oil and Gas Investor This Week, A&D Watch,, Contact Nissa at