What’s new in exploration

	Vol. 230 No. 4
ARTHUR BERMAN, CONTRIBUTING EDITOR, bermanae@gmail.com

Haynesville sizzle could fizzle

Despite lower natural gas prices, the Haynesville Shale is the hottest onshore play in North America. Production is more than 150 MMcfd from recently drilled horizontal wells, and single-well Initial Production (IP) rates are as high as 24 MMcfd.

I used standard rate-vs.-time methods to determine estimated ultimately recoverable reserves (EUR) for 14 horizontally drilled wells that had sufficient production history to project a decline rate. Production was extrapolated using a hyperbolic decline, and an economic limit of 1.0 MMcf/month. The wells had an average EUR of 1.5 Bcf, and 67% (10 wells) had reserves less than 1.5 Bcf. This is an early evaluation, and does not include several recently completed wells because of insufficient production data. Reserves were, with one exception (5.3 Bcf), considerably lower than the 6.5 Bcfe most likely per-well reserves, and than the 4.5–8.5 Bcfe range, claimed by the leading operators in the play, Chesapeake and Petrohawk.

Problems with the Haynesville Shale include high decline rates and costs. Average monthly decline for the wells that I analyzed is 20–30%, and projected annual decline rates average 80−90%. Rapid decline makes IP rates unreliable indicators of well productivity. The average production history of wells used in this analysis is less than 5 months; current production rates already average only 48% of IP.

Drilling and completion (D&C) costs are about $7.5 million per well, although Petrohawk recently revised its D&C costs upward to $8.5–9.5 million. Average true vertical depth of wells in this study is 11,500 ft, and average measured depth is 15,250 ft. Five- to ten-stage hydraulic fracturing is typical with 600–750 lb sand per lateral foot in horizontal boreholes, which average 4,500 ft long. Leasing costs in active areas during 2008 were $10,000–30,000/acre, increasing capital expenditures for an 80-acre spacing unit $0.8–2.4 million above D&C costs.

Operating costs average $2.25/Mcf, based on US SEC 10-K filings and annual reports. After gathering and transportation costs, netback gas prices for early March 2009 were less than $2.50/Mcf (RBC Richardson Barr). Net revenue interest, after royalties, is typically 75%, and Louisiana severance tax is $0.27/Mcf (included in operating cost). While current prices are the lowest in many years, and hedging has helped careful operators, it cost many operators $7.25/Mcf or more to produce gas during the fourth quarter of 2008.

Clearly, most Haynesville wells will not approach a commercial threshold until both gas prices and per-well reserves increase. To quantify that threshold, I ran a basic NPV10 model using the cost information above. I used decline rates from the Barnett Shale (65% Year 1, 40% Year 2, 30% Year 3, 25% Year 4, and 20% thereafter) instead of the higher decline rates projected from Haynesville production to date.

The break-even (NPV10 = 0), minimum per-well reserve volume is 2.5 Bcf with a netback gas price of $8/Mcf (~$9/MMBtu Henry Hub spot). This means that the play would have been marginally commercial in 2009 dollars during only 15 months (12.5%) over the past decade—and for an even smaller percentage of the 20 years since the advent of the gas commodity market—if an average well had reserves of 2.5 Bcf instead of only 1.5 Bcf. At 1.5 Bcf/well, $12/Mcf netback gas price is needed to break even.

Chesapeake CEO Aubrey McClendon recently said, “We only need gas prices to be ‘good’ for three to six months out of every two-year period.” (Houston Chronicle, Feb. 11, 2009) If “good” means to break even in the Haynesville Shale, it looks like he will meet costs no more than 12.5% of the time, and lose money the other 87.5%, assuming that per-well reserves can be doubled. That business model is difficult to understand, although successful hedging might change those percentages. But that’s not the entire business model.

“We believe in volatility ... You can sell volatility. Volatility has value,” McClendon continued. “Our company makes additional money when we sell those calls.” What he means is that his company can make money by selling deals to other companies that fear they will be left behind during brief periods of rising prices. For example, in 2008 Chesapeake sold interests in its shale plays to Plains, BP and StatoilHydro, making $10.3 billion.

Why do I reach different conclusions about the Haynesville and other shale plays than some industry analysts? First, they are not industry insiders and, therefore, many do not incorporate true operational costs including interest expense for debt service, or netback gas prices into their evaluations. Second, investment company analysts are marketing a product and make a commission on stock that they sell to clients; their analyses cannot be truly objective. Third, they do little investigative research, and generally accept information on rates, reserves and declines provided by the companies that promote these plays. They cannot have done independent decline analysis on the Haynesville Shale, or they would have recognized the obvious reserve discrepancy (1.5 vs. 6.5 Bcf/well).

I expect shale plays to be part of the natural gas landscape for a while, despite the fact that they are marginally commercial at best. Most companies in these plays have a lot of debt, and the only way to service the debt is to generate cash by drilling wells to produce gas.

The Haynesville play appeared at a time when gas prices were rising. Companies rushed to pay great sums to obtain positions based on the irrational belief that prices would continue to rise. This is the same thinking that brought us the global financial crisis. The magnitude of Capex for leasing and drilling illustrates a profound breakdown of due diligence by the financial and E&P industries.

It is difficult to imagine that the Haynesville Shale can become commercial when per-well reserves are similar to those of the Barnett Shale at more than twice the cost. Maybe the most recently completed wells will tell a different story; otherwise the Haynesville Shale play will likely be replaced by other shale plays that lose less money.

 IHS provided some of the well and production data that was used in this evaluation. Their support of this column is greatly appreciated.

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