Tuesday, April 21, 2009

Haynesville Sizzle or Fizzle: Let’s be fair!

When I read some of the comments posted on this web log to a friend yesterday, he said, “Anything that gets this much flak, must be close to the mark.”

I have received dozens of e-mails and a half-dozen posted comments on this web log about the Haynesville Shale. Many of the e-mail authors strongly disagree with my opinions about the Haynesville, but are respectful and professional. In contrast, the authors of many web log postings who disagree with me are often disdainful, caustic and even vulgar, not only about my opinions but also about my professional qualifications. Some indignantly demand that I disclose the wells (be patient inquisitors—a list of wells follows as Figs. 1 and 2) that I used in my evaluation—I wonder if these same people issue similar demands to the companies that make pronouncements that the Haynesville Shale has 250 Tcf of reserves when there are fewer than 50 wells with any production so far, or that an average well will produce 6.0 Bcf when none have yet produced more than about 3.0 Bcf and most, considerably less.

To be fair from my side, readers have sent me data on Haynesville Shale production that was not available to me when I did my research and published my World Oil column and the previous web posting. That new information modifies my view of the Haynesville play somewhat, and requires an update to my observations and conclusions. Also, there is now a month or two of additional production history since I did the research for that work.

Based on this information, approximately 59% of Haynesville wells may have ultimately recoverable reserves of 0.5-2.0 Bcf (16 wells), while 41% may produce 2.0 Bcf or greater (11 wells), according to my analysis. The mode of 27 wells is 1.5 Bcf and the mean is 2.2 Bcf. These reserve projections are approximations, and are only intended to provide a range of possible outcomes for wells with too little production history to accurately project.

For those reservoir engineers who disparage my qualifications to pick a trend line through data points on a graph (something that apparently is beyond the capability of those with advanced degrees in science unless their degree is in reservoir engineering), I hope that you have never picked a top unless your degree is in geology.

The crucial issue about the Haynesville Shale play, however, is not rates and reserves, but cost. As I explained in “Haynesville Sizzle could fizzle”, threshold economics for the Haynesville Shale require netback gas prices of $8.50/Mcf, and minimum reserves of 2.5 Bcf/well. This is because drilling and completion costs are from $7.5-9.5 million. It is simple algebra once the costs are known.

I have studied the 10-K SEC filings by the major players in the Haynesville play. These are public documents prepared by the operators. With most operating costs between $2.50 and $3.50 per Mcf, rates and reserves simply do not matter at current gas prices of $2.50 netback in the Haynesville. When capital expenditures are added, it costs most operators about $7.50/Mcf to find, develop and operate in the play. While some operators are currently hedged at higher prices, this is a short-term situation, and no one will take the other side of a hedge at more than $7.50/Mcf today or at any time in the foreseeable future.

If you don’t believe me, you should read reports by Credit Suisse, “The True Cost of Shale Gas” (April 2009), and by Bernstein Research, “Why the Haynesville Won’t Work…at $4, $5, or $6/Mcf gas” (April 2009).

I am more optimistic now, based on new information, that the Haynesville Shale may be different from most other shale plays. If operators can substantially reduce cost, and if gas prices improve to levels during the first half of 2008 (average $10/Mcf Henry Hub), some percentage—perhaps 25-50%--of wells in this play may become commercial, but it’s really not about EUR as much as it is cost and gas price.

I have been fair in admitting that new information has modified my view of the Haynesville Shale play. I acknowledge that rates are extremely impressive for several wells, and that some wells have already produced more than 1.0 Bcfg.

For those who disagree with my views on this play, I ask that you be fair too. Look at costs, and not just rates and reserves. If the marginal cost to produce gas is more than $7.50/Mcf (which all operators admit and many state in public presentations–for example, Range Resources’ “IPAA 2009 Oil & Gas Investment Symposium”), then no one is making money on this play today regardless of impressive rates and strong reserves. Unless prices rise above levels they have reached during only 15 months over the past 10 years (or 20 years, for that matter), none of the wells in the Haynesville Shale play is likely to be commercial (Fig. 3).

I am not a gladiator. I don’t perform in my columns and web log waiting for thumbs up or down from readers to validate my methods or conclusions. I put my work in a public forum to share what I observe, and to generate a dialogue that may help us all move closer to the truth. I return every e-mail message that I get, because the people who write them want to engage in the conversation, and deserve my time and respect. For those who prefer to comment anonymously on this web log, I welcome your views also. I encourage you to join the conversation as peers and not as blood-sport spectators looking for entertainment at the Coliseum.























Tuesday, April 14, 2009

Haynesville Sizzle Might 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-versus-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 4.5-8.5 Bcfe range, claimed by leading operators in the play Chesapeake Energy Corporations and Petrohawk Energy Corporation.

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 five 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/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 a $7.25/Mcf or more to produce gas during the fourth quarter of 2008.

Clearly, most Haynesville Shale wells will not approach a commercial threshold until both gas prices and per-well reserves increase. To quantify that reserve and price threshold, I ran a basic NPV10 model using the cost information already mentioned. I used decline rates from the Barnett Shale (65%—Year1, 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 over the past 20 years since the advent of the natural gas commodity market in 1989—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 CE O 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, February 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 McClendon 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. Chesapeake made $10.3 billion on those transactions.

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 awhile, 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 Shale 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 capital expenditure 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.