Barnett Players Keep Production Growing

Carrizo fracs fie horizontal wells (7,000 feet deep, 3,000 feet long) in the Rendon area of the Barnett in Tarrant County.

R?ig counts are falling all over the U.S., in some weeks by as much as 40 to 70 rigs. In the Barnett shale play in the Fort Worth Basin, activity is down about 30% from a year ago, according to a recent report from Tudor, Pickering, Holt & Co. Securities Inc.

While that is the general trend, it’s not true for all producers in the basin. Despite falling rig counts, some operators are still reporting increases in reserves, production and take-away capacity.

“We had a very good year in 2008,” says Glenn Darden, president and chief executive for Fort Worth-based Quicksilver Resources Inc. “We once again had big reserve additions, resulting in about 2.2 trillion cubic feet of proved gas reserves, including 1.9 trillion in the Barnett shale alone. That’s a 58% increase over the past year from just the Barnett.”

The increase is partly attributable to bringing new wells online at the company’s organically grown Lake Arlington and its acquired Alliance projects in Tarrant and Denton counties.

In August 2008, the company acquired producing and nonproducing leasehold, royalty and midstream assets associated with the Barnett shale in northern Tarrant and southern Denton counties. The assets, representing about 20% of its base, were purchased from Chief Resources LP, Hillwood Oil & Gas LP, Collins, Young LLC and others for $1 billion and some 10.4 million shares of common stock.

The acquisition netted Quicksilver about 13,000 Fort Worth Basin acres, which its engineers estimate contain more than 1 trillion cubic feet of recoverable gas, including about 300 billion cubic feet of proved reserves (40% proved developed producing) and making about 50 million cubic feet per day.

Altogether, its reserves as of year-end 2008 rose 42% from 2007, representing 474% organic production replacement and 785% total replacement. At press time, projected fourth-quarter 2008 production guidance was 325- to 335 million cubic feet of gas equivalent per day, an approximate 20% increase from the prior-quarter average daily volume.

Hedging

“We carry a little higher debt load, so we are very aggressive on the hedging side. We now have a nice hedged position, not only on the product price but also on the downstream side,” says Darden.

"We expect to drill about 180 well in the Barnett this year, " says Glenn Darden, president and chief executive of Quicksilver Resources Inc.

During fourth-quarter 2008, Quicksilver hedged some 85% of its gas production at a floor of $8.87 per million Btu, about 90% of its oil production at $65 per barrel and about 20% of its gas liquids at $1.04 per gallon.

For 2009 and 2010, the company has hedged 75% and 65%, respectively, of its anticipated gas production at a floor of about $8.60 per million Btu. Quicksilver places its hedges with its credit-facility bank group, including JP Morgan, Deutsche Bank, Credit Suisse and TD Bank.

The netbacks are better, too. “We have secured firm transportation out of the basin, which allows us to get higher netbacks for our product,” he says. At press time, Quicksilver had secured transportation to Henry Hub for about 100 million cubic feet of gas per day at a cost of $0.52 per thousand cubic feet and 260 million per day to the Houston Ship Channel at $0.35 per thousand, including fuel.

“Toward the end of 2009, we have secured 50 million cubic feet per day of firm transportation on the new Midcontinent Express pipeline, which is expected to be completed in the third quarter,” Darden adds.

Going forward, the 500-employee company plans a $600-million capital budget for 2009, including $400 million for drilling, $155 million for gathering and processing facilities, $40 million for leasehold and $5 million for other property and equipment.

?“We had our biggest quarter in earnings and we had our biggest loss in earnings and it all happened in one year,” says Brad Foster, senior vice president, central division, for Devon Energy Corp.

“All but about $50 million of that will be spent in the Barnett,” says Darden. “Because of our hedge position, we have a good handle on our cash flow. Our budget is essentially living within cash flow for 2009, while the service costs were based on 2008. We are seeing some significant savings of at least 10% to 15% on those costs now.”

The company started assembling leases in the Barnett in 2002 and its assets are in several areas that it has high-graded over time. The company is now in full development mode, albeit at a slower pace due to commodity prices.

“We now have a good spacing and development plan to harvest our portion of the field. We have about 10 years of inventory, and everything we are drilling has a horizontal component. We expect to drill about 180 wells this year in the Barnett.”

The company plans to use eight to nine rigs—down from a peak of 14 rigs—but the drilling program is flexible. Because most of its leases are held by production with favorable terms and extensions, it is only required to drill 80 wells in 2009 to hold leases.

Quicksilver plans to stay in the Barnett for the foreseeable future, as Darden believes that unconventional gas will be an increasingly significant source of energy for the U.S. Also, the Barnett has been “a proving ground for companies to transport the technology into new shale plays.”

Discretionary fracturing

Carrizo Oil & Gas Inc., based in Houston, is also focused on the Barnett. It has brought 11 new horizontal gas wells online since the start of the year, for a combined gross production of 31.5 million cubic feet equivalent per day.

?Nabors rig #714 drills 5,000 to 9,000 eet deep, targeting Barnett shale in Cleburne, Texas, for Devon Energy.

Carrizo has oil and gas production primarily from the Barnett in North Texas and from onshore trends along the Texas and Louisiana coasts.

“These 11 are new Barnett wells that we started drilling as early as April of last year,” says Richard Hunter, vice president of investor relations. “We drill up to six wells from a single pad, one after the other, then hydraulically fracture stimulate them before we connect the wells to a pipeline and initiate sales. So we had been anxiously awaiting the results.”

The wells are in southeastern Tarrant County, in the core of the Barnett, on Carrizo’s six-well Cain, three-well Copper Bluff and two-well Harburger drilling pads.

“One of the Cain wells was drilled in a manner different from any well we’ve drilled in the Barnett to date,” he says.

Carrizo’s engineers devised a new well-spacing configuration they thought would more efficiently drain the producible gas in the shale formation. They decided not to simply reduce the spacing between the wellbores to 250 feet, because the result might be a large degree of frac-treatment communication.

“We think we would be essentially over-fracing the rock and wasting some energy and money,” Hunter says.

The new well configuration is three laterals drilled in a stagger-stacked manner, and tests the concept of placing two layers of horizontal wells in thicker parts of the shale.

Two of the wells were drilled about 150 feet above the limestone base of the Barnett and 500 feet apart. The third lateral was drilled 250 feet between the first wells but was placed about 80 feet higher in the formation. The geometry of this orientation causes the third well to be around 262 feet away from the lower wells.

This wellbore configuration should cause the rock to be more uniformly fractured, and capture gas that is structurally higher in the shale formation and may not have been otherwise drained, resulting in higher gas production per acre.

Moving the third wellbore higher into the section also reduced frac commingling. According to the plan, each wellbore will be fraced in six to seven stages.

“We may monitor the well’s production performance for up to a year before we decide if this is the best way to go about drilling and completing our wells,” Hunter says. The method involved some risk, as the higher section could have contained less gas or come in at a lower rate, but so far Hunter sees no such evidence. The well is producing at the same rate as the other wells.

“These wells were not in our reserve books. They are classified as exploration wells,” says Hunter. “Not that we have ever drilled a dry hole in the Barnett. It’s simply a classification due to reserves-booking criteria.”

Carrizo has difficulty booking undeveloped reserves in the Barnett due to its acreage layout. It drills mainly in urban areas and develops small clusters of scattered leases, usually surrounded by other leases.

“For example, if Chesapeake (Energy Corp.) or XTO (Energy Inc.) should drill a well right next to one of our lease lines, we could use that data to book some reserves on our wells, but that doesn’t happen very often.”

Classifying wells as exploration, as opposed to exploitation, acceleration or development, has little to do with geology and everything to do with how the acreage is distributed on the surface, he says.

Meanwhile, Carrizo’s top wells are on the University of Texas at Arlington campus. “Those are the best wells we’ve ever drilled in the Barnett. The rock in that neighborhood is extremely rich in gas and porous. Those wells tested at higher rates and pressures than any others.”

The company drilled six wells on campus that flowed at unusually strong average daily rates above 3.5 million cubic feet for the first 90 days. Carrizo then moved the rig to another location, where it will drill six to eight more wells. (For more on this activity, see “Urban Drilling,” Oil and Gas Investor, August 2008, at OilandGasInvestor.com.)

“We kept the traffic and noise levels low, and recently sent them a check for $528,495 for the first royalty payment from production. So they are happy and we are still on campus.”

Carrizo plans to have at least 20 extended-reach horizontal wells on the campus by 2010, drilling one quadrant at a time. But with high oilfield-service costs, it’s in no hurry.

“We have not seen any material drop in costs yet,” says Hunter. “That’s because we are not doing anything we don’t have to. We are not signing contracts. We believe that every day we delay in signing a contract to fracture stimulate a well, for instance, it will be cheaper the next day.

“We brought in our new wells and ramped up our production, and we are drilling, but the rate at which we fracture our wells is completely discretionary.”

Single-digit growth

Major Barnett producer Devon Energy Corp. echoes that strategy. While the Oklahoma City-based company’s Barnett output reached 1.2 billion cubic feet per day in fourth-quarter 2008 (up 31% from 2007), it does not intend to keep drilling at 2008’s rate.

?A Carrizo Oil & Gas worker checks three horizontal Barnett shale-gas wells in Tarrant County, southeast of Fort Worth city limits.

Since Devon acquired Mitchell Energy & Development Corp. in 2002 and Chief Holdings LLC in 2006, its investment and production in the Barnett have continued to grow. But for now, Devon plans to manage its Barnett production to single-digit growth, year-on-year, because the gas market has “fallen drastically over the last six months. We don’t want to put more gas into a low-price environment,” says Brad Foster, Devon senior vice president, central division.

In 2007, Devon drilled more than 600 wells in the Barnett. In contrast, it plans to drill about 200 in 2009, staying within its primary acreage in Denton, Wise, Tarrant, Parker and Johnson counties.

Meanwhile, last year, the company began to downsize to 250-foot spacing for its horizontal wells, closer than its previous 500-foot spacing. The results of its first six wells are encouraging, with initial production averaging 2.1 million cubic feet of gas per day. Devon also plans to continue development of 500- and 1,000-foot-spaced lateral wells.

“We were running 39 rigs coming into the end of 2008,” says Foster. “Since that time, we have backed off, and we are currently running 23.” In the next few months, Devon plans to pare that number to about eight.

“From a corporate perspective, now we are managing cash,” says Foster. “Last year was a year of two contrasts for this company. We had our biggest quarter in earnings and we had our biggest loss in earnings, and it all happened in one year.”

Devon has hedged about 15% of its 2009 production, modest when compared with that hedged by other E&Ps. Meanwhile, its capex program, scaled back 64%, is projected to exceed cash flow by about $1 billion. Devon’s sizable balance sheet and yet-untapped $3.1-billion borrowing base should support its global E&P program.

“We have commitments to deepwater and international projects that are long-term, so we will continue to fund those. But where our assets are held by production, such as in the Barnett, we are going to decrease our activity.”

Devon has no plans to abandon the Barnett, though. “This company was built around unconventional gas. Even though we are slowing down, short-term, we believe the Barnett has tremendous upside. I don’t think there is any possibility that Devon would shed its Barnett assets.”

Take-away demand

In January, the Dallas-based company completed its 31-mile, 36-inch Southern Shale line that originates in southern Tarrant County and provides 700 million cubic feet per day of take-away capacity. Southern Shale will move gas to ETP’s Maypearl compression station, then to the company’s existing infrastructure.

?“There are producers talking to us about significant infrastructure needed in and around the Dallas-Fort Worth airport,” says Mike Howard, president of Energy Transfer Partners’ midstream operations.

In February, ETP completed its 20-mile, 36-inch Cleburne-to-Tolar line that originates in the western portion of the Barnett play and connects to its Cleburne compression station, then to its Cleburne-to-Carthage and North Texas pipes.

The two pipelines will provide an additional 1.1 billion cubic feet of daily capacity from the Barnett, helping to boost the partnership’s capacity out of the shale to more than 4.6 billion cubic feet per day.

Also in February, the company completed its 56-mile, 36-inch Katy Expansion pipeline, adding another 400 million cubic feet of Barnett take-away capacity.

In April, ETP’s Midcontinent Express pipe, which originates in southeastern Oklahoma, will come online, adding another 500 million cubic feet of daily take-away capacity from the Barnett and other producing regions throughout Texas. “We are the largest transporter of gas out of the Barnett, by far,” says Mike Howard, president of Energy Transfer’s midstream operations. “Our Barnett shale pipeline system essentially operates fully subscribed.”

In March, ETP will start construction on its 150-mile, 42-inch Texas Independence Pipeline (TIP), which will increase capacity by another 1.1 billion cubic feet per day.

“All of these pipelines are bolt-on expansions to our existing infrastructure,” says Howard. “This bolt-on strategy is what has made our Texas pipeline system so successful.”

ETP secured funding for TIP and other projects by raising $800 million via recent debt and equity offerings. “We were very pleased with the favorable financing terms we were able to secure and the market’s response to our offerings during a difficult time,” says Howard.

In December 2008, ETP offered $600 million of 9.7% senior notes due 2019 that may be called in 2012. Morgan Stanley & Co. Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities Inc. and Wachovia Capital Markets LLC were joint book-running managers.

In January 2009, ETP offered 6 million common units representing limited-partner interests at $34.05 each, and an over-allotment of 900,000 additional units. Credit Suisse Securities (USA) LLC, Citi, Morgan Stanley & Co. Inc., UBS Investment Bank and Wachovia Capital Markets LLC were joint book-running managers, and Barclays Capital Inc., Deutsche Bank Securities Inc., Raymond James & Associates Inc. and RBC Capital Markets Corp. were co-managers.

Despite the slowdown in drilling, Howard is seeing increased Barnett gas production. “There are producers talking to us about significant infrastructure needed in and around the Dallas-Fort Worth airport and some other difficult places that are expensive and hard to get to. They continue to ask us to quote pipelines to get their gas out of some of these regions.”

Meanwhile, steel costs for large-diameter Barnett pipes have fallen off their price peaks of last summer as steel mills find themselves with more excess capacity than they had last year, says Howard.

“We have had mills coming out of the woodworks that are available right now. We’ve gotten quotes from 17 pipe mills recently. If we had asked that number for quotes last summer, we may have had two quotes returned.”

During the past two years, most of ETP’s pipe supply came from Greece and Italy because domestic mills were so loaded and backlogged. Now, domestic availability and prices are lining up with that of European suppliers.

“There are also several new U.S. mills that will be coming online, so we should see increased competition also driving steel prices down.”