Good Well Hunting

They’re professional gamblers — wildcatters in a sense.

Natural gas explorers roll the dice every time they drill a well.

“It’s a guess, an educated guess,” said Bill Hanna, president of Hanna Oil & Gas Co. in Fort Smith.

That’s because hitting the target is like pinning the tail on the donkey that is buried under rock and sand a mile deep. At a cost of about $1.5 million to drill and produce a well, that’s a big gamble.

Some pay off, some break even. And some are a bust.

Natural gas explorers based in the Arkansas River Valley have been drilling in the Arkoma Basin — which stretches from McAlester, Okla., to Russellville — since the 1900s. But the recent boom surrounding the Fayetteville Shale Play in central Arkansas has made drilling the Arkoma Basin an afterthought.

And that’s OK with Hanna. That just takes the focus off the Arkoma Basin, which is where his company has been successfully drilling since the 1960s.

But even with the focus shifted to the Fayetteville Shale, the cost and scarcity of equipment and the warm winter last year has slowed the pace of production for some gas companies, forcing them to shift to other means of operation while they wait patiently. Still, the high price of natural gas allows them to find more and more successful prospects in the Basin, a mature area of sandstone that stretches 200 miles long and 50 miles wide.

So, the big companies can have the Shale Play for now. Independent companies like Hanna’s are still playing the game they know best.

The Drill

There are about 100 companies that operate about 4,800 wells in the Arkoma Basin. Hanna, who operates 200 wells in the Basin and has non-operating interest in 1,500 others, said finding a place to drill a well is based on many criteria.

The main one is logging wells, which concerns mapping wells that have already been drilled and studying their production. If his company finds two producing wells that are close together, the best bet is to drill between the two. Companies have geologists on staff to determine where to drill based on maps and logging wells.

Once the decision to drill a certain spot is made, the company’s “land man” must secure a lease on the mineral rights. Whoever owns the mineral rights — the landowner isn’t always the one — goes into agreement for royalties and interest in the drilling. And in order to drill, a company, or group of companies, has to lease a section of land, which is 640 acres.

Leasing mineral rights in the Arkoma Basin costs from $100 to $200 an acre.That could amount to about $64,000 to $128,000 for a section of land, in addition to royalties from the well’s production.

After the lease is secured, drilling can begin. The lease is good as long as the well is producing.

Because many companies are “paper offices,” not many have drilling rigs. So, they have to lease a rig, which can cost from $16,000 to $20,000 a day. And it could take about 30 to 45 days to drill a well — at a cost of about $480,000 to $900,000.

Sounds easy enough, if there’s a drilling rig to be found.

“The business is challenging right now,” said Howard Bagby, president of Bagby Energy LLC in Fort Smith. “Prices are up, equipment is scarce, and rigs are tight.”

Big companies have the cash flow to reserve all the equipment. And with the “gas rush” in central Arkansas, equipment is disappearing, Bagby added.

That’s what Tim Smith, president of Ross Explorations Inc. of Fort Smith, had trouble with last year.

In September 2005, Smith’s company was ready to drill. Prices were up, and production was at full steam. The company had leased a rig for two-years, and as an unwritten policy, usually drilling companies continue to let exploration companies use the rig for as long as they want as long as they keep paying for it.

But the drilling company suddenly wanted a long-term contract, which Smith, being a small company with 60 wells in the Basin and interest in 300-400 more, wasn’t comfortable with. His company lost the rig, leaving him with nine roads built for drilling with no drill.

So Smith bought four used rigs and started Ross Drilling LLC in Fort Smith. He wouldn’t divulge how much they cost, but said he plans to use two of them and lease two others as soon as they’re ready to go.

His largest rig is about 170 feet tall and can drill 16,000 feet, although no one drills that far in the Basin. It takes 40 truckloads to transport the big rig, which would amount to about 1,200 tons.

The rig also has a 22,000-gallon diesel gas tank, which runs the drill for “several days.”

“Our first big [rig] we filled up, I about had a coronary,” Smith said.

Smith said he plans to hire 90 employees in September this year to run the drilling company.

Price Point

Bagby said profits aren’t as good because, when natural gas prices went up, so did cost of services — basic supply and demand. But when prices went back down, services didn’t.

The cost to drill a conventional well in the basin doubled over the last two years from $750,000 to about $1.5 million.

That and the warm winter last year kept a lot of natural gas in reserves.

But while the cost of equipment has gone up over the years, the price of natural gas has fluctuated with the times.

The cost of natural gas per thousand cubic feet (MCF) was about $1.59 in 1980. In 1990, it was $1.71 per MCF. Then in 2000 it hit $3.68. Since then, it has buoyed up and down from $2.95 in 2002 to $7.51 last year. As of Aug. 7, the price on the New York Mercantile Exchange was $6.87 per MCF.

Gas is extremely volatile, Bagby said. During the last week of July, the threat of a hurricane pushed natural gas up to $8.50 per MCF.

“It can be rather hair raising,” Bagby said.

“We’re incredibly price sensitive, and we have no control over it,” Smith said, adding that “billionaire traders” are the ones who set the prices. So the natural gas companies are much like farmers.

“When you have the best crop, prices bottom out,” he said. “When there’s a drought, prices go up.”

Hanna said last year it cost his company $2.50 per MCF to find and produce gas. That was a $4.37 profit as of Aug. 7. Hanna Oil & Gas drilled 25 wells last year and had production out of 18 of them.

Smith said he’s producing about 15,000 MCF of gas a day, which would amount to about $103,050 a day at $6.87 per MCF. And he has about 90,000 acres of undeveloped land waiting to be tapped into.

So, if a company can overcome the cost or scarcity of equipment, the gas prices are high, which is good for them, Bagby said.

Shale Play

Smith, Bagby and Hanna all agreed that they’re taking a “wait-and-see” approach on the Fayetteville Shale.

“Our thought is, let the larger companies exploit the play,” Hanna said. “If it’s real, it will still be here in five years. It will still be here in 20 years.”

Hanna said his company was in the back of the line to drill the Arkoma Basin, but they’re having success nonetheless.

There’s so much hype behind the Fayetteville Shale that big companies have scoured the land, purchasing acres left and right. The price to lease an acre is running from $200 to $500 in some areas.

That’s great for the landowners, bad for the banks. Bagby said farmers are paying off their bank loans, which doesn’t sit well with banks.

Smith said the Shale Play didn’t produce a profitable well in 2004, yet prices were about $200 to $300 an acre. In 2005, there was about a 15 percent success rate drilling the unconventional wells, where the drill goes down and then horizontal into the shale. Finally, for the first half of this year, companies had a 75 percent success rate, he said.

“It’s improving, but the costs are so far away from where all the service cost is,” Smith said. “The cost of what they’re doing is at least a third more [than drilling in the Arkoma Basin].”

It costs about $2 million to $3 million to drill in the Play, almost twice as much as the Basin, which is a conventional way of drilling straight down.

“Our standpoint is if you spend all your money buying leases, you don’t have any money to drill wells,” Smith said.

But the greater the risk, the bigger the payoff.

On average, wells in the Play produce about 1,000 to 1,500 MCF a day, compared to about 50 MCF a day in the Basin. But the Basin is also in a natural decline, and has been for 10 years, said Lawrence Bengal, director of the Arkansas Oil and Gas Commission in El Dorado. The commission is moving its headquarters from El Dorado to Little Rock in September due to the popularity of the Shale Play.

“It’s a normal decline for any gas reserve,” he said. “It still hasn’t come back to what it was, and it may never.”

Smith said gas prices would have to be $7 or higher per MCF in order for it to be economical for small independent companies to drill in the Play.

Bagby said he’s watching the Play out of the corner of his eye. He and investors from Dallas started Bagby Energy in January, but he’s no stranger to the game. Bagby has operated Providence Exploration since 1992.

Along the way, he bought two gas companies in Fort Smith, Hoover Wilson and Freedom Energy. But in 2002, he sold Freedom, along with 80,000 acres, to Dernick Resources Inc. of Dallas.

Bagby Energy basically started from scratch, Bagby said. So far his company has drilled five wells in the Basin this year, with one more to be drilled that he has interest in.

But his interest in the Fayetteville Shale could be more than the others. Bagby has four wells drilled along with other prospects being developed in the Barnett Shale near the Fort Worth (Texas) Basin.

“[The Fayetteville Shale] has got the potential to be a gas prospect that can compete with any domestic play that exists today,” Hanna said. “It’s got that kind of potential.”