NGI The Weekly Gas Market Report / NGI All News Access

Barnett Shale Boom Days Far From Over

Last week's announcement by Chesapeake Energy Corp. that it would pay multiple sellers a combined $932 million for 67,000 net acres of Barnett Shale leasehold turned up the heat on the hottest gas play in the country. Consolidation has clearly come to the 13-county area around Fort Worth, where costs have skyrocketed to as much as $5,000/acre from just $50 two years ago. But the players keep coming because in the Barnett you make your money through the drillbit, and even a high ticket price can be dwarfed by future profits.

Chesapeake is picking up 39,000 net acres in Johnson and Tarrant counties, TX, 30 MMcfe/d of current production and $55 million worth of midstream assets in an $845 million cash deal with Four Sevens Oil Co. Ltd. and its partner Sinclair Oil Corp. Chesapeake also is spending $87 million to buy 28,000 net acres of leasehold in the same area from other sellers. In the Four Sevens/Sinclair deal the company said it is getting 160 Bcfe of proved reserves for $275 million for a cost of $1.72/Mcfe. Probable and possible reserves total 710 Bcfe at a cost of $515 million. Chesapeake's all-in cost to develop the 870 Bcfe of 3P reserves is $2.32/Mcfe, including $1.2 billion of anticipated future development costs, it said.

The Barnett Shale of North Texas is one of the hottest natural gas plays going (see NGI, Jan 17). It could possibly be the largest natural gas find in the United States, some leading energy experts believe. The play's popularity today can be greatly attributed to well frac-ing advances that began in 1997 and continue today. And if there's some acreage available, they recommend buying it as soon as possible.

Speaking at Platts' Shale Gas Developer conference in Houston last week, oil and gas veterans who work in the Barnett agreed that the North Texas shale is the place to be for unconventional gas. Drilling is no longer confined to the prairies and rural farmlands of Texas; Barnett exploration is now taking place below golf courses, in the backyards of ritzy housing developments and near skyscrapers. And no wonder: the region was producing about 1 Bcf/d two years ago; today, it's around 2.5 Bcf/d.

"Barnett is the king of resource rock and shale plays," said Mark Whitley, senior vice president of Range Resources. Whitley should know. He worked for the original Barnett kingpin Mitchell Energy and Development Corp., which current kingpin Devon Energy bought in 2001 (see NGI, Aug. 21, 2001). "There is a tremendous resource there, and we have huge resources to work on." Not all of the Barnett shale is the same, he said. "The number of wells that can be drilled is mind boggling. How long will it last? I will retire on this shale, but I also think the next generation could retire on this play.

"There are no longer just two or three companies involved," he said. "Some of the biggest independents, some of the biggest producers are now operating there."

Phil DeLozier, vice president of business development for EOG Resources Inc., said EOG estimates Barnett's total reserve potential is between 500 Tcf and 1,000 Tcf. EOG is one of the top leaseholders. "This is our playground." But he said EOG is always looking for more onshore gas resources. "I can't tell you how many times we get calls about the 'next' Barnett."

John White, an energy analyst with Natexis Bleichroeder Inc., said the Barnett "continues to show strong economics even using a $5/MMBtu gas price assumption." The main reason is "predictability, due to the almost zero dry hole risk and very low operational risk. In a gas price environment where operators began to prioritize drilling prospects between conventional prospects and Barnett shale wells, we believe the core area of the Barnett shale will remain a high priority for near-term drilling activity."

During an analyst call last week, Chesapeake CEO Aubrey McClendon said the Barnett Shale currently offers the best margins in the business. The company maintains there is "virtually no drilling risk" in the area where it's operating. Drilling costs in the Barnett also are far more reasonable than those experienced to date by Chesapeake in the Fayetteville Shale, where Chesapeake is just getting started with its drilling program.

Oklahoma City-based Chesapeake is the second largest U.S. independent gas producer behind Devon Energy, which is the largest producer in the Barnett Shale. XTO Energy is the No. 2 producer and Chesapeake is No. 3 in the Barnett. Chesapeake said it expects to grow production on its recently acquired leasehold from 30 MMcfe/d to 45-50 MMcfe/d by year-end and to 80-100 MMcfe/d by year-end 2007. Chesapeake's current pro forma average daily net production in the Barnett is about 140 MMcfe. This is expected to reach 200 MMcfe net and 250 MMcfe net by year-end 2006 and 2007, respectively.

From Four Sevens/Sinclair, Chesapeake is getting 26,000 net acres in the Tier 1 portion of the Barnett Shale. Chesapeake describes this as a high quality reservoir area in the horizontal drilling fairway with high gas-in-place levels and optimal thermal maturity and shale thickness. Here, just 19 wells are producing 30 MMcfe/d. Chesapeake said its large contiguous acreage position will allow for optimal placement of horizontal wells and associated gathering systems. The additional 28,000 net acres being acquired from other sellers are also mainly in the Tier 1 sweet spot. There are no reserves booked yet, but the company plans to drill 400 net horizontal wells to develop 650 Bcfe of unproved reserves at an all-in acquisition cost of less than $1.80/Mcfe. Chesapeake said a 3-D seismic survey is under way and the first drilling is expected to begin later this summer. Chesapeake plans to finance the deal with a balance of senior notes and preferred equity in the near future. The transactions are expected to close by July 1.

Biggest in Texas

Based on 2004 statistics, the Texas Railroad Commission reported the Barnett Shale gas field is the state's largest producer (see NGI, Feb. 28, 2005). Last month, Oklahoma City-based Devon announced a deal to buy the properties of Chief Holdings LLC (Chief Oil & Gas) in a $2.2 billion deal that expands the company's Barnett Shale position to 720,000 net acres (see NGI, May 8). Next, Fort Worth-based XTO Energy Inc. said it would buy privately held Barnett producer Peak Energy Resources Inc. for $105 million of its stock (see NGI, June 5). The deal grows XTO's reserves and leasehold acreage in the Tier 1 and Tier 2 regions of the Barnett, mainly in Hood, Parker and eastern Erath counties, Texas.

XTO had been focused on East Texas when the Barnett Shale caught its attention. The company's first entry into the Barnett came in 2004 with an acquisition from Four Sevens. The deal was for 18 MMcf/d of production and about 11,000 acres," recalled Vaughn Vennerburg, XTO senior executive vice president. Setting out to accumulate 200,000-250,000 Barnett acres, XTO launched an active lease program. "People were just pouring through the doors," Vennerburg said. "Everybody had their one or two acres and they wanted to give a lease to XTO or somebody else in the play."

Next, XTO struck a deal to buy Antero Resources for $685 million in cash, stock and warrants (see NGI, Jan. 17, 2005). The deal to acquire Peak Energy followed, which takes XTO up to about 200,000 net acres of leasehold in the Barnett. "We have a very active lease program going on and I think we'll get to 250,000, probably within the next year or so," Vennerburg said. About half of XTO's acreage is in the core area of the Barnett where the company is considering going to 20-acre spacing, which would create the possibility for 4,000 wells. "That is a decade of drilling for XTO."

And that's what analysts who follow these companies like to hear, according to David Marcell, Tristone Capital managing director. "To be in this game you've got to be able to afford the inventory. You have to have it," he said. "The stock market's telling people that they don't like the reinvestment risk. They want management to have something far in the future that's known. That's where a shale play comes in; it's there forever."

And so the consolidators consolidate and build their inventories of drilling opportunities. "Consolidation has always been a factor in the Barnett Shale, and it will continue to be and will probably accelerate in the future," said Westside Energy CEO Jimmy Wright. "The success of all these acquisitions is not going to come through the buy price as much as through the drillbit. As you're seeing... a substantial amount of the value in the acquisitions with the prices the way they are currently is attributable to PUDs, or proved undeveloped or even potential [reserves]. The drillbit is going to drive the value for the shareholders, not just the acquisition."

Early to the Play

But while independent titans Devon, XTO and Chesapeake are consolidators in the Barnett and other plays, there wouldn't be much for them to buy up were it not for companies like Hallwood Petroleum LLC.

"Five of us started up in 2002," recalled William Marble, Hallwood vice president of land and engineering. "We took $6 million of investor money. We went to Johnson County [TX] where there was nothing but 67 dry holes, where there are technical papers written by experts on all the reasons you cannot drill a Barnett Shale well in Johnson County. There were six uneconomic tests and failures in the Barnett in Johnson County. Our first well was a discovery. Our third well was a dry hole; it was our first and only well chosen by a geologist. We went on and we changed frac design on virtually every single well. We drilled about 40 vertical wells, 31 horizontals. We built our own infrastructure, and we turned that $6 million into $540 million in 43 months."

So far, lower gas prices are not having much effect on the Barnett, and in fact, may fuel more merger and acquisition activity. Those considering acquiring should not be too concerned about front-month Nymex prices, said Marcell. "Front months are important, but not if you're buying." Look at the out months on the Nymex strip and prices have remained high and relatively flat, he said.

Natexis ran several versions of its Barnett shale economics model. After examining the data disclosed by active operators in the Barnett, Natexis' primary assumptions found that completed well costs were about $1.8 million, lease operating costs were $1.30/Mcfe, and a basis differential to Henry Hub was $1/MMBtu.

With 2 Bcfe of reserves at an average production rate of 1.2/MMcf/d in year one, the "play is still showing strong returns under the pricing scenarios of 1) $6.00/MMBtu flat, 2) $5.00/MMBtu for the first six months and $6.00 flat thereafter; and 3) $5.00/MMBtu flat," White said.

But there are challenges, said Mackie McCrea, senior vice president of commercial development for pipeline company Energy Transfer Partners LP.

"The biggest challenge is getting enough pipe in the ground soon enough," McCrea said last week. "We move about 5 Bcf/d, mostly in Texas. About 80 to 85% of our capital is spent on facilitating movement out of the Barnett."

Energy Transfer has made a lot of "mistakes" on its bets for the pipeline in the Barnett. "When we decided to build a 36-inch pipe, we made a mistake. It should have been a 42-inch pipe. A 24-inch pipe should be a 36. One of the biggest challenges in the Barnett shale is capacity...We are just trying to stay ahead of the curve," McCrea said.

"From our standpoint, it was not long ago when there was about 1 Bcf/d coming out of the Barnett," said McCrea. "By this time next year, it will be 2.5 Bcf/d. In two to three, four years, we don't know. It's unbelievable what's happened in the Barnett, where we are headed."

Because some of Barnett's most prolific gas shale resources lie within the city of Fort Worth, EOG's DeLozier said producers are finding land issues to be a "really tough issue." For the next few years, he said split-estate issues may dominate within the Barnett production region. In a split estate, a landowner may own the "top" of the property but may not hold title to the minerals in the ground. In those circumstances, some drillers have been working under golf courses and within expensive housing divisions in the Fort Worth area, much to the chagrin of landowners.

The economics within gas shale plays are a "bit of wild card," DeLozier said. "We have to make large upfront investments to buy the acreage before we have a drilling plan in some cases, which requires a different mindset. Then we need to accumulate enough acreage to have enough 'running room.' Some think small is fine; we don't."

Is it too late to get in?

Today, the price paid for entry into a hot shale play is secondary to scope and scale in determining the success of a project, said Peter Vig, RoundRock Capital LLC managing partner.

A prospective acquirer needs to get all the data available and have a sense of urgency about it because of the speed at which deals are getting done today, Vig said. When looking at a property, know the vintage of any wells drilled, the technology used and what the gas price was at the time, he added. If someone walked away from the prospect in years past, it might be time to reexamine the project in light of higher natural gas prices and improved drilling technologies.

When taking the plunge, grab up as many big tracts as possible. Build a big position to gain leverage in the play and control of gathering and other infrastructure. These days a large portion of purchase prices in the Barnett is being allocated to gathering, Vig said. Today the Barnett is said to be the most prolific gas play behind the San Juan Basin.

Southwestern Energy followed a strategy like what Vig outlined when the company entered the Fayetteville Shale play on the Arkansas side of the Arkoma Basin in 2003. By 2005 the company had about 600,000 acres. As of May 1, Southwestern had about 880,000 net acres. "They control the play," Vig said. Additionally, Southwestern bought up area abstract companies, so it cornered the market on title work, Vig said.

A producer that has the foresight to take a substantial acreage position in a play can afford to farm out some of that acreage to other producers that might have more experience in the play. This can provide learning opportunities, Vig said.

It's true that getting into a play like the Barnett Shale today is tougher and more costly than it was before things got hot. Players entering now will pay top dollar but will be taking a lot less risk than the early entrants did. Don't be put off by the fact that you're late to the play, Vig said. Run the economics on today's price and don't be put off by what others are paying, he advised.

"Just run the numbers and don't get hung up on where prices were or what someone else paid to get into the play." And remember what J. Paul Getty said, Vig advised: "The meek shall inherit the Earth, but not its mineral rights."

©Copyright 2006 Intelligence Press Inc. All rights reserved. The preceding news report may not be republished or redistributed, in whole or in part, in any form, without prior written consent of Intelligence Press, Inc.