Unconventional Resource A&D

Roughnecks roll drill pipe along the pipe rack for Chesapeake Energy Corp.’s Nomac Rig #44 in Bradford County, Pennsylvania.

?Tucked in the hills of northern Pennsylvania along the Susquehanna River Valley, the crew of Chesapeake Energy Corp.’s Nomac 245 rig spudded the Otten #2H in a 22-degree February day that carried a biting wind. Its target: the Marcellus shale 7,500 feet below.

This particular well, near Towanda, in Bradford County, and one of the northernmost drilled by Chesapeake to date, will feature a 4,000-foot horizontal lateral and multiple fracs. A similar well three miles north, Chancellor #1H, was brought on line days earlier. While undisclosed, a field rumor is that the initial flow rate was “very exciting.”

Otten #2H is 83% funded by Norwegian national oil company StatoilHydro, one of the first wells to be paid for from a multibillion-dollar joint-venture agreement between the two gas giants. The November deal valued the Marcellus holding at $5,625 an acre, roughly a 200% premium to previous-deal average values. Closing amidst the carnage of rapidly declining natural gas prices and collapsing capital markets, it was the last significant U.S. oil and gas deal of 2008—and still is, as of press time.

A rig is set up to drill Jennings #1, a Chesapeake Marcellus vertical test in Granville Township, Pennsylvania.

Transaction activity in U.S. shale plays has been fervent in the recent, bullish years, from competitive land grabs to billion-dollar farm-outs. But persistent devastation in gas prices is changing the nature of A&D in resource plays.

What is the outlook for transactions in the Big 5—the Haynesville, Marcellus, Barnett, Fayetteville and Woodford? According to Scott Richardson, principal with Houston asset-marketer RBC Richardson Barr, it will be busy, albeit for different reasons.

“Capital is so short right now from the private and public markets that we’re seeing companies have a hard time coming up with the capital to drill on their resource plays.” Acreage and joint-venture-type transactions will dominate the near-term marketplace as lease expirations come due during the next 12 to 18 months, he predicts.

“A lot of companies are not going to be able to drill out their positions in these plays. A lot of acreage will change hands.”

By the second half of this year, corporate transactions and joint ventures will swell, he anticipates, with well-capitalized companies looking to enter resource-play positions.

“The aggregators of these assets will be the biggest companies with the most capital that are currently underweighted in resource plays in North America. You’re going to see a lot of transaction activity.”

Statoil’s step into shale

Peter Mellbye, executive vice president, international E&P for StatoilHydro, says the company’s $3.3-billion entry into the Marcellus shale took a forward-looking view without weighting the current price environment. “We are doing this to build a production profile.”

When Norway’s Statoil and Norsk Hydro combined in late 2007, they formed the world’s largest offshore operator, producing 2 million barrels of oil equivalent (BOE) a day. StaoilHydro is presently a significant player in the Gulf of Mexico. But when the offshore leader stepped onshore the U.S. with its acquisition of a 32% nonoperated interest in Chesapeake’s 1.8 million acres in the heart of the Marcellus shale for $3.375 billion, the move appeared out of character.

Peter Mellbye, StatoilHydro executive vice president, international E&P, says the strategy is simple. “To grow this company, we’ve come to the conclusion that we have to involve ourselves in growth plays. We identified the shales in the U.S. as a resource that could substantially contribute to our business. It makes us an early mover into what we regard as a very attractive area in terms of the Marcellus.”

That attractiveness includes some 2.5- to 3 billion BOE in ultimate recoverable resource potential, the company believes.

StatoilHydro, heavily vested in the Norwegian Continental Shelf, a region with maturing assets and declining production, for two years looked onshore U.S. to expand its gas production, “so it wasn’t something we just jumped into when the opportunity came up.” After evaluating coalbed methane, tight gas and other opportunities in various parts of the U.S., the company focused on the Marcellus, an enormous play geographically with existing infrastructure and proximity to large markets.

“We looked at different opportunities, all onshore, and this is where we ended,” says Mellbye. “The size is the attraction—it’s a very large resource. This play is significant in supplying gas to the U.S. market.”

Acreage valuations in prime shale plays have dropped dramatically since land prices peaked in 2008.

Currently running six rigs in the play, Mellbye says the partnership plans to be aggressive in developing the leasehold, of which 600,000 acres is net to StatoilHydro. As part of the deal, StatoilHydro may participate at the same 32.5% level in all future Chesapeake lease acquisitions in the Marcellus as well. The current position alone holds drilling locations for 13,500 to 17,000 horizontal wells with average recovery per well of about 3.1 billion cubic feet (Bcf).

The deal stipulates that Chesapeake is required to maintain a “significant” level of drilling activity, and the plan calls for one new rig each month to be added with a targeted maximum fleet level of 50 running. Production targets are bold as well: 50,000 BOE per day by 2012 net to StatoilHydro, and a peak of 200,000 BOE per day in 2020.

The company never considered entry via a corporate acquisition or by building its own leasehold; a partnership with an experienced player made more sense. “We did not consider buying Chesapeake as a company. We are a major gas player, but we didn’t have the experience in onshore U.S. resource plays. The best thing to do is work with somebody that has that experience. This model fit our situation well.”

The deal structure involved an upfront payment of $1.25 billion in cash and another $2.125 billion to be paid during 2009-12 by funding 75% of Chesapeake’s share of costs. StatoilHydro, by policy, does not hedge and did not hedge this deal.

The transaction implies a deal value of $0.22 per thousand cubic feet equivalent (Mcfe) of total recoverable resources, according to John. S. Herold Inc. Meanwhile, the price paid per acre, when factoring in the carry, is more than double the play’s typical acreage value, which peaked at $2,000 to $4,000 and is now on a downward trend. Yet Mellbye defends the higher valuation.

“We think this compares favorably with other recent deals,” he says. “We feel comfortable with what we are paying and the value that can be created through this deal. This is for the long term. We are doing this to build a production profile. We do believe that the prices that we are looking at for the moment are not what you’ll see stand over a longer period.

“This deal delivers very satisfactory economics at prices well below what we presently can see in the forward curve.”

StatoilHydro completed the deal in fourth-quarter 2008 amid a commodity-price freefall while dozens of other deals were falling apart. Did it consider abandoning the plan?

“Given that the world was in turmoil, obviously we were looking at what was going on around us. Something we had to consider was, ‘How was this going to affect Chesapeake?’ That was the most challenging point.” After careful analysis of Chesapeake’s situation, he says, the assessment was that Chesapeake could perform, especially considering StatoilHydro’s drill-cost carry.

“The carry mechanism is structured so they have a strong incentive to execute the program. It’s an incentivized relationship, so that is not really a concern to us.”

JV the Chesapeake way

Chesapeake Energy acquired more shale acreage than it could develop and then took “some chips off the table” by monetizing a portion of its interests through joint ventures, says CEO Aubrey McClendon.

“I knew when we were putting these big plays together that we were going to end up with more acreage than we could handle,” says Aubrey McClendon, Chesapeake chairman and chief executive. “I thought there would be a high degree of interest in the industry by companies that had cash, but maybe not the shale evaluation or the land-acquisition expertise, and would be willing to pay us a premium for our skills in those areas.”

They did. Plains Exploration & Production Co. paid $3.3 billion for a 20% share of Chesapeake’s 550,000 net acres in the Haynesville shale in July. British major BP Plc paid $1.9 billion for a 25% stake in 540,000 acres in the Fayetteville shale in September. And the deal with StatoilHydro added $3.35 billion for the Marcellus position in November. In all, the Oklahoma City-based producer raised $8.6 billion in 2008 via selling nonoperated stakes with a cost basis of $1.2 billion in the industry’s best shale-play positions.

“It was pretty extraordinary, we believe. We finalized, negotiated and closed three deals that were innovative, creative and value-added for both buyer and seller. We did it in a way the industry hadn’t seen before. We think we’ve established a transaction template that will serve us well for additional joint ventures going forward.”

Taking chips off the table up front is how he puts it. For cash, of course. Some now, some later.

While the cost basis of the assets sold was approximately $1.2 billion, per the company, they sold for eight times that. “Yet from the buyer’s perspective, each of them acquired an interest in a play where they couldn’t have done it themselves and, at the end of the day, acreage cost doesn’t matter much in these great shale plays.”

The Susquehanna River as it winds through the rolling hills of northeastern Pennsylvania where Chesapeake is drilling for Marcellus gas with partner StatoilHydro.

The joint-venture structure—essentially a supersized farm-out—allows Chesapeake to capitalize on what it considers its two best core competencies: a technical competency in identifying unconventional plays early and accurately, followed by a land competency that is “second to none, in which we turn on our land machine and go buy leases.” At one point in 2008, Chesapeake had more than 4,500 brokers scouring these plays for leases. And price was no obstacle.

Because the gas reserves in these shale plays are so high, and the wells use up such a small amount of the leasehold, “honestly, the difference between paying $1,500 per acre or $15,000 per acre is just not that big of a deal,” says McClendon. “You’re talking about finding cost differences that might be measured in 2 cents or 20 cents per Mcf. Gas prices can move that much in a day.”

And, it still didn’t get that expensive, on average. “We knew we could buy the leasehold off the ground for amounts much less than that simply because we didn’t have that much competition, and there’s just not that much money in the industry to price acreage the way the gas reserves per acre would tell you that it should be priced.”

Houston-based Plains boldly planted a flag in the coveted Haynesville at the peak of the frenzy in early July, sealing the deal the very day commodity prices crested and began a long and precipitous plunge. Plains gained a net position of 110,000 acres for $1.65 billion up front and another $1.65 billion cost carry. The deal valued the leasehold at $30,000 per acre. Was it too rich?

“Plains made a great deal,” says McClendon. “Five or 10 years from now, Plains will be recognized as having one of the strongest positions in the largest gas field in the U.S. They couldn’t have gotten that from anybody else. Today’s gas prices are not likely to last very long, but even if they do, you’d rather be in a play like the Haynesville with lower finding costs than some other play.”

Nomac Rig #45 is drilling Otten #2, a Marcellus horizontal well, for Chesapeake in Asylum Township, Pennsylvania, to a total depth of 11,200 feet.

McClendon specifically sought out longtime friend Jim Flores, Plains’ CEO, to offer him the deal in late April 2008. Flores’ roots in Louisiana—home of the Haynesville play—go deep, and McClendon wanted to tap those relationships via a partner he thought might want to broaden his portfolio.

“Also, I needed somebody to understand that land costs don’t matter that much. Jim, being a landman, understood that, when some others might have had sticker shock.”

Factoring in the new SEC reserve-reporting rules that will go into effect at year-end 2009 and give new consideration to unconventional resources, McClendon believes Plains is buying reserves “on the cheap, even though I admit the headline price of the acreage looks tough in today’s environment.”

Why would Chesapeake give up so much of its hard-fought core Haynesville position? “Actually, on a net basis, we ended up with more.” At the start of negotiations with Plains, Chesapeake held only about 300,000 Haynesville acres, but when it became clear they were able to make a deal, the company accelerated its acreage-capture strategy to get to its goal of 550,000 net acres, which it wouldn’t have had the capital to fulfill otherwise.

Chesapeake’s strategy is to be in the lowest-cost plays possible. McClendon estimates average finding costs for the Haynesville at $1.30 per Mcfe, and only $0.65 for Chesapeake when factoring in the Plains carry. “There’s almost no gas price where it doesn’t make sense to drill.”

A low-price environment for Chesapeake is an ideal environment, he says, because “we’re essentially 100% hedged and we have these drilling carries that are dollar denominated, so the lower service costs go, the more valuable they are to us.”

About 7,500 feet below the hills of northern Pennsylvania, Norwegian entrant StatoilHydro hopes to capture 3 Bcf estimated ultimate recovery per well from the Marcellus formation. It paid some $5,600 per acre for a 32.5% nonoperated position to enter the play.

In spite of capex pullbacks industry-wide, Chesapeake is accelerating its Haynesville program. It has 21 rigs operating in the play today, with up to 35 expected in the field by the end of this year. “We’re accelerating because half of our bills are going to be paid by Plains, so this is a great time to be drilling wells. Those carry dollars are going to go a lot farther in a time of lower costs.”

And yes, leasing continues in the Haynes­ville. While reduced, “our leasehold budget amount goes a lot further today than it did a year ago.”

BP followed Plains soon thereafter, buying a 25% position in Arkansas’ Fayetteville shale in a deal similarly structured with $1.1 billion in cash, and paying 100% of Chesapeake’s costs up to $800 million. The deal was valued at $14,000 per acre, and $42,000 of flowing Mcfe per day.

Chesapeake established the relationship with BP earlier in the summer when it sold its entire Woodford shale position in Oklahoma to the major. The Fayetteville acquisition further established BP as a U.S. shale player with 135,000 net acres, adding to its 90,000 acres in the Woodford.

In all three JV deals, Chesapeake sought out buyers that looked beyond today’s bears and to the potential of the plays.

And Chesapeake is not done selling pieces of shale positions to cash partners. It is currently offering a chance to participate in the granddaddy of all U.S. shale plays, the Barnett, in which Chesapeake holds 310,000 acres. “It’s more mature, and therefore less risky,” he says, “so it requires a different approach.”

McClendon believes the current soft gas market presents an opportunity. “A low-gas-price environment for the next year or two would be the best.” Low service costs during the downturn equals more wells drilled for the money, just in time to produce significant volumes of gas as prices recover. “We’re not drilling wells today with the view that gas prices will always be where they are today.”

And, low natural gas prices make the shale plays that much more attractive. “The whole U.S. gas business is subeconomic now. The question really is, Where would you rather be in a time of low prices? I’d rather be in plays that don’t have much geological or engineering risk. I’d like to be in plays that have reasonably attractive gas prices on a relative basis, and I’d like to be in plays that find gas at low finding costs and that can start producing cash quickly.

“If gas prices are high or if gas prices are low, you still want to be in the best assets, and we think the Haynesville, Fayetteville, Marcellus and Barnett are the best assets, bar none, in the industry today.”

XTO’s buying adventure

If an award were given for most acquisitions in a year, Fort Worth, Texas-based XTO Energy Inc. would take the prize for 2008. The company closed 220 transactions in the period—within only nine months, in fact—totaling some $11 billion, capping the run with the $4-billion acquisition of legendary Dallas-based Hunt Petroleum. When XTO laid down its deal-making pen, the company had more than doubled in size. Most of these acquisitions involved significant acreage in the Big 5 shale plays, where XTO bolstered existing holdings and established new footholds.

“It’s one of the most entrepreneurial times in the history of XTO Energy,” says president Vaughn Vennerberg. “There are few times when such exceptional properties come on the market. We had to strike while we could. In 2009 and beyond, you will see the fruits of those labors and the wisdom of why we did it.”

The economic-return opportunities on those properties, in particular the shale basins, were irresistible. Following those acquisitions, XTO now holds 1.7 million acres in the five leading shale plays with an inventory of 6,050 to 6,770 prospective drilling locations.

“Those plays were very hot plays. To be able to get a select position in a core area doesn’t happen very often. It will give us a drilling inventory that we will be able to pursue through the ups and downs of the market.”

Vennerberg sees the current price environment as undervalued and an anomaly. XTO looks five years out and prices its drilling at $7.50 gas and $75 oil. Even with $4 to $7 gas, he says, finding costs of $1 to $1.60 per Mcf result in realized returns of 30% to $100% on capital employed.

Economics in these plays are “pretty phenomenal,” he says. The company calculates returns for the Barnett at 92% at $7.50 gas, and 47% at $5, factoring in a 20% reduction in well costs. Similarly, the Fayetteville returns 65% and 36%, respectively, and the Marcellus, 99% and 70%. “Economics are very good.”

XTO rolled up a host of smaller sellers in the Barnett in 2008, bolt-ons for about $1.5 billion that “fit like a glove” over existing acreage. Vennerberg sees similar transactions as the template for A&D activity in the maturing Barnett shale.

“The driver in the Barnett for the next 18 months will be those operators that have undrilled leasehold that have expirations coming up. You’ll see producers putting out packages, doing joint ventures or farming out acreage to hold leases. That will be the driving force.”

In the Fayetteville, where XTO acquired 20,000 acres from Contango Oil & Gas and 55,000 acres from Southwestern Energy, Vennerberg believes divestiture activity will be quiet for awhile. “The Fayetteville is characterized by a handful of players and they seem to be doing business as usual,” he says. “Everybody is focused on drilling.”

Economics of the five leading U.S. shale plays are “pretty phenomenal,” even in a lower price environment, according to XTO Energy president Vaughn Vennerberg. Following an intense acquisition spree beginning in mid-2007, XTO now holds about 1.7 million acres and a drilling inventory of up to 6,700 locations in these marquee regions.

With a drilling inventory of 1,600 to 1,800 locations in the Fayetteville, potential reserves of 2.5 trillion cubic feet and finding and development costs of $1.20 to $1.60 per Mcfe, “the economics are beautiful,” he says. The company will drill 105 wells in the play this year.

Long-term lease terms will soften the urgency to move acreage in the Marcellus, where XTO gained a 152,000-acre foothold from Linn Energy and currently holds 280,000 acres total. Most leases are five years with five-year extensions, so “nobody is pressured by lease expirations.” Consequently, A&D activity will be slow moving, he thinks. The company is running one rig in the Marcellus with 10 to 12 horizontal wells planned for 2009.

Activity in the Haynesville is presently hampered by a market adjustment as landowners and sellers swallow a changing price environment. Still, he says, the well economics are too good and the well results are too big to stifle activity for long. XTO holds about 100,000 acres in the play, with 40,000 coming from the Hunt transaction, mostly on the East Texas side. The company will drill 15 to 20 wells there this year.

The Woodford, however, should be active with transactions. “There are more small outfits in the Woodford shale than the other plays, where you have much larger independents. You’ll see (packages from) some of these small operators that want to get out.”

While XTO only registered about $200 million in acquisitions in the Woodford during its multibillion-dollar year, the play is “very much an emphasis for the company,” Vennerberg stresses. “The opportunities were not there in the acquisition market, but we wouldn’t be running three to four rigs in that area if we didn’t like it. It’s definitely a growth area for the company.” It holds 160,000 acres there.

In spite of falling gas prices, Vennerberg believes resource plays will continue to thrive. “You see incredible reserve additions from these basins.” By XTO’s estimates, ultimate recovery per well for the Barnett is 3.3 Bcf; Fayetteville, 2.2; Woodford, 3.8; Marcellus, 3; and Haynesville, 6.5. “That makes the returns and economics very attractive, even in a lower price environment.”

Following its aggressive acquisition run, might XTO need to sell any assets to raise cash?

“We’re not in a position to need to do that,” says Vennerberg. “Generally, we don’t do that and we aren’t interested in doing any joint ventures. We’re in great shape. We have built this company to perform through the cycles and this year we’re going to spend our time digesting those acquisitions.”

Hot on Haynesville

Even before the Haynesville shale was a household name, Petrohawk Energy Corp. had identified the potential of the play and was acquiring acreage. Today, after a short and bruising battle for leasehold, Petrohawk claims 300,000 acres in the heart of the play and is spending 70% of its 2009 budget on the northwestern Louisiana prize.

?Chesapeake’s production facilities for its Evanchick #1 Marcellus well in Asylum Township, Pennsylvania.

“We feel like we’ve put together one of the best acreage positions in the play,” says Steve Herod, Petrohawk executive vice president, corporate development. “Our well results are bearing out that we have great acreage.”

Results from 14 wells, ranging from 15- to 23 million cubic feet per day for most, convinced the company to pack up rigs in its Fayette­ville shale leasehold, and deploy them south across the Louisiana border, where 12 rigs will punch up to 80 wells in 2009.

While the Fayetteville is “still just as good of an opportunity for us,” it is taking a back seat to the Haynesville only temporarily, says Herod, due to holding longer-term leases there of five years with five-year bumps. “We’ll get rigs back into the Fayette­ville and develop that according to plan, but these leases in the Haynesville need to be held.”

About half of its holdings in the Haynesville are either held by production or have lease terms exceeding three years. “The other half we have to drill in the next three years. Our current rig schedule will let us hold what we need to hold.”

Plus, the returns in the Haynesville are juicy. “If we put money into one well, we’ll see that money back once or twice in the same year—we’ll drill two or three wells with the same money in the same year in the Haynesville. It’s an incredible return scenario that is almost unprecedented in our business. In an environment where it’s hard to raise money, it’s hard to say no to that kind of cash flow, even at these lower gas prices.”

The Haynesville resource play is “the best of the best,” says Petrohawk executive vice president, corporate development, Steve Herod. “If gas prices fall yet more, you’re going to see rigs get laid down in other plays before they get laid down in the Haynesville.” Petrohawk is moving rigs out of the Fayetteville play to accelerate its Haynesville program.

Petrohawk is content with its land position in the play, but selective lease acquisition continues. “Certainly the majority of the acreage is leased up, but there are people who didn’t lease for one reason or another. We’re more focused now on quality and getting acreage in sections where we already have significant acreage. We’re very selective at this point.”

Prices have also dropped precipitously from more than $20,000 an acre last summer. “The numbers now are much less than that.” For a time in the fourth quarter, no market existed for Haynesville acreage as buyers and sellers split on valuations. “No deals were getting done, so it was impossible to gauge market value.”

Petrohawk is open to joint-venturing with a major or large independent, he adds. For example, small-cap Goodrich Petroleum Corp. farmed out some of its Haynesville position to Chesapeake last year.

“Certainly, we’ve had people approach us to talk about it. We’re always interested in considering what has value for Petrohawk.” Those talks involve major oil companies, he confirms. However, he emphasizes that the company is not in an active transaction process with anyone presently. “It’s an idea that we would consider.”

The Haynesville hosts four or five large players and many smaller operators. Herod expects to see consolidation. “This isn’t a mom-and-pop type of play. For someone that hasn’t done it before, to drill these horizontal wells is a big challenge. If things don’t go right, it can result in big cost overruns. That’ll send some companies to market.” Also, smaller companies will find it more difficult to get rigs, equipment, pipeline access and technical staff.

Of all the plays in North America, the Haynes­ville is “the best of the best,” says Herod. “Once these Haynesville wells are drilled and on production, the operating costs are really low. If gas prices fall yet more, you’re going to see rigs get laid down in other plays before they get laid down in the Haynesville.

“We feel good about the economics in today’s price environment. We’re going to be drilling out here for years. The price of gas this week doesn’t control what we’re going to be doing here for years to come.” In second-half 2008, Petrohawk opened another shale play—South Texas’ Eagle Ford—that it hopes will rival its Haynesville and Fayetteville holdings. From a technical standpoint the rock looks similar to the Haynesville, and Petrohawk put together its 156,000-acre block under the radar. “We got all the acreage we wanted at very attractive prices before we completed our first well.”

Two wells drilled to date flowed between 8- and 9 million cubic feet per day. “It’s still early days, but it looks good so far.”

He believes shale plays will still be standing when the economic dark clouds pass. “Maybe the lower price environment is a necessary evil to realign the gas supply toward these lower-risk unconventional plays.”

Move over for majors

“The companies with the best positions in these resource plays are going to be highly coveted by the larger companies,” says RBC’s Richardson. “There is going to be a flight to asset quality, and you’re going to see a lot of consolidation.”

It’s gas-farming—low risk, predictable plays with an enormous resource potential and attractive finding and development costs. That recipe attracts major oil companies.

?Production facilities under construction for Chancellor #1 in Bradford County, Pennsylvania. The Chesapeake well was drilled to a total depth of 11,500 feet including a 5,000-foot lateral. It is the northernmost Marcellus well drilled by Chesapeake and flow rates were reported as “exciting.”

“There’s a scarcity of high-quality assets. As markets go up and down, we continue to see resource plays trade at premiums. Big companies have few options to get a terrific foothold. The reserve life of these assets is very long and it’s a long-term strategy. They’re comfortable paying a premium in the short term for a long-term reward.”

Majors will be the most active acquirers in resource plays in coming months. “The resource-play positions require so much capital that it is becoming a big-company game. You need to have a clean balance sheet and significant access to capital to exploit these plays. It’s going from small to big.”

Even in a soft gas market, “you’re still seeing capital being spent by the majors in some of these areas that do not have the greatest economics now, but they’re betting on the future. They’re trying to get positions in the right plays so that, when the gas markets do come back, they’re positioned to get terrific returns.”

International majors are looking to expand their footprint in politically secure North America, in particular, he adds, in the deepwater Gulf of Mexico and in onshore gas-resource plays.

The joint venture as a divestiture template will continue, particularly in the Marcellus and Haynesville plays where a number of producers are capital-short and will need help in drilling their leasehold. “It’s a perfect way to raise capital as a seller.”

And, “people capital” is a motivator for majors to seek joint ventures, he adds. “BP and StatoilHydro entered joint ventures with Chesapeake and took a nonoperated position. It’s remarkable that a major international company would prefer having a nonoperated position where Chesapeake can supply the people, technology and institutional knowledge of the play. Ten years ago, you would not have seen that. The shortage of technical people is significant.”

Because the Haynesville and Marcellus are more widely held and the Barnett and Fayette­ville have dominant players, he expects joint ventures to continue to be the trend in the former and corporate acquisitions to surface in the former. “If one of the majors were to do a transaction with a Devon Energy, Chesapeake or XTO, they would get a significant position both in the Barnett and Fayetteville.”

Shale transactions will resurface in the second half when capital becomes more available and commodities stabilize. “We see a busy 2009 in the resource plays.”

Can the Big 5 shale-gas plays survive in a price-adjusted new world? “They are the name of the game going forward.”