Southwestern Energy Co. drills into another 2.2 billion cubic feet of gas reserves almost weekly in the Cotton Valley tight-gas sands about 12,000 feet under the green hills of East Texas. Each of the four rigs that are running in the company's Overton Field hit total depth roughly every 18 to 24 days. Four days later, they spud a new well.

The mostly dry and sweet gas flows into nearby pipelines at an initial rate of about 3.5 million cubic feet equivalent per day. About six months later, the rate settles to approximately 800,000 per day. So far, the company has drilled 52 wells and plans another 87 through 2004. The reserves may produce gas for 30 to 40 years. Current production is about 43 million cubic feet equivalent per day, worth $172,000 a day in a $4 gas market.

Some in the industry would call this exploitation and development program "gas manufacturing," a term for dropping wells into a known prolific formation every so many acres and hitting long-life pay time and time again. It's what Denver-based Evergreen Resources Inc. and its fellow coalbed-methane gas producers do in the Rockies.

Houston-based Southwestern Energy (NYSE: SWN) is applying the manufacturing method to about 17,600 acres of lush terrain south of Tyler in Smith County, where a fifth of the country's commercial rose bushes are produced.

Fina, which is now part of Total SA, discovered Overton Field in 1977 while drilling to Haynesville Lime, below Cotton Valley sand. The well was not a discovery but Fina's explorationists found production from the gassy sand to be economic. That well was completed and 15 more were put online through the 1980s and 1990s. Production grew to as much as 10 million cubic feet per day.

But gas prices and economic forecasts changed, and the exploration program ended. Total production declined to 1.8 million cubic feet equivalent per day by mid-2000, when Southwestern Energy bought Fina's position in the field for $6.1 million.

Southwestern Energy saw a future in expanding its long-life reserves and production, and it launched an exploitation program in the field in the spring of 2001 with one rig.

Fina originally drilled the field to 640-acre spacing. Southwestern Energy now plans to drill it down to 80-acre spacing.

The grassy landscape along Highway 346 is dotted with square patches of red earth-sites that have been prepped for drilling-and with fresh gas-production facilities. The horizon hosts the peaks of two Unit Corp. and two Helmerich & Payne Inc. drilling rigs. The latter are a FlexRig2 and a FlexRig3, the patented new rigs called "flexible" in that they can reach shallow and deep targets.

Southwestern Energy's target in Overton Field is the Taylor series sand. "Geologically speaking, this is the equivalent of the Bossier sands on the other side of the basin," says Alan Stubblefield, vice president of production.

The sand is reached after several thousand feet of drillbit-eating Travis Peak rock. For example, H&P FlexRig #224 recently hit total depth of 11,667 feet for the Wright #1-2 in an Overton Field record of 17 days. The first 7,000 feet of hole were made in five days; the next 2,800 took five more days; the next 1,200, five days; and the remaining 700, two days.

Reducing drilling time has been a key ingredient in Southwestern Energy's profit forecast for the field. While the drilling results are virtually assured, the ultimate profit margin can be narrow or reversed if costs are not controlled. Each completed well is carrying a $1.5-million pricetag currently, driven down from about $2.2 million in 2001. The pretax rate of return on the overall program is 35%, assuming the gas gets $4 per thousand cubic feet on the market and assuming each well will produce 2.2 billion cubic feet equivalent (Bcfe) in its lifetime. An undesirable change in any of these variables can put a profit forecast out of whack.

Each extra day of drilling costs $15,000 to $20,000. The 17-day record is improved from Fina's average of 55 days for each of its 16 wells. Southwestern Energy's 2001 average was 35 days for each of 15 wells. In 2002, the pace improved to 27 days for each of 18 wells. Through May 15 of this year, each of 19 wells was drilled in an average of 24 days.

To complete its 53-well program for 2003, Southwestern Energy needs all four rigs making record hole. At one time earlier this year, it had a fifth rig. Proposed for 2004 are another 53 wells for a total of 155, including the 16 originally on the property. With these, production is expected to peak at 75 million cubic feet per day by the end of 2004. In 2003, total capital invested will be about $90 million, and the company expects to invest a like amount in 2004.

Proved reserves in the field will total some 250 Bcfe at year-end 2004, compared with 7.5 Bcfe when purchased.

For an ExxonMobil, the company-wide impact of a project like this would not be as meaningful. To Southwestern Energy, which had proved reserves at year-end 2002 of 415 Bcfe (90% gas; 77% developed) and 2002 daily average production of 110 million cubic feet equivalent, it is a company-transforming endeavor.

Harold Korell, Southwestern Energy president and chief executive officer, says, "Overton Field has grown into something substantial, and during the next couple of years will be a key project for us, a big part of our strategy. It's a gem and it's an example of our people being creative and using their skill and talent to unlock its value."

The estimated 35% rate of return gives the program a pretax present value index of 1.9, says Richard Lane, executive vice president, E&P. "This basically gives us another whole dollar of margin." Finding costs are about 85 cents per thousand cubic feet. "Those are the kinds of numbers you love to have, and the property delivers that for us," Lane says.

Cost Innovations

Sonny Bryan, manager, drilling, is charged with driving drilling costs down, and has produced a variety of methods:

• Optimizing surface locations. "We've built high-quality surface locations," Bryan says. "We know we're going to be here 20-plus years, so why not build it right the first time?"

• Incentivizing rig crews. "This has been one of our biggest achievements. We've come up with a bonus program to incentivize them to get deeper, cheaper, safely."

The company has paid about $550,000 in bonuses to the crews, and estimates reduced expenses at more than $2.5 million. "We now have a 17-day well. A month earlier, we had an 18-day well. The guys on the rig said, 'We can beat that.' Now, they think they can get down to a 15-day well. They're starting to take ownership of this work."

• Optimizing bottomhole assembly for deviation and bit-life. "It wasn't very typical in East Texas to use a lot of stabilizers, shock subs and a cone-saver. Those things cost a bit more money but can result in savings, longer-term."

• Utilizing advances in bit technology. Vendors are customizing tricone bits, making them tougher, in order to drill through the hard and very abrasive Travis Peak section. "When we started, we would get to the top of Travis Peak with PDC, spin out a bit in the first 50 feet, and get a tricone to finish. We've gone as much as 1,000 feet into the Peak now with PDC. The bit designers are working with us, changing the angle and applying more diamond and abrasive-resistant coating."

The company was using approximately 14 bits per well and has reduced this to eight or nine. "We've had bits last as little as five hours. In West Texas that same bit would last 200 hours."

• Reducing the hole size. "It's very typical in East Texas to drill an 8.5-inch hole. We drill a 7.875-inch hole-probably the optimum size because the bit is designed as 7.875."

• Using advanced rig technology, especially the highly computerized new-design FlexRig. The FlexRig's dayrate is higher ($12,500 versus $10,000 for the Unit rig) but has proved to be competitive overall.

"To break-even for us-on costs for a conventional rig versus a FlexRig-is about three days. In other words, the H&P rig has to drill three days faster than the Unit rig, to justify that dayrate, and on average, it has." The H&P rig now reaches total depth in about 20 days; lately, the Unit crew is down to 22 days.

Innovation is being used post-drilling too. The fracture-stimulation jobs, each costing about $250,000, are done with a hybrid fluid. "We started out with strictly slickwater," says Stubblefield, but the company has preferred the results of slickwater combined with a linear gel.

About 12,000 barrels of fluids are pumped down the wellbore, along with 300,000 pounds of two different sizes of sand-about 25% as much sand as frac jobs in the Cotton Valley required 20 years ago. Surface-treating pressure is about 6,600 psi. Clean-up is about 100 barrels per hour. Within 24 to 36 hours, the gas is heading for sales, and is priced at the Houston Ship Channel.

"One of the challenges we see is to continue to make the tighter portions of the field as economic as our current wells, so we can continue development drilling into 2005 and 2006," Stubblefield says.

Other interesting shows from well results are being evaluated but might not be commercial. "The Cotton Valley Lime is developed by ExxonMobil northeast of our field, and we've tested the Lime in our area. We have a theory on what may be additional potential in our area but we have not realized that yet."

Helping to pay the bills until full production is under way are proceeds from a recent $103-million equity offering. The funds were applied to debt that will be re-incurred during the course of the exploitation program.

Jeff Mobley, E&P analyst for Raymond James & Associates, says, "Southwestern's development-drilling program in the Overton Field is a low-cost, low-risk, high-rate-of-return project that will primarily fuel the company's growth through 2004." At press time, he had a Strong Buy recommendation on the company's stock and a target price of $18 per share.

Mobley expects company-wide production growth of about 4% in 2003, not adjusted for asset sales, and 20% in 2004 as a result of the ramp-up in drilling in Overton Field. "We view the stock as a solid play on robust North American gas markets and expect to see continued strong performance from the company during the next several quarters."

Korell says, "Identifying Overton Field as an acquisition candidate was an important part of what we did there. Understanding the down-spacing opportunity was probably the next key."

Lane concludes, "The property was very underdeveloped when we purchased it. Once we understood the geology and the engineering, we had to apply the correct technologies to the field. Then, we had to drive the costs down, and continually improve on well performance. What we have here is a very high-margin, great economic project."

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