East Texas is a gas wunderkind. The time-honored basin was once synonymous with the old oil patch, home to the great East Texas Field and its ripe, black-oil reservoirs in the prolific Upper Cretaceous.

But it's a new day, and gas is the primary target now. These targets are older: mainly Jurassic Cotton Valley and Bossier reservoirs, with some Lower Cretaceous James Lime, Pettet and Travis Peak thrown in. Popular plays now range from straightforward tight-gas targets to tricky, high-temperature, high-pressure reservoirs. Operators wield an abundance of technologies such as staged fracture treatments in horizontal openhole laterals, microseismic frac monitoring, and oil-based-mud drilling in deep, hot rocks to extract abundant volumes of gas.

East Texas now ranks as one of the nation's formidable gas-producing basins: it contributes 3.7 billion cubic feet (Bcf) per day to domestic supply. And bountiful resources remain. Operators continue to access the region's opportunities, drawn to its plethora of reservoirs, solid economics, and excellent infrastructure connection to markets.

Horizontal Breakthroughs

The most exhilarating news out of East Texas in recent months has been the rousing success of several horizontal wells drilled by Oklahoma City-based Devon Energy Corp.

Devon has a vibrant program in the region, centered on its Carthage area in Panola County and Groesbeck area in Freestone, Limestone and Robertson counties. It holds 120,000 net acres at Carthage and 142,000 net acres in Groesbeck. Devon's net production from the two is more than 280 million cubic feet equivalent per day and growing.

"We have made some big horizontal wells in East Texas, several in the Bossier and one in the Cotton Valley," says David Sambrooks, Devon vice president and general manager, southern division.

That statement is a bit restrained: Devon's Crenshaw #14H, in Nan-Su-Gail Field in Freestone County, is extraordinary. The horizontal well was gauged at an initial rate of 32 million cubic feet per day and has produced an astonishing 1.3 Bcf during its first two months online.

Going back to the beginning, the first spot Devon selected for horizontal drilling was Groesbeck, an area that includes Nan-Su-Gail, Dew, Oaks, Personville and Bald Prairie fields in the Freestone Trend on the west side of the East Texas Basin. These produce from vertical wells in the shale-dominated Bossier section that occurs at about 12,000 feet along the regional Cotton Valley shelf.

The issue was that rising well and service costs were squeezing margins in the tight-gas reservoir. Vertical wells were still economic, but returns were declining. The decision to go horizontal was made after some serious study of the East Texas region and its reservoirs.

The horizontal campaign was launched in Nan-Su-Gail Field in mid-2005 when Devon drilled a grassroots well with a horizontal lateral and stimulated it openhole. Results were heartening: "We unlocked the economics. We found that we could get several times the production and reserves of a vertical well for less than that multiple of cost."

Fracturing is crucial to success in these wells. The Bossier horizontals cannot simply rely on the intersection of natural fractures to produce at commercial rates. As in vertical wells in this reservoir, horizontals must be stimulated.

And, more is better. Devon developed a technique of fracturing each lateral multiple times at regular spacings. "Essentially, for each frac, we're getting rates and reserves close to a vertical well, but we don't have to spend as much as we would to drill individual wells," says Sambrooks. Information to date indicates a strong correlation between the number of fracs and production. "The key is how many fracs we can get in a well."

These are amazing stimulations. Devon fractured its first horizontal four times; on its Crenshaw well, it achieved a seven-stage frac along a 3,300-foot lateral.

The scale of such a completion is hard to fathom. A seven-stage frac requires on the order of 2 million pounds of sand and 75,000 barrels of fluid. The stimulations are evenly spaced along a lateral to touch as much reservoir as possible. Devon uses a hydraulic packer system with frac ports spaced 400 to 500 feet apart.

The back-to-back jobs are pumped for 48 straight hours. Logistics are incredibly complex, with crew changes throughout the job, huge reserve pits for fluids, and redundant pump trucks on location.

At present, Devon is drilling its sixth horizontal well in Nan-Su-Gail, and on each well, it is pushing the laterals to greater lengths and adding frac stages. It has moved exclusively to horizontal wells there.

During 2007, the company plans to expand its horizontal program to several other Bossier fields in the Groesbeck area. Meanwhile, it continues to drill vertical wells in the Bossier where economics support that approach. "Each field is different, and we're going to see where the horizontal applications work the best. I anticipate that we will drill more and more horizontal wells throughout this area."

Cotton Valley Wonder

Devon has another renowned horizontal well in East Texas, this one in the Cotton Valley sand. The company's Haygood #11H, drilled in the great old Carthage Field, is a breathtaking success. Using the horizontal drilling and completion techniques it developed in the Bossier play to the west, Devon drilled a 2,500-foot lateral into the Cotton Valley #5 sand, found at about 9,300 feet, and fractured it five times. During the Haygood's first month on production, it produced 9 million cubic feet a day. Its initial potential was 15 million.

Notwithstanding the success of this first horizontal Cotton Valley well, the tight-sand reservoir poses some different issues than those seen in the Bossier. The Upper Cotton Valley section reaches more than 1,200 feet in thickness on the crest of Carthage, and contains up to 10 productive reservoirs separated by shales. The long vertical column is obviously a concern, because laterals have to be placed into amenable zones to work effectively, and fracs need to propagate vertically.

"We have seen good connection of the vertical intervals with the frac treatments that we made in the Haygood," says Sambrooks. "It's very early, but we're encouraged that the drainage might be effective across intervals in the Cotton Valley."

The initial well was also drilled in an area with a thinner Davis pay section than is present in the heart of the field. Perhaps Cotton Valley horizontals will turn out to be particularly suited to thin-pay areas, and may thus open up new regions for production.

Devon is not ready to switch its extensive Cotton Valley drilling program to horizontals just yet. Of the six rigs it runs in the Carthage area, it will devote one to horizontal wells this year. "Going forward, we will drill both vertical and horizontal Cotton Valley wells," he says. "Vertical wells are very economic in Carthage, and they make sense in a lot of areas. Our work on the horizontals will focus on determining how big the application is and where it will be of most benefit."

For Devon, the potential could be substantial. The company estimates it has up to 70 horizontal locations in Carthage and 200 more in Groesbeck.

To date, Devon has drilled 17 horizontal wells across its East Texas holdings. In addition to Bossier and Cotton Valley horizontals, it has laterals in some depleted conventional reservoirs such as the Travis Peak and Pettet. In the latter application, horizontal wellbores allow the company to access bigger pay sections and produce at increased rates from low-pressure reservoirs.

"We're obviously excited about our early horizontal wells. But we expect a variety of results, just as with vertical wells. Finding the right applications for the technology is still going to be required."

Exceptional Technology

Devon's horizontal wells that are fractured multiple times in open holes offer a new option to East Texas operators, says Harry Chernoff, Pathfinder Capital Advisors, located in Great Falls, Virginia.

As often happens, Fort Worth-based XTO Energy Inc. has developed a similar approach. That company has drilled a very strong horizontal Cotton Valley Lime well. Its Gail King #23H, in Bear Grass Field in Leon County, has been completed in one-third of a 2,500-foot lateral for 7.7 million cubic feet per day. When fully completed, the initial rate should be around 20 million a day, XTO reports.

Excitement is spreading across the region because excellent horizontal wells have now been drilled in different zones and in different fields, ranging from the Freestone Trend to Carthage Field. "It's the common completion technique that appears to be the key," says Chernoff. "More gas is coming out, and it's coming out more cost-effectively."

If, based on results known to date, a company can increase reserves and production four to 5.5 times for three times the cost per well, it's a huge gain in production rates, total recoveries, and finding and development (F&D) costs. For example, says Chernoff, a Carthage horizontal should be able to recover 4- to 6 Bcf at F&D costs of around $1 per thousand cubic feet of gas.

Of course, there is a tradeoff in spacing horizontal versus vertical wells. A Carthage horizontal well drilled on 80- to 100-acre spacing would replace two to 2.5 vertical wells at 40-acre density. Per-acre recoveries could double nonetheless, assuming reserve gains of four to 5.5 times that of vertical completions.

"And these results are for the first horizontal zone," he says. "It's too early to tell, but there's a good chance multiple productive zones in the Cotton Valley could be tapped by horizontal recompletions via the same wellbore." Per-acre recoveries would rise and F&D costs would drop even farther if multiple laterals prove successful.

In the Freestone Trend, where XTO's Gail King #23H and Devon's Crenshaw #14H appear to be so successful, average recoveries of 10 Bcf or more and F&D costs well south of $1 per thousand cubic feet look likely.

Several independents hold significant positions in East Texas and could enjoy consequential benefits from a horizontal drilling boom, says Chernoff. The Freestone Trend and Overton Field, in the western Cotton Valley, tend to be controlled by major producers and the largest independents, such as Devon, XTO, EnCana Corp., Anadarko Petroleum and Southwestern Energy.

Farther east, in the Greater Carthage area near the Texas-Louisiana border and into North Louisiana, there are many of the same names plus a much larger number of smaller players, including Penn Virginia Corp., Comstock Resources, Goodrich Petroleum, GMX Resources, Exco Resources, PetroQuest Energy and Petrohawk Energy.

In terms of acreage and reserve exposure per dollar of market capitalization, these smaller independents offer the greatest potential in a general shift toward horizontal drilling. "We're not yet at the point of saying that the very strong initial production rates will translate into the hoped-for total recoveries, let alone total recoveries across the entire Cotton Valley, but it looks extremely promising," Chernoff says.

"If results hold up, this will be a huge play, especially for smaller, more concentrated independents."

Cotton Valley Standard

Notwithstanding the euphoria surrounding horizontals, plenty of companies continue to drill Cotton Valley vertical wells throughout East Texas. Thousands of holes have tapped this prolific trend, which took off in the late 1970s. Initially, development was spurred by the inclusion of the low-permeability formation in federal "tight gas" classifications. In ensuing years, improvements in drilling and fracturing technologies, along with higher gas prices, have kept the Cotton Valley persistently active.

One producer that has been enjoying success in the formation is Cabot Oil & Gas Corp. Recently, the Houston-based company decided to alter its risk profile. It sold its offshore and South Louisiana assets and increased its emphasis on low-risk drilling in the Gulf Coast, Rocky Mountains, Appalachia and Canada.

"We're putting a lot of emphasis on development projects," says Mike Walen, Cabot senior vice president and chief operating officer. "East Texas fits nicely into that strategy."

Two and a half years ago, Cabot generated its Minden prospect in Rusk County. It obtained an initial foothold of 3,500 acres and drilled a 10,800-foot Cotton Valley sand discovery, Harrell #1, in 2005. The well came in above expectations, and Cabot expanded its position to more than 10,000 acres. "It's a stratigraphic play, but there are definitely sweet spots, and we're in one," he says. To date, Cabot has drilled and completed 25 wells at Minden and grown its production from zero to 24 million cubic feet equivalent of gas per day.

Early on, the company spaced its wells to prove up its acreage and built field infrastructure to tie in those wells. Now, it is beginning an infill-drilling program at 40-acre density. Throughout this year, it will run two to three rigs at Minden. "We will drill and complete 18 to 20 wells in the field in 2007," says Walen. "We think that we have more than 200 remaining locations, and we plan to keep drilling at a steady pace."

Cabot's dry-hole costs are $1- to $1.2 million, and completion adds another $1 million per well, depending on the number of fracs. The play is predicated on keeping costs as low as possible and getting effective frac stimulations. Drilling times, which have improved dramatically throughout the play thanks to bits and hydraulics, are currently between 12 and 15 days per well.

The company typically puts two to three slickwater fracs on each wellbore, across some 1,200 feet of section in the Upper and Lower Cotton Valley and Taylor intervals. A normal job contains around 250,000 gallons of fluid and 160,000 pounds of sand.

"Microseismic frac monitoring has helped us fine-tune our completions," says George Taylor, operations manager. Fracs are run back-to-back, and all three frac stages are completed within a week. Cabot, always looking for ways to trim costs, is currently working on eliminating one of the frac stages and also eliminating the use of composite bridge plugs between stages.

"Our biggest challenge right now is to keep costs under control," says Walen. "We fight to keep costs flat or on a downward path. Our people are very good at getting max rate out of the wells and also at keeping finding costs attractive."

Usually, a well will start off making between 1.5- and 3.3 million cubic feet per day. Initial estimates called for ultimate recoveries of 1.2 Bcf equivalent (Bcfe) apiece, but Cabot's wells are behaving quite strongly. Now it is looking at recoveries of 1.4 Bcfe, and some wells as high as 1.8 Bcfe.

In addition to its Minden activities, Cabot is pursuing James Lime and Pettet prospects in Shelby County and other Cotton Valley projects in North Louisiana. In its Shelby County area, which it calls County Line, Cabot recently completed its first horizontal well in the Pettet. The 11,387-foot A.M. Scott #1 flowed 3.3 million cubic feet a day from a 3,400-foot lateral. Cabot, which holds a 100% interest in the Scott, controls 13,200 net acres and has 50 to 80 horizontal locations in the James and Pettet reservoirs at County Line.

This year it plans to drill 30 to 35 wells in East Texas and North Louisiana. Two new-build rigs have just been added to its program, one in Minden and one in Shelby County. Out of its company-wide budget of $435 million, it will spend $70 million in East Texas in 2007.

East Texas has proved to Cabot to be a good, reliable place to work. "Our results are much stronger than we anticipated going into it. We're going to continue to expand our program there," Walen says.

Seasoned Operator

Some companies may be freshly discovering the attractions of East Texas, while others have been enjoying success there for years. Comstock Resources Inc. has worked in East Texas since 1991, says Jay Allison, chairman, president and chief executive. "When we started the company in 1988, we targeted basins that had been profitable for a long time. Vertical wells in the Hosston/Travis Peak and Cotton Valley are predictable, have high success rates and have been making money for decades."

Frisco, Texas-based Comstock made its first acquisition of acreage and producing wells in East Texas from a private company. In 1995, it bought Sonat's assets in East Texas and North Louisiana, a move that doubled its size. The early entry gave it a favorable cost basis, especially compared with today's prices.

"At the time we bought our initial interests, commercial banks would only loan money for producing reserves and property values were based primarily on proved developed reserves only. Our acquisitions during that time frame included probable and possible reserves, but we just paid for proved developed," Allison says.

In March 2005, Comstock added further to its holdings when it acquired assets from EnSight Energy Partners for $190 million. The package carried 120 Bcfe of reserves, half of which were in East Texas and North Louisiana.

Today, the company holds 300,000 acres and owns interests in 27 fields-25 of which it operates-in East Texas and North Louisiana. During the past 15 years, it has drilled more than 300 wells in the region. It runs eight rigs at present, and plans to keep the rigs under contract at that level throughout much of this year. In 2006, it spent $150 million of its $215-million capex budget in the region, and drilled 90 wells in 15 separate fields.

This year, Comstock will drill 110 wells in East Texas and North Louisiana. In keeping with the recent surge of interest in horizontal wells, it plans its first such test during the first half of 2007. "Several years ago, Cotton Valley wells became a lot more profitable when the industry adopted water fracs," says Allison. "Now the first horizontal wells look like they could materially increase the economics of Cotton Valley wells in East Texas."

Its typical vertical Cotton Valley well costs $2 million to drill and complete and nets a Bcfe of reserves.

Most of its wells are spaced on 80 acres, and only a handful of areas are downspaced to 40s or 20s. Although its 300,000 acres could potentially support thousands of wells, the company prefers to be conservative in its estimates of drilling inventory. "Right now, having been in this area for 15 years, we're comfortable that we have more than 400 operated drillsites."

All signs are that East Texas will continue to play a strong role in Comstock's future. "We're in East Texas because it's as predictable as any area can be in this business."

Another New Face

Dorado Exploration, based in Dallas, is a young company headed by Don Schmidt, president and chief executive. The private entity was incorporated in January 2005, and capitalized with oil and gas properties the principals had owned previously.

Dorado, backed by private equity and mezzanine financing, plans to go public this year. In addition to East Texas, the firm operates in Louisiana and Mississippi. In East Texas, it also has a 100,000-acre area of mutual interest with Ramshorn Investments Inc., a wholly owned subsidiary of Nabors Industries Ltd.

The Cotton Valley was a natural choice for the company for its early growth. Schmidt's partner had worked the area for many years, and both were familiar with the tight-sand reservoir.

First challenge: acquiring acreage. "Acreage in East Texas has always been tough to come by, any way you slice it," says Schmidt. "There's lots of competition, from mom-and-pop outfits to the big boys."

Dorado's land team, which includes in-house and contract staff, has been able to take leases on the ground in Panola County. Some three years ago, a flurry of leasing hit this area, so now leases are lapsing due to lack of development during the primary term. That said, East Texas lessors are savvy. If someone owns mineral rights that were leased at rates below what acreage fetches today, and they didn't get a well drilled, they can be fairly demanding. Some are motivated by high per-acre prices, others want well commitments, and some want both.

Dorado uses the instruments dear to a small independent: a personal approach and a willingness to make well commitments. "We've been able to add 500 to 600 acres a month, which is about what we need to stay ahead of the drilling rig," he says.

During 2006, the company drilled six 10,500-foot Cotton Valley wells in Panola County on 5,000 acres of leasehold. This year, it plans to add a second rig and increase its leasing activity.

Although any Cotton Valley operator that hasn't thought about horizontal wells lately has either been dead or sleeping, Dorado is not yet ready to make that leap. "Our vertical wells are quite economic, and we don't think we're quite stout enough to bite off on horizontal drilling. But it sure is on the drawing board for us."

Naturally, hurdles too numerous to mention face a small start-up company trying to grow in a bustling yet long-established play. Dorado's two looming issues are personnel and well costs. "It's impossible to get experienced landmen. And costs are a good 20% above what they were when we started," says Schmidt.

But, necessity breeds innovation. Dorado has trained freshly minted law-school graduates as landmen and focused closely on hauling in costs. For instance, the company pre-purchases its pipe in bulk, which saves it more than 20% on steel.

"The Cotton Valley is a smart place to put money, and that's the philosophy we follow."

Deep Bossier

Another reservoir making headlines in East Texas is far different from the Cotton Valley, or anything else in the basin. It's not even that similar to its cousin, the Bossier in the shelf play in the Freestone Trend.

The Deep Bossier might be in its early stages, but it is firmly in the sights of such megafirms as ConocoPhillips, EnCana Corp. and Chesapeake Energy.

One company that has been in the play since its genesis is Gastar Exploration Ltd., says J. Russell Porter, chairman, president and chief executive. "The Deep Bossier is our core focus area. We are dealing with net reserve potential to Gastar of more than half a trillion cubic feet of gas."

Houston-based Gastar entered the play in late 2000 when it acquired a 14,000-acre position. Anadarko Petroleum, one of the major operators in the Bossier shelf fields, proposed a 21,000-foot well in eastern Leon County that included some of Gastar's acreage. The concept was to investigate whether the Bossier section expanded into a series of sands off the shelf edge.

Indeed, it did. The Belin Trust #A-1 encountered some 800 feet of sands between 18,000 feet and total depth, and was the first modern well to prove the presence of a greatly expanded Bossier section. Both high flows of water and moderate flows of gas were recorded. Although the well was eventually abandoned due to mechanical problems, it altered industry perceptions.

"Conventional thinking had been that the area was too far away from the Bossier sand sources to have good reservoir characteristics and thick sands," says Porter. The results encouraged Gastar to grow its position to 55,000 acres in southwestern Leon and southeastern Robertson counties.

The company concentrated on Hilltop, on the border of the two counties, an area that contained a deep-seated structure. The Hilltop feature had uplifted the deepest Bossier sands and influenced deposition of other sequences of Bossier sands.

In late 2003, Gastar put together funds and drilled a 20,050-foot discovery at its Fridkin-Kaufman #1. The wildcat found tight sands in the Lower Bossier, but encountered three zones with 136 feet of net pay in the Middle Bossier. The well was completed for an initial potential of 15 million cubic feet per day.

That kicked off the play for Gastar. It drilled another six wells, targeting the expanded Bossier section. The Bossier in the Hilltop area is greatly overpressured, bottomhole temperatures are colossal, and the wells are challenging and complex. Initially, even reaching total depth posed problems. "We have focused on well design and well integrity, and very early in the play we went to oil-based muds for the deeper section."

In 2006, after drilling seven Deep Bossier tests, Gastar brought Oklahoma City-based Chesapeake into the play. Chesapeake acquired a 33% interest in the Hilltop project, and the two companies formed a 13-county area of mutual interest. As part of the transaction, Chesapeake invested in Gastar through the purchase of 16.5% of Gastar's common stock, a position it has maintained in a recent Gastar equity placement.

At present, Gastar is drilling the 11th, 12th and 13th wells on its properties, after recently adding a third rig to its drilling program.

Gastar's wells contain from 40 to more than 200 feet of net pay in the Middle and Lower Bossier sections. For the most part, the two targets are not coincident, but sometimes do overlay each other. Both reservoir intervals have to be stimulated with large frac jobs and special proppants.

Lower Bossier wells reach 19,000 to 19,500 feet and cost approximately $12 million apiece to drill and complete. Initial rates can be from 6- to more than 10 million cubic feet per day. Favorable structural position appears to be crucial for productivity, as early hydrocarbon migration into the reservoirs apparently preserved porosities.

Middle Bossier wells in the Hilltop area usually reach total depth between 17,500 and 18,000 feet. Wells in this interval with three-zone completions run $9 million each, and initial production rates average 8 million a day. Explorers look for structural lows where maximum sand thickness was accumulated. "We try to find as much sand as we can, and within the sands are intervals that can contain phenomenal porosities," says Porter. At present, Gastar and Chesapeake are shooting a 250-square-mile 3-D seismic survey, which will be very helpful in selecting locations in this stratigraphic play.

To date, more than 50 wells have been drilled across the entire deep play, mainly into Middle Bossier reservoirs, and initial production rates have been as high as 30 million per day. The average well, with an initial rate of 10 million per day, will produce around 8 Bcfe. Some wells are spectacular and will make 15- to 20 Bcfe each.

Gastar has 159 potential Middle Bossier and 20 Lower Bossier locations on 160-acre spacing on its Hilltop acreage. Naturally, being in East Texas, its properties also have shallow potential in the Knowles Limestone, Travis Peak, Pettet and Glen Rose.

But the Deep Bossier has been and will remain its focus. This year, Gastar plans to drill nine to 10 wells at Hilltop, and late in the year may add another rig or two to the area.

"We believe in the play and we've obtained financing sufficient to allow Gastar to continue an aggressive exploration and development program in it," he says. "We have a lot of leverage to success, but as a small public company there is a spotlight on all our activities. Every completion in every well is important."

Robertson County

A private firm that has also staked its future on the Deep Bossier is Houston-based Leor Energy LP. The company began acquiring acreage in the play in 2003, about the time Burlington Resources Inc. (now part of ConocoPhillips) launched an effort in the unconventional reservoir.

Guma Aguiar, Leor vice chairman and chief executive, was taken with a prospect idea pitched to him by a geologist. John Amoruso believed thick Bossier sands would be present in eastern Robertson County, and that's where Leor concentrated.

Amoruso was correct, and Burlington soon justified his premise with amazing results. By early 2005, Burlington had drilled seven wells in the Deep Bossier in Savell Field in eastern Robertson County, and those wells were making 45 million cubic feet of gas per day. ConocoPhillips stepped right into the program after it acquired Burlington in late 2005. At present, some 20 ConocoPhillips-operated wells in Savell Field are making 180 million per day.

Leor's acreage was fortuitously smack in the middle of the red-hot play, which operators were beginning to realize covered an impressive area. Calgary-based EnCana Corp. already held a substantial position in the broader Deep Bossier trend, but it was decidedly interested in acreage in Leor's area. The two firms struck a deal: in May 2005, EnCana farmed into a 30% interest in Leor's assets and took over operations. In mid-2006, EnCana added another 20% interest, in exchange for $242 million and 4,000 adjacent net acres.

Today, Leor holds interests in some 50,000 acres in Robertson County, and in an additional 100,000 acres outside that county in the larger Bossier trend.

During the past six months, Leor and EnCana have grown production from their joint properties from 7- to 100 million cubic feet per day. The companies currently have a dozen wells capable of production in Robertson County and have four rigs drilling there. Shortly, they expect to add two to three additional rigs. In addition, the partners have a rig at work on their Houston project in Nacogdoches County, an exploratory project in the eastern side of the Deep Bossier trend.

"We're very early in our play, but we are seeing very prolific wells," says Greg Scott, executive vice president and chief operating officer. "We are quite optimistic about production capabilities down the road as well as our value creation."

Leor estimates the average well in its Robertson County area will produce around 10 Bcfe. Typically, its wells range from 16,000 to 19,000 feet in depth and take 65 to 90 days each to drill. Costs are from $8- to $10 million, although wells that reach the deeper end of the range and have several stimulations can be more expensive. Fracture stimulations are done through 5-inch casing with no tubing. Some wells are completed in as many as five different sands; others produce from a single zone.

Initially, the partners drilled on wide spacing to evaluate as much of their holdings as possible. "The results were quite impressive over a broad area, and we have a lot of running room in our acreage position," says Aguiar.

"It's an extremely exciting story. We are very fortunate to be in the position we are in," he says.

Many operators share that sentiment. East Texas is humming with landmen and alive with rigs. Operators of all descriptions are drilling vertical and horizontal wells in formations up and down the strat column. Now's a magnificent time to work this remarkable basin.

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