Adapted from “Unconventional-Resource A&D” in the April 2009 Oil and Gas Investor.

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 on a 22-degree February day that carried a biting wind. Its target: the Marcellus Shale 7,500 ft below.

This particular well, near Towanda, in Bradford County, and one of the northernmost drilled by Chesapeake to date, will feature a 4,000-ft horizontal lateral and multiple fracs. A similar well three miles north, Chancellor #1H, was brought online 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 US $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 US oil and gas deal of 2008.

Statoil’s step into shale

When Norway’s Statoil and Norsk Hydro combined in late 2007, they formed the world’s largest offshore operator, producing 2 million boe/d. It is presently a significant player in the Gulf of Mexico. But when the offshore leader stepped onshore the US 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, said 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 US 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 billion boe 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 US 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 US, 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,” said Mellbye. “The size is the attraction — it’s a very large resource. This play is significant in supplying gas to the US market.”

Currently running six rigs in the play, Mellbye said 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 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,” Mellbye said. “We are a major gas player, but we didn’t have the experience in onshore US 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/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 valuation.

“We think this compares favorably with other recent deals,” he said. “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, Mellbye said, 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,” he said.

JV the Chesapeake way

“I knew when we were putting these big plays together that we were going to end up with more acreage than we could handle,” said 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,” McClendon said.
Taking chips off the table upfront 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,” he said.
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,” said 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,” McClendon said.
He 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 US 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,” McClendon said.

“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.”