EOG Resources Inc. reported a screamer Barnett Shale well in December-10 million cubic feet per day-in Johnson County. To those unfamiliar with the play, this may not be meaningful. To Barnett fans, however, the news further fracs the play's potential wide open-the flow is huge and the location is outside the traditional core area. Thousands of acres held by EOG and others in the county are theoretically worth much more since the news, and the rumble is being felt by acreage-owners elsewhere in what has been the noncore Barnett. So, just when prices for Barnett assets seemed high, there they grow again. Properties in the area have jumped from the 76 cents per proved thousand cubic feet equivalent (Mcfe) that Progress Energy Corp. paid Republic Energy Inc. and others for 195 billion cubic feet equivalent (Bcfe) of Barnett reserves in early 2003 to the $6.19 per Mcfe paid for another Barnett producer and its 40 Bcfe of proved reserves in Johnson County last summer. The Barnett is proving to be no sleepy giant-it has produced surprises regularly in its roughly six years since making the E&P map when early play worker Mitchell Energy & Development Corp. began reporting initial results. Devon Energy Corp. bit early, buying Mitchell in January 2002 and getting 2.5 trillion cubic fee equivalent (Tcfe) of proved for $3.5 billion (a bargain $1.40 per proved Mcfe). It has had the chance to play the Barnett anthem at investor presentations ever since. And, the buzz is loud in the Fort Worth Basin. A relatively E&P-savvy region, some landowners are going to drill their own wells. Many are refusing leases longer than three years. Rumors of lease-flipping-acquiring acreage to accumulate and sell the bulk for a higher price-are running rampant. The lease-expiration clock is ticking too fast for some acreage-owners who can't get their hands on enough rigs. Some 100 were drilling there at year-end 2005 and most operators have announced plans to add more during this year. Yet, even pros have missed the Barnett train. From the core of Denton, Tarrant and Wise counties, where the oftentimes 500-foot-thick shale is found as deep as 7,500 feet, it screams updip westerly to as shallow as 2,500 feet in Erath County, in as few as 160 miles. One private-equity provider says the firm turned down funding Barnett-focused prospectors in the early 2000s because the play seemed to need at least $6 gas prices. "In hindsight, our view of gas prices was wrong and lots of people have made a fortune in the Barnett," he says. The firm never did invest in a Barnett player. Meanwhile, Warburg Pincus, Yorktown Energy Partners and Lehman Brothers Merchant Banking committed $260 million to Barnett start-up Antero Resources Corp. in 2003 and sold some 24 months later to XTO Energy Inc. for $900 million. Founder Paul Rady and team had put together some 60,000 acres in Wise, Tarrant, Parker and Johnson counties; 440 billion cubic feet (Bcf) of proved reserves; and daily production of 60 million cubic feet. The price per proved Mcfe was $2.05. Also believing in Barnett potential was Houston-based private-equity provider EnCap Investments LC. For a $27-million commitment, it owns 37% of Fort Worth-based Stroud Energy Inc., which was planning an initial public offering at press time. Founded in 1985, Stroud had focused on Oklahoma and Kansas, and expanded to the Giddings Field in central Texas when joined by former Union Pacific Resources managers. It gained a focus in the Barnett Shale when ex-Mitchell Energy managers Patrick Noyes, Gregory Frazier and Chris Veeder joined the company in 2003. It has interests in 22 wells in the Barnett now, producing 3 million cubic feet per day, and it controls some 14,000 acres. Active gas-play acquirer Chesapeake Energy Corp. sat out of the Barnett initially. "It took us a while to get our valuation machinery fine-tuned there," says Aubrey McClendon, chief executive. The company finished second for Antero. "We should have bought that. It was a great acquisition for XTO," McClendon says. Then, Chesapeake missed a Four Sevens Operating Co. package. "In early 2004, we really didn't appreciate the full potential of the play, particularly in Johnson and southern Tarrant counties." Soon, however, Chesapeake jotted down the most convincing numbers and won assets from Hallwood Energy in Johnson County, more assets from Hallwood in a later divestment and then a package from David H. Arrington Oil & Gas Inc. last month. In addition, the company has been actively leasing in the field and today owns close to 100,000 net acres-the vast majority of it in the hottest parts of Johnson County. The company is producing about 100 million cubic feet equivalent per day, has five rigs running and plans to go to between 15 and 20 rigs by year-end. Chesapeake believes it is the fourth-largest producer in the play, behind Devon Energy, XTO Energy and EOG Resources. Point of entry Is there room now for newcomers except by buying out other players? It would be very difficult, operators and financiers say. "I wish we had bought more acreage earlier, when it was easier," says Bill Pritchard, chairman of Durango, Colorado-based Peak Energy Resources, which has about 30,000 acres over the shale. The large sections of land that are left in the hot core are there for a reason- the landowners aren't interested in leasing or "have grandiose ideas of what they're entitled to in terms of lease bonuses and royalties," he says. Privately held, Yorktown Partners-backed Peak came by its first 9,600 acres in the Barnett in early 2003 in an acquisition that held three assets: a shallow, held-by-production position in Hood County; properties in the San Juan Basin, which were later sold to Burlington Resources; and an Anadarko Basin and Texas Panhandle position, which was later sold to Forest Oil. The Hood County position, which Peak I had not focused on, became part of Peak II in August 2004. "We didn't know what we had out there," Pritchard says. Others did. The company soon received eight offers for its leasehold. "We didn't know the play had gotten as far out as Hood County. We discovered that, not only had it gotten that far out, but about two-thirds of the acreage had already been leased all around us." Peak's neighbors today in Hood County are no small names: Burlington (which will become part of ConocoPhillips upon merger closing later this year), XTO Energy, Chief Oil & Gas, Quicksilver Resources and EOG Resources. Peak's other leasehold is in Parker, Palo Pinto, eastern Erath and northern Somervell counties. Its Hood County acreage offers the thickest shale-some 290 feet-and is getting the most attention from the company's geoscience team. It otherwise owns a small field in Wyoming in the Wind River Basin that makes about 2 million cubic feet per day. "I'm trying to discourage any more competitors in the Barnett," Pritchard says. "We've got all we need. It would be very difficult now to put together a lease block like we have. You can go into the outlying counties and put acreage together, but in the area where we are, the majority of the leases are taken and what is left, it would take a lot of time, effort and expense to acquire." The company owns three rigs and has two drilling for it now; one is on loan to XTO Energy in Johnson County. Peak's wells cost some $1.9 million each and prove about 1.1 net Bcfe of reserves each. "Those finding costs are pretty rich-$1.72 or so. It is somewhat commodity-price sensitive, although I think we still make money at about $4 gas," Pritchard says. Peak has drilled seven horizontal wells; four are producing a total of 2.5 million per day, two are waiting on completion and one was nearing total depth in late February. The shale has a notoriously prompt and steep decline curve, producing a few million cubic feet per day its first week and falling off to maybe 450,000 cubic feet within a couple of months. But it's easy gas, right? No. "What the investment community doesn't understand is that this is an unconventional-resource play. It is still a very technically complex play. You can't just get into this play and begin to start printing money in a back room. You're going to spend many millions of dollars figuring out what works and what doesn't work before you're going to actually start making money." Pure-play opportunity On the market at press time was privately held Chief Oil & Gas LLC, the No. 3 Barnett producer, bringing up 100 million cubic feet per day. Estimates in the M&A community were that the package would go for more than $1.5 billion, using Antero deal metrics. The company holds more than 200,000 acres in Wise, Denton, Tarrant, Parker, Johnson and Hood counties, and more than 250 wells. Randy King, co-head of investment banking at Houston-based investment banking firm Petrie Parkman & Co., which is advising Chief on its Barnett exit, says, "I think the market underappreciates the longevity of the production and that we're in the first pass across the acreage. People are drilling to secure acreage. That sets up years, if not decades, of multiple passes." Within the core and Tier I areas, it's going to be difficult from a standing start to accumulate much of a position without buying somebody who already has a position, he adds. "To get a large position, you have to go beyond these areas. Probably the industry is underestimating how much exploitation is left even in the core, and there's probably going to be room for other parties from downspacing, refracturing, stacked laterals, all those types of second-, third- and fourth generations of development. It's going to be here a lot longer than that. It's no flash in the pan." In the heart of the Barnett play, the shale is 300 to 500 feet thick. "We know that you're only contacting via stimulation a small percentage of that interval over an area. We're just scratching the surface on the extent of how big this Barnett is." In Barnett Shale deals, Lehman Brothers Inc. has advised XTO Energy in its purchase of Dabb Oil Co.; Progress Fuels in its sale to EnCana Oil & Gas (USA); Antero in its sale to XTO Energy; and Arrington in its sale of acreage in Johnson County to Chesapeake Energy. Greg Pipkin, Houston-based managing director, Lehman Brothers, was expecting 15 or 20 companies in the Chief data room. "That's probably the last big acreage position-more than 100,000 acres-that will be sold as a pure play. If you're going to be large in the Barnett, you should be very aggressive in purchasing that, or it's going to be very difficult to get into the Top Five in the near future, unless you buy one of the Top Five." That would be XTO, EnCana, Devon, Chesapeake and EOG. "The resource potential is great. That's why you're hearing major oil companies' names being bandied about. The resource is there. It's all a question of if you have a completion and frac technology to make this very cost-effective." Estimates are that a minimum $5 gas price is needed to make the economics work, and at least $6 gas for a decent profit. "It is an expensive resource but it is all a matter of your long-term perspective of gas price, and your effective procedure in extracting the gas out of the shale." Moving on Buying out existing publicly held Barnett players today at their current stock prices could give away all the upside-at least the perceived upside as of a few months ago; the Barnett's potential remains a growing target, bumped up again just lately by the EOG well news. Dave Pursell, an analyst with Houston-based Pickering Energy Partners Inc., and former colleague Jeff Hayden, extensively analyzed the Barnett in an October report. "Our primary takeaway from this analysis is that Barnett upside is already priced into most of these stocks-with some priced to perfection," they say. "An investor has to use aggressive assumptions about the play-not to mention higher commodity prices-to justify buying most of these names on Barnett upside alone." Randy Hill left the Barnett and hasn't looked back. The chairman and chief executive of Plano, Texas-based Grayhawk Energy Inc. was in the play with his Cortez Oil & Gas Inc., a predecessor company he sold in 2004 to Fort Worth-based Encore Acquisition Co. for $123 million. It had 4,000 acres in Tarrant County. Cortez had private-equity backing from Natural Gas Partners. Hill had gotten into the play when it was hard to ignore in his Dallas-Fort Worth neighborhood. "It was right in our backyard. In 2002, we started looking for leases when you could still put together acreage," he says. He didn't re-enter with Grayhawk, however. "We didn't see any opportunity there for us. It's hard to get in." Instead, he and the balance of the Grayhawk team went west, taking the horizontal-drilling and slickwater-frac technology they used in the Barnett to the Texas Panhandle's Granite Wash, which is also a tight, shaley, sandstone reservoir. The slickwater fracs, which Hill credits Bravo Natural Resources with first applying in the Granite Wash, are doubling reserves. The Barnett was a technical challenge: "It's not a blanket play. You have geologic risk. You have a lot of faulting. You can make a good well there right next to an awful well. You have to have good seismic, not to see the reservoir, but to see the faulting. Also, you don't want to go in without a lot of acreage-and that's hard to accumulate or you have to buy an existing company." J. Robert Ransone, a partner at Dallas-based producer Duer Wagner III Inc., has seen many Barnett deals, including while at his former Wellspring Partners property-marketing practice. For a newcomer wanting to get a toehold by leasing acreage, rather than buying existing holdings, "there is opportunity. Where the opportunity is is getting far out. If you're talking about the core, like in Johnson County, you wouldn't want to go in there. There are no leases available." It's difficult to put together even a 300-acre unit, and that is the minimum size Ransone recommends for a horizontal play. "I don't want to go in there and drill one well on a 50-acre lease. It would have to be vertical or a short lateral. In a 300-acre block, you can get three horizontals. If you can't drill three wells, I don't think it's worth doing. You should have at least 600 acres; 300 would be at an absolute minimum." Chief Oil & Gas was an early entrant, really second only to George Mitchell in the core area, Petrie Parkman's King notes. It's probably more difficult for an existing player to make the leap to higher land costs and outside the core and Tier I areas than new entrants. "Existing players already have a position to exploit. Second, you've got the scarcity value for those who don't have a position-the economics still work but they're willing to pay an entry price that a current operator isn't going to pay. Even at a higher land costs, the economics of the play are still very good." Another producer says of leasing in untested territory, "What would I be buying? I would be getting into a less-proven Barnett opportunity-thinner sections and less pressure. In the core, the best entry is taking a nonoperated stake, but the operators don't want you. They aren't going to let you in on their deals, and the ones who need help, I don't know if I'd want to go in with them." Capital access To those who want to buy out competitors in the play, capital is available. Jason Meek, director, Key Banc Capital Markets in Dallas, recently arranged an equity offering for small-cap Houston-based Westside Energy Corp. to buy out EBS Oil and Gas Partners Production Co. LP, a Barnett operator. "That was financeable because Westside has high-quality acreage, adequate personnel, and access to service assets to support its drilling plans in the Barnett Shale," Meek says. Westside placed 3.3 million shares at $3.15 each, raising $9.5 million net. The company, which holds 68,000 gross (64,000 net) Barnett acres, is purchasing EBS for $9.8 million. It will gain 6,000 acres, 12 Barnett wells under way and 27 producing; total proved reserves of 2.3 Bcfe (88% gas; 51% proved developed producing); a one-sixth interest in some 14 miles of gathering lines; and three compression stations with pipeline capacity of approximately 20 million cubic feet per day. "More importantly, though, the management and employees of EBS are joining Westside," says Jimmy Wright, Westside president and chief executive, "bringing considerable oil and gas expertise, further critical mass and relationships for Westside that will complement our efforts in assimilating acreage, drilling and completing wells, and placing them on production." Most of Westside's existing acreage is in Hamilton and Mills counties, and it also has holdings in Denton, Wise, Montague, Ellis, Comanche, Lampasses, Hamilton and Coryell. The company's 2006-07 drilling focus will be on 8,000 acres in Montague, Cook, Wise and Hill counties. Meek says some operators and investors are concerned with how much acreage will be drilled before leases expire. "Some leases have been shortened to three years. The landowners are very aggressive and they're putting demands on the lessees that they didn't before, to encourage quicker drilling than what you would have experienced five years ago. The landowners require significant money upfront, and usually require the lessee to drill a minimum number of wells throughout the lease term." Wall Street was very familiar with midstream and service restrictions in the play that are hampering more rapid development, Meek adds, and they readily liked the Westside-EBS story. "A lot of companies have acreage in the Barnett, but unless they have the personnel with the development expertise and good, deep contacts in the industry, particularly the service industry, they're not going to be able to extract maximum value out of their acreage," Meek says. "Although every company in the Barnett is short at least one rig, other companies like Quicksilver, Carrizo and Denbury have excellent access to equipment and infrastructure, and that's what creates the true value-not just acreage. At final lease expiration, undrilled acreage is worth zero. The real value is in being able to convert that acreage into proved and probable reserves and, of course, cash flow." Deal metrics For now, many players are looking for Barnett assets rather than capital. Dallas-based investment banker and M&A advisor Energy Spectrum Advisors has closed four Barnett working-interest sales, three Barnett royalty sales and one Barnett acreage sale. In addition, it has closed one Barnett financing. At press time, it had closing under way on a Barnett acreage sale, and was marketing another Barnett working-interest sale and a Barnett royalty sale, says Ben Davis, senior vice president. The financing was in 2000. "Most of our activity in the Barnett in the past three years has been on the sale side. In fact, I think that's somewhat indicative of where the market is. In this price environment, there are a lot more folks who want to sell than there are folks who need to finance." He and colleague Kyle Miller, assistant vice president, looked at several Barnett transactions in a year-end 2005 U.S. upstream M&A activity report. "It was interesting to see the different tiers of property sales," Davis says. "The larger deals-the $250-million-plus, maybe in some particularly hot areas where they're drilling great wells-are trading for $15,000 to $20,000 per daily Mcf." Smaller deals, or where producers aren't drilling quite the barn-burner wells, are still trading at $10,000 to $15,000, he says. Otherwise, it seems to be a very predictable sales basin. "We sold a Gulf Coast package in fourth-quarter 2005 that traded at $150,000 per daily barrel. On the chart, it's way up there on the Y axis by itself. That's what I call an anomaly. We're not seeing that in the Barnett. We see some a little above the median and below the median, but they're all in that $10,000- to $20,000-per-Mcf-per-day range." Barnett packages bring in a number of data-room visitors but few outsiders are buying. "Most of the companies doing the deals are in the Barnett already. Both our deals and the public deals we've been tracking are getting the usual suspects," Davis says. A seller can get back in. "The only constriction he might have to worry about is getting a rig. But if he can hang onto the rig he had, or if he owns a rig, he's going to go right back to leasing acreage and drilling wells. The big companies keep getting bigger but there is enough free acreage out there that keeps coming into the bottom of the food chain. It keeps the smaller guys with plenty to do." Where is this acreage? "Clearly there's less acreage still available in the original core area and even now in the new core area in Johnson County. Aside from acreage expiring, yes, guys are going to have to move farther out, but that's not necessarily as far out as people might think. I mean going from eastern Parker to western Parker is not falling off the edge of the Earth." Republic Energy sold to Progress Energy two years ago, sold again six months ago to Burlington Resources, and is back at work again in the Barnett. Privately held Grapevine, Texas-based Reichmann Petroleum Corp. was able to get back in. It bought back its 50% stake in interests in 25,000 acres from Marathon Oil Co. in October in Denton, Erath, Johnson, Parker, Stevens and Tarrant counties. The price was not disclosed. Reichmann had sold 11,500 gross acres to Marathon in December 2004. The company has interests in 70,000 gross acres in the Barnett. It operates there and in South Texas. It has a joint venture with Wynn-Crosby Partners Ltd., Kerogen Resources Inc. and Neumin Production Co., a subsidiary of Formosa Plastics Corp. USA, in 6,200 acres in the Barnett. Dyke Ferrell, Reichmann co-founder and president, says a good land position could command up to $5,000 per acre this year in the play. So far, he has paid $500 per acre for most of the existing holding. Drilling results Beyond a lease position, good well completion is key, Davis says. "Look at Hallwood. They were the one of the first ones in Johnson County and they drilled 16 or 17 vertical wells, none of which were very good. A lot of people would have quit long before they did, but they stuck with it and ended up with a strategy for completing their wells horizontally. They were one of the pioneers in Johnson County." Pickering's Pursell and former colleague Hayden like Johnson County too. "Surprisingly, despite consistently hearing that the core area is the best acreage in the play, the best wells are the Johnson County horizontals-an average rate of 2.14 million cubic feet per day-with superior economics to both core-area horizontals and verticals." They define the core as Tarrant, Denton and Wise counties, which include the popular Newark East Field. Their Tier I noncore area consists of Parker, Hood and Johnson counties, and the Tier II noncore consists of Jack, Palo Pinto, Erath, Somervell, Hill, Bosque, Hamilton, and Comanche counties. Tier II is likely to produce oil rather than gas, and uneconomic amounts. "This is the riskiest area of the Barnett," the analysts say. "...The industry still does not have definitive proof of where the gas window ends, nor what the decline rates or recovery factor will be. Each of these will meaningfully impact the play's ultimate potential." Players obviously want acreage in the tri-county core, but venturing out farther may hold the most new potential. "At this point in the play's development, we'd take random acreage in Johnson County over the core counties-Tarrant, Denton, Wise-any day of the week. The Newark East Field looks relatively mature, which is consistent with statements from Devon that its core-area production has peaked, and core-area results outside of Newark East haven't been nearly as good. The Johnson horizontals, however, have been quite good, and it appears that another 'sweet spot' trend is emerging." In Tier II, the analysts found six horizontal wells to review, and the results were not promising. "Although we expect results to improve as companies improve the completion techniques in the area, we'd be lying if we said the rates didn't give us some concern. So far, most of the wells are noticeably below our assumed average." Yet, while a tough play, it can be very rewarding. "...There are more below-average wells than above-average wells. However, the good wells tend to be really good, pulling up the average." XTO Energy reports a 40% to 60% pre-tax rate of return at $6 gas on a Barnett Shale well (100% working interest) that costs between $1.8- and $2.4 million to drill and complete, and proves 3 Bcf of gas. At $8 gas, the rate of return grows to between 60% and 90%; and at $10, between 80% and 130%. A large acreage position is important, Pursell and Hayden add. "As the industry has yet to figure out how to identify the good wells from the bad-yes, there are bad wells in the play-a large acreage position is a necessity to minimize the risks and allow the law of large numbers to take effect." Peak Energy's Pritchard says, "Everybody thinks that the Barnett is an easy play, the hottest play in North America, and that if you're in there, you can't help but make money. But it is an unconventional-resource play. The work George Mitchell (at Mitchell Energy) did dates back 20 years with vertical wells and, more recently, with horizontal wells. But, not every well works." Some wells end up fracing into the Ellenberger, a water-bearing formation below the Barnett; when that happens, the well is largely a bust. "Because it is an unconventional resource play, it takes tens of millions of dollars as you go into new areas to figure out what works and what doesn't work. It's not just a lay-up," Pritchard says. In the play, he most admires EOG Resources' work. "EOG has the right approach. They're not involved in the acquisition game. They've got their leasehold position. They're methodically going about shooting it with seismic. They have a consistent drive to get their costs down." Downspacing Outside of player consolidation and continued tests of the Barnett's economic boundaries, what is next on the horizon? Downspacing. EOG Resources plans to drill its Johnson County holding in 500-acre spacing this year. It is also in Jack, Erath and Hood counties, where it is expanding its drilling program. Lloyd Byrne, E&P analyst for Morgan Stanley, says, "This implies 35-acre splits and likely increases the number of drilling locations from 750 to between 1,250 and 1,500 (in Johnson County)." It could add $5 to EOG's share price, he adds. In Johnson County, EOG's last 20 wells have proved reserves of 2.4 Bcf, net, each. Shorter laterals add approximately 300 more locations than previously estimated on 1,000-foot spacing, EOG reports. Net production from its shale acreage at year-end 2005 was some 90 million cubic feet equivalent per day. Of EOG's 500,000 acres, some 413,000 are in Jack, Erath and Hood counties. Byrne says, "Questions about the productivity of the western shales have continued to linger, as it remains early in the development of these 'thinner' shales. However, given the acreage position, potential impacts to recovery and/or downspacing could be material to asset values." Lehman's Pipkin says the Barnett isn't a play for the faint of heart. "You need deep pockets. That's why you see XTO, EOG, Devon, EnCana, Chesapeake and maybe Shell there-these are all sizable companies." Royal Dutch Shell is getting its feet wet in the play already, having bought assets from Sundance Resources and Pitts Oil & Gas recently. ExxonMobil has entered the play in a venture with Harding Co. And, a large player will be taken out later this year-when ConocoPhillips completes its acquisition of Burlington Resources. Pritchard expects further consolidation. "We'll sell. And, Chief is selling. I look out at this play and three years from now, maybe, there will only be a few dominant players: Devon, EOG, XTO, Chesapeake, Quicksilver, and it may be Shell and Exxon; or it may be just Shell and Exxon. Any one of those other companies might not be here three years from now."