During the past year, the Haynesville shale has remained one of the top unconventional plays in the U.S., its status bolstered by impressive geological characteristics and stellar well results on the Louisiana side of the play. Now, recent drilling successes in the southwest portion of the Haynesville, in East Texas, have heightened expectations for the “Texas sweet spot” and the emerging Bossier interval.

Initially, Haynesville drillers in Texas focused on Harrison and Panola counties, to the north. But as drilling expanded southwest, to the sweet spot in Shelby, San Augustine and Nacogdoches counties, operators found the rock quality was similar to the Louisiana core area and boasted higher organic carbon, pressures and recoveries than in the north.

One of the first wells to validate East Texas potential was Devon Energy Corp.’s #1H Kardell Gas Unit, in San Augustine County. The Oklahoma City-based company’s well yielded an average continuous 24-hour flow rate of 30.7 million cubic feet of gas equivalent per day. Drilled to a total depth of 18,350 feet, its horizontal section stretched 4,500 feet.

At press time, EOG Resources Inc. of Houston further confirmed the East Texas and Middle Bossier potential with the results of its first Middle Bossier completion, #2 Hassell, in Nacogdoches County. It posted an initial production (IP) rate of 21 million cubic feet equivalent per day on a 30-day test. The well is adjacent to Cabot’s County Line project area and 15 to 20 miles northeast of Goodrich Petroleum Corp.’s Angelina River Trend acreage.

At year-end 2009, EOG was producing 60 million cubic feet per day from its Haynes­ville/Bossier activity, and it expects to ratchet that up to 175 million per day by the end of 2010. It holds 160,134 Haynesville acres and estimates its potential reserves are 10 trillion cubic feet from the Haynesville and Middle Bossier shales.

To date, the Texas sweet spot has hosted 12 wells with an average IP of 16 million cubic feet equivalent per day and estimated ultimate recoveries (EURs) of 6- to 12 billion cubic feet equivalent (Bcfe). The wells are deeper and more expensive than in other areas of the play, but some operators think the production rates make up for the cost.

Encouraged by East Texas production to date and the Bossier’s potential as a stand-alone reservoir, operators have been busy locking in acreage and refining their development approach—and they’re already seeing promising results.

The Two Haynesvilles

Cabot Oil & Gas Corp. has been an active player in East Texas for the past five years. In late March, its first operated horizontal Haynes­ville well, #1 King Gas Unit, in San Augustine County, Texas, was producing 19 million cubic feet equivalent per day. The well was completed with a 4,487-foot horizontal leg and 14 frac stages.

To date, the company has some 31,000 net acres prospective for the Haynesville in East Texas, primarily in Shelby and San Augustine counties. Its acreage seems to be in the second core area of the Haynesville, according to Cabot.


“We got into East Texas chasing the Cotton Valley, Pettet and James objectives, before the area morphed into the Haynesville shale,” says Mike Walen, senior vice president and chief operating officer. “There wasn’t any Haynes­ville shale drilling on the East Texas side then.”

Cabot drilled a vertical Haynesville well, the #3 Von Goetz, in 2007 and completed it in the Haynesville shale, Middle Bossier and Haynesville Lime. After seeing the results, the company leased additional acreage.

In 2009 it formed four separate small areas of mutual interest (AMIs) with other companies. Through the AMIs, Cabot drilled a well with Common Resources LLC, of Houston, #1 Burroughs, which came on line at 20 million cubic feet per day. Cabot also sold some acreage to Crimson Resources LLC, Tulsa, and Devon Energy, holding on to an override and select surrounding acreage. The acreage would later be the location of the #1H Kardell Gas Unit, Devon’s winner.

Walen credits better technology for much of its success. “Without it, the results weren’t going to happen. On the completion side, the plug-and-perf method isn’t new technology, but the service companies have improved the technology, reliability and ease of handling the plugs. The fluids’ properties have also been improved and allow us to slickwater frac these reservoirs and effectively prop the formation.”

Cabot has up to 12 wells gross planned in the East Texas Haynesville. It has 10 left to drill, and most of the wells are outside-operated. The company’s 2010 capex budget is $648 million, with 30% earmarked for East Texas.
Walen says drilling in the area has skyrocketed during the past 12 months, as many operators work to hold leases. “There was a lot of money spent during the last two years putting acreage blocks together. Companies don’t want to lose them.”

For its own Haynesville wells, Cabot is looking at 55 to 60 days to drill and set casing. It factors in a couple of additional weeks to complete the well after lining up a frac crew.

“We’re doing up to 15 stages, but we’re starting to question whether more frac stages are pushing mechanical and economic limits. There’s limited data in East Texas, but our well model is an IP of 20 million cubic feet per day for EUR of 7- to 7.5 Bcf of gas.”

Cabot keeps its wells pinched back during flowback. The practice may not generate blockbuster IP rates, but the management hopes that flowing the wells back gently, keeping the sand in place, and ensuring the formation doesn’t collapse around the wellbore will yield a higher EUR.

Based on rock quality, there are two separate Haynesville core areas, Walen says. The northeastern core is between Bossier and De Soto parishes in Louisiana. Another area is the sweet spot developing in Shelby and San Augustine counties, Texas. The East Texas trend’s rock properties are similar to the Louisiana side, he adds.

“But when you go north of that trend into Panola, Rusk, and Harrison counties, our interpretation is that the rock properties are different. There’s plenty of gas up there, but the recoveries aren’t quite the same as what you’d see farther south.”

The verdict is out on how viable the whole play is in a sustained, low-gas-price environment. “We will see modest returns with gas around $4, although this will be offset by the rapid expansion of production,” Walen says.

“A low-gas-price environment certainly means we need to concentrate on cost control. Most acreage costs have come down from the highs of several years ago, and we are seeing moderation in most service costs. Where we’ve seen the largest cost increase is in high-pressure pumping services, which are up 50% over last year. This makes a big impact on economics.”

In 2009 Cabot had 70% of its gas production hedged at prices north of $10. Its balance sheet carried only 30% debt, leaving it with plenty of dry powder to exploit key shale plays, Walen says. “We’re definitely going to keep drilling in East Texas to hold our acreage and evaluate what the deep Haynesville looks like under our spread.”

Rock Quality

Houston-based Goodrich Petroleum Corp. started acquiring acreage in East Texas and North Louisiana in late 2003, primarily targeting shallow objectives. By 2008, the company had drilled about 500 shallow wells across the area. At the same time, Chesapeake Energy Corp., Petrohawk Energy Corp. and others started testing the deeper horizons offsetting Goodrich’s acreage in North Louisiana, sparking a land grab across the play. Today, Goodrich has 85,000 net acres in the Haynes­ville, of which 60,000 are in East Texas.

“We started with no production from the Haynesville as we entered 2009,” says Robert Turnham, president and chief operating officer. “As we exited, our fourth-quarter Haynesville production averaged 120 million cubic feet per day gross (36 million per day net) with about 15% coming from East Texas.”

Initially, the company completed wells with fewer perforations to get better frac length. But because of the Haynesville’s high pressure and temperature, Goodrich doubled the number of perforations to better stimulate the near-wellbore rock. This could be a game-changer for the company, Turnham says, as its average IP rates in Panola and Rusk counties have jumped from 7.5 million a day up to almost 12.5 million because of increased frac density and better stimulation.

The company has set a $255-million capex budget for 2010, of which two-thirds is slotted for the Haynesville. About $50- to $60 million is budgeted for drilling seven wells in East Texas, with five wells planned for the southwest extension of the play. Two 100%-working-interest wells are planned in the company’s Beckville/Minden acreage block, where it holds 37,000 net acres.

Operators are now testing an emerging area in Nacogdoches County called the Angelina River Trend. There, Goodrich is drilling its first well, which should spud in the second quarter. If all goes as planned, a second well will be under way there later this year.

Geologically, the core of the Haynesville play is in the southern portions of Caddo and De Soto parishes in North Louisiana, and extending southwest into Texas. Going due west from the core into Panola and Rusk counties, Texas, there are lower porosities and permeability, and therefore bigger challenges in how to stimulate the rock and get the most productive wells, Turnham says.

“In North Louisiana, a well may have 12 stages and each stage would be 360 feet wide. We’ve shrunk that down to intervals of 250 to 260 feet in East Texas. We’ve been experimenting with how best to drill and complete these wells. It’s an evolution, and we’re seeing improving results with each change to our procedures.”

At year-end 2009, Goodrich’s reserves averaged 6.5 Bcf per well in the Haynesville, and the majority of its locations were in North Louisiana. Turnham says the company’s acreage in Panola and Rusk counties is likely a 4.5-Bcf-per-well area, but he’s optimistic that the EURs will improve with new completion techniques.

Some industry watchers question whether Haynesville production in East Texas will equal Louisiana’s bounty. At the end of the day, it’s about the quality of the rock.

Turnham says, “When you start extending southwesterly from De Soto Parish, the quality of the rock is similar to that in North Louisiana. It’s where we saw Devon Energy’s 30-million-cubic-feet-per-day well, and see other operators such as EOG, Cabot, Common Resources and Petrohawk posting very impressive well results, with IP rates from 10- to 20 million cubic feet per day.”

Goodrich’s Haynesville wells initially required an average of 46 days to hit total depth. That’s since been reduced to 40 to 41 days, with a recent well drilled in 32 days. The company’s average well in the play has been costing some $7.5 million.

“When you’re looking at cost, it’s all about how many days it takes you to get to total depth because your spread rate probably falls in the $50,000- to $60,000-per-day range. Frac costs peaked at the height of the play, and we were spending close to $2.5 million to stimulate a 12-stage frac.

“That dropped to almost $1 million when gas prices dropped. Today, pressure-pumping services have gotten very tight, although frac costs are currently still 50% to 60% of what they were at the peak.”

Turnham says Goodrich is able to achieve a 10% rate of return on a $3.50 gas price at the average well cost of $7.5 million. But, when other expenses inherent to running a business are factored in, a $4.50 gas price better justifies the cost of capital.

“At the end of the day, the Haynesville has some of the better economics compared with many of these other shale plays. So if the economics are marginal in the Haynesville, then a lot of these other plays simply won’t work at $4.50. In fact, the marginal cost of gas, being the cost to produce at an adequate profit the last Mcf of gas needed to supply the last Mcf of demand, is likely $6 to $6.50, and therefore current prices are unsustainable.

“The attractiveness of shale plays, and the Haynesville in particular, is in the low finding and development cost, no dry-hole risk and low lifting costs. The challenge for the industry is accessing and allocating capital over a long period of time, and doing so in the least dilutive way while maintaining a strong balance sheet.”

Gas Factory

Over time, unconventional plays like the Haynesville have reaped the benefits of technology enhancements that extend wells’ horizontal reach and increase the number of fracture stimulations. As this occurs, E&Ps can improve operating efficiencies and well performance, driving down costs on a per-unit basis and improving margins.

“This ‘gas factory’ approach is a strategy we employ for all of our resource plays, and one which, over time, will allow us to maintain our position as one of the lowest-cost producers,” says Paul Sander, vice president of Encana Corp.’s Midcontinent business unit, USA Division.

Encana entered the Haynesville in 2005, drilling its first wells on the Louisiana side in 2006. After drilling several horizontals in 2008, it expanded its position to the 429,000 net acres it has today. About 230,000 of these are in the core in Louisiana, extending into East Texas.

Through a partnership with Royal Dutch Shell, the company has 30 rigs operating in the play, one of which is running on the East Texas side. In 2010, Encana plans to drill 100 net Haynesville wells, 225 gross, and expects to exit the year producing around 400 million cubic feet per day. Average production is estimated at 325 million a day annually.

“The play is deep—11,000 to 13,000 feet in the core,” Sander says. “The well we’re drilling on the East Texas side is even deeper, a 14,000-foot vertical. Because of our experience, we’ve been able to get the wells down to vertical depth faster, and then drill the curve and the lateral quickly by drilling underbalanced and selecting the proper motors and bits. We were working with oil-based muds in this area on a traditional basis, but now we’re starting to test water-based muds. These optimization efforts have reduced our drilling time dramatically.”

The company’s average drilling time is just below 50 days. As Encana’s gas-factory strategy develops, this time should come down to the low 30s, Sander says. Meanwhile, on a 30-day basis, the company’s IPs for Haynesville wells have shot up from 8.2 million per day during fourth-quarter 2008 to 16.9 million in the first quarter of 2010.

“We’re optimizing our completion by drilling longer wells, pumping more stages, pumping sand at higher concentrations and adding more perf clusters. We’re also breaking the rock and keeping the fractures open more effectively.”
In spite of gas prices’ recent lows, Encana’s management says Haynesville economics remain compelling, partially because of its improved well performance and reduced drilling costs.

“In the core, well costs are around $9 million. We’re hoping to exit the year closer to $8.5 million and as we get into gas factory, that number should come closer to $8 million. Across Encana, all of the plays we’re working on have supply costs in the range of $3 to $4. The Haynesville is going to be well below $4, meaning we can return our cost of capital at gas prices above $4.”

Encana is also evaluating its mid-Bossier shale potential in its core position in Louisiana/East Texas. Its initial results there have been positive, and the company anticipates this shale will become another commercial development.
“Getting in early and establishing a strong land position was key, as the Hayneville is a premier reservoir that has the potential to be one of the lowest-cost plays in the entire industry. In terms of the best plays to be in, if it’s not the leader, it’s certainly going to stay near the top.”

East Texas Extension

Radnor, Pennsylvania-based Penn Virginia Corp. started the Haynesville-Bossier buzz in East Texas in May 2008 with its #5-H Fogle in Harrison County, Texas. The horizontal well, drilled to 11,378 feet, had an IP rate of 8 million cubic feet per day, greater than the company expected.

Penn Virginia’s Haynesville entry was an outgrowth of its existing program in East Texas. “We’d been making a living off of some low-permeability rocks for a long time, so we were trained to look out for other similar kinds of opportunities,” says Mike Mooney, vice president and regional manager.

“As we were drilling the wells into the shale we were picking up some large gas shows. We drilled a dozen wells across our acreage position to evaluate it, utilizing state-of-the-art technology to help us identify the gas-in-place numbers. Over time we found the same general characteristics across a broad area.”

The company estimated about 150 Bcf of gas in place per section in a lower shale interval and 50 Bcf per section in an upper shale. As the company got ready to start drilling, commodity prices skyrocketed and a boom hit the oil and gas industry. Penn Virginia needed to drill several wells across its East Texas acreage to rationalize increasing land costs, Mooney says.

“To that end, we’ve drilled 21 wells; 16 are producing and five are pending completion. We’ve also drilled quite a few wellbores throughout the Cotton Valley, and we’re going to see about capturing those reserves with horizontal wellbores as opposed to 20-acre-offset vertical wells.”

Penn Virginia has identified key elements of what it will take to succeed in the Lower Bossier/Haynesville. At year-end 2009, the company held 55,000 acres in East Texas, and its production there was 4.3 Bcfe, or 8.43% of the company’s total.

This year, its Lower Bossier/Haynesville budget is $120 million, of which $10- to $12 million is for small land and lease acquisitions. The company is also open to joint ventures.

Now that companies have locked up most of the leases in the Haynesville trend, there is pressure to hold them by production. Other challenges include managing the conversion from water-based to oil-based drilling mud and high bottomhole temperatures and pressures.

“Everything from the bits, motors and MWD (measurement-while-drilling) selections has to work and be sustained in that kind of environment to effectively drill these wells,” says Mooney. “Well completions also require thorough planning. And while service costs have come down slightly, the big operators have a lot of the equipment tied up in long-term contracts. We have to work around all of those limitations.”

While Penn Virginia laid down rigs (as did much of the industry) in October 2008, it started to increase drilling again in fourth-quarter 2009. By that point the company was able to drill a 4,500-foot lateral in the shale in about 30 days, and its spud-to-sales time ranged from 45 to 50 days. Also in 2009, the management decided to start drilling longer laterals and increase frac stages. This strategy is likely to push the spud-to-sales time to 60 days, with higher costs, but it should ultimately add reserves at a higher stabilized rate.

“Right now, a 4,500-foot lateral costs about $7.5 million,” says Mooney. “We’d all feel better with gas prices north of $5, but these wells are cheap to operate. Our direct lifting cost is less than $0.20 per Mcf. And we have less than $400 an acre tied up in most of our acreage.”

The company’s two East Texas wells that came online in early 2009 had IPs ranging from 10- to 11 million cubic feet per day, but the EUR for the wells is a mystery, Mooney says.

“We conservatively think 4.5 Bcf, optimistically 7.5 Bcf or greater. The trick is determining where these wells stabilize. A steep initial decline in the wells followed by stabilized production and minimal decline—that’s been our experience since we entered the play.”

Operators in the shale need to have a systematic approach and keep expectations in tune with reality, Mooney says. “In plays like this there’s a lot more that you don’t know versus what you do. In the end you have to expose the capital, drill a number of wells and take opportunities to improve. Despite the initial hype, there’s predictability to a play like this. It’s on the upper end of capital intensity, but the bang for the buck comes in the long-term production.”

Haynesville Leveraged

Oklahoma City-based GMX Resources Corp. has amassed 42,400 net acres in the Haynes­ville with about 279 de-risked locations available to drill horizontal wells. The company also has more than 1,300 Cotton Valley and Travis Peak locations. At year-end 2009, it had 355 Bcfe in proved reserves in the play and 3 trillion cubic feet of upside potential.

This year, GMX plans to spend $175 million drilling 20 Haynesville and up to four Cotton Valley horizontals.

Michael Rohleder, president, says the right formula for completion practices is ever-evolving. “More drilling success in East Texas is confirming what we and other operators have said for the last year—the area will produce some very large Haynesville wells. As an example, our #1 Mia Austin well in Harrison County had an IP of 14.1 million cubic feet per day and averaged 7.5 million per day in its first 30 days. It’s our best well yet and is one of the best wells reported in the entire western part of the total basin.”

Like many operators, GMX has changed its approach over time to maximize drilling results. Along these lines, the company recently decided to switch to a larger-diameter casing scheme. This will allow its completions engineers to accomplish a number of different treatment options that, theoretically, will have a positive impact on results, Rohleder says.

In addition, increased efficiencies have reduced average drilling time from 70 days in 2009 to as few as 26 days currently. Reduced drill times and improved economies of scale pared costs by 54% and increased return on investment in the past year, he adds.

GMX’s EURs are expected to average 5.4- to 6.5 Bcf per well on 80-acre spacing with a 32.5% recovery factor. This translates to gas-in-place values of 160 Bcf per section (640 acres), which it has confirmed by examining core samples and logging a number of vertical tests across its property base.

Rohleder says the company’s initial leasing started 10 years ago, and its average acreage cost is now about $1,500 per acre.

“We started as a Cotton Valley story in the areas now prospective for the Haynesville. While there has been a certain degree of serendipity, we did hold rights to all depths on much of our leased acreage for many years, which has been a significant advantage for us as we have expanded into drilling Haynesville wells. By virtue of production in the Cotton Valley, all of our Haynesville acreage is held by production.

“Our company’s size, the contiguous acreage base and the existing infrastructure give us a very low-cost platform from which we are now drilling these Haynesville horizontals. Our well hook-up costs are some of the lowest in the industry because all our drilling locations are purposely selected to be close to existing gathering and transport pipelines.”

Though service costs in the Haynesville have climbed during the past several months, they are still well off their highs of 18 months ago. GMX’s completed well costs were as low as $6 million in 2009.

“Our costs have increased in the first part of 2010, but even in the short period between February and now, we’ve reduced our current AFEs (authorizations for expenditures) by 10% and expect to continue to drive costs down throughout the year—especially if gas prices stay low and operators start to lay down rigs. This will improve our overall economics.”

Many Haynesville operators realize technical expertise and capital availability will determine the most successful players. In the meantime, operationally, costs are still rising in the play. On the financial side, Wall Street continues to seek companies that can demonstrate growth, Rohleder says.

“But growth alone is not enough,” he adds. “Companies must be able to grow at low cost. This is what the Haynesville offers efficient operators. Our average finding and development costs are $1.37 per Mcf. IP rates are rising, and EURs at GMX Resources continue to increase. We are the only small-cap company that is fully leveraged to the Haynesville, and we have prospects in front of us to grow our company to 10 times its current size.”

Take-Away Capacity Grows

As producers focus on growing Haynesville production, the midstream side is just as busy, expanding infrastructure to take volumes to market. As a result, the infrastructure in place in the Haynesville is substantial, says Tim Dahlstrom, senior vice president of Dallas-based Energy Transfer Partners LP.

In late 2008, the pace of infrastructure development slowed due to constrained debt and equity markets. In some situations, producers built their own gathering and treating systems. But, starting in late 2009, the credit markets revived and infrastructure construction resumed, Dahlstrom says.

“It’s our intent to be a major midstream player in East Texas. That area is different from the Louisiana side in the way that it’s been slower to develop. But with the construction that we have under way right now, we expect to initially be able to move 500 million cubic feet a day.”

In January 2009, ETP announced plans to construct, own and operate the Tiger Pipeline, a 2-Bcf-per-day interstate pipeline. The 42-inch pipeline will begin near Carthage, Texas, and extend 175 miles to Perryville, Louisiana. The company also started construction on another East Texas mainline gathering project with treating at the downstream end, where it plans to deliver into the company’s intrastate pipeline network, which delivers gas into Texas intrastate, Midwest and Northeast markets.

Dahlstrom concludes, “Today, infrastructure development in Haynesville is running neck and neck with production. Volumes are a bit higher than what we initially expected at this stage of the game, but we’re doing everything that we can to keep up with producers in mainline gathering and treating infrastructure. Infrastructure development across the industry is definitely back on track from 2008.”